Geologic CO2 Sequestration 

 Technology and Cost Analysis 
Office of Water (4606-M) 

EPA 816-R10-008 

November 2010 

http://water.epa.gov/drink/ 
i 

Table of Contents

1 INTRODUCTION ..................................................................................................................................................... 1

2 GENERAL COSTING METHODOLOGY, DATA SOURCES, AND COST TRENDS ........................................ 3

COSTING METHODOLOGY ............................................................................................................................................... 3

PRIMARY DATA SOURCES FOR COSTS ............................................................................................................................ 3

COST YEAR BASIS AND TRENDS IN MAJOR COSTS ......................................................................................................... 5

3 TECHNOLOGIES AND COSTS ............................................................................................................................. 9

3.1 SITE CHARACTERIZATION ........................................................................................................................................ 9

Maps and Cross Sections .......................................................................................................................................... 9

Seismic Surveys ......................................................................................................................................................... 9

Seismic (Earthquake) History ................................................................................................................................. 10

Remote Land Survey ................................................................................................................................................ 10

Data on Extent, Thickness, Capacity, Porosity of Receiving Formations ............................................................... 10

Geomechanical Information .................................................................................................................................... 11

Potentially Affected Underground Sources of Drinking Water (USDWs) ............................................................... 11

Geochemical and Other Information on Formations .............................................................................................. 12

Information on Water-Rock Geochemistry .............................................................................................................. 12

List of Penetrations of Injection Zone ..................................................................................................................... 12

List of Penetrations of Containment System ............................................................................................................ 13

List of Water Wells within Area of Review .............................................................................................................. 13

Geologic Characterization Report .......................................................................................................................... 13

Geologic Site Characterization Unit Costs ............................................................................................................. 13

3.2 MONITORING ......................................................................................................................................................... 15

Develop Geochemical Baseline of Formation Water .............................................................................................. 15

Eddy Covariance Air Monitoring ............................................................................................................................ 17

Front-End Engineering and Design- Monitoring Wells .......................................................................................... 18

Rights of Way for Surface Use – Monitoring Wells and Air Monitoring Sites ........................................................ 18

Downhole Safety Valve or Check Valve .................................................................................................................. 18

Standard Monitoring Well Costs ............................................................................................................................. 18

Pressure and Temperature Gauges and Equipment for Monitoring Wells ............................................................. 19

Salinity, CO2 , and Tracer Equipment for Monitoring Wells ................................................................................... 19

Develop Plan and Implement Eddy Covariance Air Monitoring ............................................................................ 20

Develop Plan and Implement Digital Color Infrared Ortho-imagery and Hyper-spectral Imaging ....................... 20

Develop Plan and Implement LIDAR Airborne Survey ........................................................................................... 21

Develop Plan and Implement Soil Zone Monitoring ............................................................................................... 21

Develop Plan and Implement Vadose Zone Monitoring .......................................................................................... 22

Develop Plan and Implement Water Table Monitoring .......................................................................................... 22

Periodic Monitoring of Groundwater Quality and Geochemistry ........................................................................... 22

Surface Microseismic Equipment ............................................................................................................................ 22

Monitoring Well O&M Costs - Above Injection Zone ............................................................................................. 23

Monitoring Well O&M Costs - Into Injection Zone ................................................................................................ 23

U-Tube Sampling O&M – Enhanced Recovery ....................................................................................................... 23

Annual Costs of Air and Soil Surveys – Eddy Covariance ...................................................................................... 23

Annual Costs of Air and Soil Surveys – Digital Color Infrared Orthoimagery or Hyperspectral Imaging ............ 24

Annual Costs of Air and Soil Surveys –LIDAR........................................................................................................ 24

Annual Costs of Air and Soil Surveys –Soil Zone Monitoring ................................................................................. 24

Annual Costs of Air and Soil Surveys –Vadose Zone Monitoring ........................................................................... 24

Annual Costs of Air and Soil Surveys – Samples from Water Table ....................................................................... 24

Annual Cost of Passive Seismic Equipment ............................................................................................................ 24

Periodic Seismic Surveys – 3D ................................................................................................................................ 24
ii 

Complex Modeling of Fluid Flows and Migration .................................................................................................. 25

Reports to Regulators .............................................................................................................................................. 26

Monitoring Unit Costs ............................................................................................................................................. 26

3.3 INJECTION WELL CONSTRUCTION .......................................................................................................................... 29

Front End Engineering and Design ........................................................................................................................ 29

Rights of Way for Surface Uses ............................................................................................................................... 29

Lease Rights for Subsurface Pore Space ................................................................................................................. 29

Land Use, Air Emissions, and Water Permits ......................................................................................................... 29

UIC Permit Filing ................................................................................................................................................... 30

Standard Injection Well Drilling Cost ..................................................................................................................... 30

Well Stimulation ...................................................................................................................................................... 31

Corrosion Resistant Tubing and Casing ................................................................................................................. 31

Cementing of the Injection Well Casing .................................................................................................................. 32

Use of CO2-Resistant Cement .................................................................................................................................. 32

Pumps ...................................................................................................................................................................... 33

Wellhead Control Equipment .................................................................................................................................. 33

Pipeline Costs .......................................................................................................................................................... 34

Injection Well Construction Unit Costs ................................................................................................................... 35

3.4 AREA OF REVIEW AND CORRECTIVE ACTION ........................................................................................................ 37

Simple Fluid Flow Calculations to Predict CO2 Flow ............................................................................................ 37

Complex Modeling of CO2 Fluid Flow .................................................................................................................... 37

Aerial Survey to Find Old Wells .............................................................................................................................. 37

Evaluate Mechanical Integrity of Existing Wells Penetrating Containment System ............................................... 37

Evaluate Integrity of Shallow Wells ........................................................................................................................ 38

Remediate Old Wells in Area of Review .................................................................................................................. 39

Area of Review and Corrective Action Unit Costs .................................................................................................. 39

3.5 WELL OPERATION.................................................................................................................................................. 41

Corrosion Monitoring and Prevention Program ..................................................................................................... 41

Corrosion Monitoring ............................................................................................................................................. 41

Measuring and Monitoring Equipment ................................................................................................................... 41

Equipment to Add Tracers ....................................................................................................................................... 41

Electricity Costs for Pumps and Equipment ............................................................................................................ 42

Injection Well Operating and Maintenance Costs .................................................................................................. 42

Land Use Rents and Right of Way ........................................................................................................................... 43

Pore Space Unit Costs ............................................................................................................................................. 43

Property Taxes and Insurance ................................................................................................................................ 43

Tracers in Injected Fluid ......................................................................................................................................... 43

Repair or Replace Wells and Equipment ................................................................................................................. 43

General Failure of Containment Site – Remove and Relocate CO2 ........................................................................ 43

Well Operation Unit Costs ...................................................................................................................................... 43

3.6 MECHANICAL INTEGRITY TESTS ............................................................................................................................ 45

Internal Mechanical Integrity Tests ........................................................................................................................ 45

Casing Inspection Log ............................................................................................................................................. 45

Radioactive Tracer Survey of Bottom Hole Cement ................................................................................................ 46

External Mechanical Integrity Test ......................................................................................................................... 46

Pressure Falloff Tests .............................................................................................................................................. 46

Mechanical Integrity Test Unit Costs ...................................................................................................................... 46

3.7 WELL PLUGGING, EQUIPMENT REMOVAL, AND POST-INJECTION SITE CARE (PISC) ............................................. 47

Flush Wells with Buffer Fluid before Plugging ....................................................................................................... 47

Plug Injection Wells ................................................................................................................................................ 47

Perform Mechanical Integrity Test Prior to Plugging ............................................................................................ 48

Plug Monitoring Wells ............................................................................................................................................ 48

Remove Surface Equipment, Structures, Restore Vegetation .................................................................................. 48

Document Plugging and Post-Injection Process ..................................................................................................... 48

PISC Monitoring Well O&M ................................................................................................................................... 49

Post-Injection Air and Soil Surveys ......................................................................................................................... 49
iii 

Post- Injection Seismic Surveys ............................................................................................................................... 49

Post- Injection Reports to Regulators ..................................................................................................................... 49

Well Plugging, Equipment Removal, and PISC Unit Costs ..................................................................................... 49

3.8 FINANCIAL RESPONSIBILITY .................................................................................................................................. 51

Performance Bond or Demonstration of Financial Ability to Close Site ................................................................ 51

Performance Bond or Demonstration of Financial Ability for PISC ...................................................................... 51

Financial Responsibility Unit Costs ........................................................................................................................ 51

4 UNCERTAINTIES IN ANALYSIS........................................................................................................................ 52

5 BIBLIOGRAPHY ................................................................................................................................................... 55
iv 

List of Tables

Table 1: Major Sources of GS Cost Information .............................................................................................. 4

Table 2: Geologic Site Characterization Unit Costs ....................................................................................... 14

Table 3: Monitoring Unit Costs ...................................................................................................................... 27

Table 4: Injection Well Construction Unit Costs ............................................................................................ 36

Table 5: Area of Review and Corrective Action Unit Costs ........................................................................... 40

Table 6: Well Operation Unit Costs ................................................................................................................ 44

Table 7: Mechanical Integrity Tests Unit Costs .............................................................................................. 47

Table 8: Well Plugging, Equipment Removal, and PISC Costs ..................................................................... 50

Table 9: Financial Responsibility Unit Costs .................................................................................................. 51

List of Figures

Figure 1: U.S. Carbon Steel Plate Prices ........................................................................................................... 6

Figure 2: Nickel Prices ...................................................................................................................................... 7

Figure 3: Gas Pipeline Costs by Component .................................................................................................... 7

Figure 4: U.S. Drilling Rig Day Rates .............................................................................................................. 8

Figure 5: Diagram of Typical CO2 Injection Wellhead .................................................................................. 34
Technology and Cost Document 

for the final GS Rule 1 November 2010 

1 Introduction 

The Environmental Protection Agency (EPA) has developed new minimum Federal requirements 

under the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO2) for 

the purpose of geologic sequestration (GS). The elements of this rulemaking are based on the 

existing Underground Injection Control (UIC) Program regulatory framework, creating a Class VI 

well classification that addresses the unique nature of CO2 injection for GS. This rule will help to 

ensure consistency in permitting underground injection of CO2 at GS operations across the United 

States. The requirements are designed to prevent endangerment of underground sources of drinking 

water (USDWs) in anticipation of the eventual use of GS to reduce CO2 emissions to the 

atmosphere. 

This Geologic CO2 Sequestration Technology and Cost Analysis document (Technology and Cost 

document) describes the unit costs of specific technologies and operating practices that are 

expected to apply to GS activities. It does not discuss in any detail the development of overall costs 

for the final rule, which is presented in Chapter 5 of the Cost Analysis for the final rule1. As 

described in that chapter, EPA believes that projects will deploy in primarily two types of geologic 

settings during the period of analysis: saline formations and oil and gas reservoirs (enhanced 

recovery (ER) sites).2,3 The costs and risk assessments for these two project types were developed 

under the five different regulatory alternatives considered in the Cost Analysis, including one 

baseline alternative that represents EPA’s understanding of the costs and risks if it were to deploy 

under current UIC regulation (absent a Class VI regulation). Each of the unit costs presented in this 

Technology and Cost document applies to at least one and usually more of the regulatory 

alternatives considered to varying degrees. A cost that is incurred under a given regulatory 

alternative and also under the existing Class I non-hazardous injection well regulations (the 

regulatory baseline for this analysis) is not attributable to the regulatory alternative but are 

presented in the analysis for completeness. 

The SDWA provides EPA with the authority to develop regulations to protect USDWs from 

endangerment; however, it does not provide authority to develop regulations for all areas related to 

GS. This document includes all unit costs associated with GS, not just those specific to preventing 

 

1

 Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide 

Geologic Sequestration Wells (Final GS Rule), EPA 816-R-10-013. The Cost Analysis presents development of the 

final rule costs, taking into account the unit costs presented in the Technology and Cost document, the schedule 

(periodicity) of cost incurrence, the baseline number of projects estimated to deploy, the types of projects (saline and 

ER) anticipated and the geological and engineering parameters associated with them. 2

 EPA understands that the primary purpose of most CO2 injection operations located in depleting oil and gas reservoirs 

will be to enhance recovery of oil and gas until it is no longer economically feasible. Under this scenario, these 

operations would be covered under the existing Class II injection well regulations. An exception is the conversion of an 

operation whose primary purpose changes from enhanced recovery to the long term storage of CO2 in an effort to 

reduce emissions to the atmosphere. In such a case, the new rule would apply. 

3

 There are other possible target formations for GS, including but not limited to coal seams, basalts, salt domes, and 

shales, as described further in the Preamble to the Final GS Rule. The GS rule does not categorically preclude or 

prohibit injection into any type of formation, but expects that the majority of GS projects will involve saline reservoirs 

and converted ER projects. 
Technology and Cost Document 

for the final GS Rule 2 November 2010 

endangerment to USDWs. GS costs are incurred in the pre-injection, or construction and permitting 

phase, throughout the injection phase, and during post-injection site care (PISC). However, GS 

components do not include carbon capture and CO2 transportation to the GS site. The GS 

component is estimated to be approximately 2.7 percent of the total cost of an integrated capture 

and sequestration project, as described in the Preamble to the Final GS Rule. 

The major cost categories included in the Cost Analysis for the final rule are: site characterization, 

well construction and operation, monitoring during operations, area of review and corrective action, 

and financial responsibility. The sections of this document that follow describe the unit costs 

specific to each category. 

EPA applied a unit cost multiplier to existing unit costs (e.g. monitoring) to account for the few 

potential cases where a waiver of the required injection depth would be permitted. These and other 

applicability factors are presented in Appendix B (Project Algorithms) of the Cost Analysis.4

 

4

 Cost Analysis for the Final GS Rule, EPA 816-R-10-008. 
Technology and Cost Document 

for the final GS Rule 3 November 2010 

2 General Costing Methodology, Data Sources, and 

Cost Trends 

Costing Methodology 

This Technology and Cost document evaluates the individual cost components for GS. These are 

termed unit costs and are categorized as follows: 

 Site Characterization 

 Area of Review and Corrective Action 

 Injection Well Construction 

 Mechanical Integrity Tests 

 Monitoring 

 Injection Well Operation 

 Well Plugging and Post-Injection Site Care (PISC) 

 Financial Responsibility 

Unit costs are specified in terms of cost per site, per well, per square mile, or other appropriate 

parameter depending on the characteristics of the cost item. Unit costs are applied to pro forma 

projects presented in the Cost Analysis for this rule.5

 The pro forma descriptions include 

specifications for total surface area, drilling depth, reservoir thickness, well injectivity, number of 

wells through time, and other parameters. 

In the cost analysis, costs are estimated for a baseline regulatory case, assumed to be equivalent to a 

Class I Non-Hazardous Industrial Injection Well, and four proposed regulatory alternatives. Each 

cost item has been evaluated as to whether it is required under each regulatory alternative, and 

whether the cost will apply to all future projects or to a fraction of projects. In many cases, specific 

cost components and technologies will be applied to the GS project regardless of which regulatory 

alternative is chosen. For these cost components, there is no cost difference among the regulations. 

Other cost components may be applicable only under particular regulatory alternatives. Thus, not 

all of the unit costs included in this analysis are attributable to a particular regulatory alternative. 

Primary Data Sources for Costs 

Table 1 summarizes the major data sources for costs in the analysis. A wide range of cost data are 

available from industry survey publications for costs typically incurred in oil and gas drilling and 

production operations. This includes drilling and completion costs by region and depth interval, 

equipment and operating costs, and pipeline costs. Data are available for both the United States. 

and Canada.6,7,8,9 The cost of drilling and equipping wells represents a large component of 

 

5

 Cost Analysis for the Final GS Rule, EPA 816-R-10-008. 

6 Joint Association Survey of Drilling Costs, American Petroleum Institute, Washington, DC. 

http://www.api.org/statistics/accessapi/api-reports.cfm

7 PSAC Well Cost Study – 2009, Petroleum Services Association of Canada, April 30, 2009 and later editions. 
Technology and Cost Document 

for the final GS Rule 4 November 2010 

Table 1: Major Sources of GS Cost Information 

API Joint Association Survey of Drilling Costs Drilling costs in the U.S. for oil, gas, and dry holes 

by depth interval 

EIA Oil and Gas Lease Equipment and Operating 

Cost Survey 

Surface equipment costs, annual operating costs, 

pump costs 

Pipeline Prime Mover and Compressor Costs 

(FERC) 

Pumps 

2009 Petroleum Services of Canada Well Cost Study 

(PSAC) 

Canada drilling costs, plugging costs, logging costs 

Oil and Gas Journal Report on Pipeline Cost Data 

Reported to FERC 

Pipeline costs per inch-mile 

Land Rig Newsletter Onshore day rates/ well cost algorithms 

New Orleans Sequestration Technology Meeting, 

January, 2008 

Monitor station costs in several categories; seismic 

costs 

FutureGen Sequestration Site Materials Monitoring station layout/number of stations 

Preston Pipe Report Casing and tubing costs 

U.S. Bureau of Labor Statistics, American 

Association of Petroleum Geologists, Society of 

Petroleum Engineers 

Hourly labor rates 

Selected presentations and papers (see below) Sensor costs, monitoring costs, number of stations, 

seismic costs 

Benson, "Monitoring Protocols and Life Cycle Costs for Geologic Storage of Carbon Dioxide", Sept., 2004

IEA Greenhouse Gas Programme Report PH4/29, "Overview of Monitoring Requirements for Geologic Storage Projects, Nov., 2004.

Hoversten, "Investigation of Novel Geophysical Techniques for Monitoring CO2 Movement During Sequestration," Oct., 2003.

Dahowski, et al, " The Costs of Applying Carbon Dioxide Capture and Geologic Storage Technologies to Two Hypothetical

Coal to Liquids Production Configurations: A Preliminary Estimation," Pacific NW National Laboratory, September, 2007.

GS costs. The costs of additional equipment or material specifications for CO2 injection wells are 

based in part upon various sources for corrosion resistant materials and specific well components. 

Cost estimates for seismic data acquisition are also available from industry publications and 

presentations. 

Labor rates are obtained from the U.S. Bureau of Labor Statistics and from surveys of oil and gas 

professionals performed by the American Association of Petroleum Geologists (AAPG) and the 

Society of Petroleum Engineers (SPE). Labor rates include a “load factor” from EPA guidance. 

The number of hours estimated for implementation of the various characterization or monitoring 

activities represent EPA’s best professional judgment, informed by and modified in response to 

public comment. 

 

8 Oil and Gas Lease Equipment and Operating Costs, U.S. Energy Information Administration, 2007 and later editions, 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/coststu

dy.html

9 Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September, 2009. 
Technology and Cost Document 

for the final GS Rule 5 November 2010 

Because some GS technologies are still under development, no comprehensive source is available 

that provides detailed summaries of the full range of GS project cost components. Estimates of the 

costs of monitoring equipment, the number of stations required, and the cost of ongoing monitoring 

are based upon analysis of available literature and recent presentations by government and 

academic research groups. Some specific monitoring costs were obtained at an industry meeting 

sponsored by the Groundwater Protection Council.10

Cost Year Basis and Trends in Major Costs 

The costs reported here and used in the cost analysis represent price levels in late 2007, inflated to 

2008 using the Consumer Price Index inflationary factor. Use of the 2007 price level avoids some 

of the extreme cost fluctuations seen in the 2008-2009 period. For the purpose of providing context 

for discussion, recent historical cost trends are presented in the figures below in nominal dollars. 

There have been very steep increases in the cost of materials and labor used in the construction of 

all types of energy infrastructure including power plants, pipelines and oil and gas wells. Figure 1 

shows the recent history of cost per ton of carbon steel plate (used in line pipe, casing, pressure 

vessels, etc.) and Figure 2 shows similar data for nickel (used in corrosion resistant tubing and 

casing and cryogenic applications such as LNG liquefaction plants and LNG storage tanks). Steel 

prices have declined since peaking in 2008, but are higher than in the early 2000s. Figure 3 shows 

the cost of natural gas pipeline construction and Figure 4 shows the average day rate for onshore 

drilling rigs in the US. 

A discussion of uncertainty in cost estimation for this study is presented as Section 5 of this 

Technology and Cost document. 

 

10 Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008. 
Technology and Cost Document 

for the final GS Rule 6 November 2010 

Figure 1: U.S. Carbon Steel Plate Prices 

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2001-01 2002-01 2003-01 2004-01 2005-01 2006-01 2007-01 2008-01 2009-01

Date

US Dollars per Short Ton

Domestic plate A36 (FOB US Midwest mill) from Bloomberg
Technology and Cost Document 

for the final GS Rule 7 November 2010 

Figure 2: Nickel Prices 

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

US Dollars per Short Ton

Figure 3: Gas Pipeline Costs by Component 

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

$70,000

$80,000

$90,000

$100,000

2009

2008

200

2005

2006

2007

4

2003

19

2000

2001

2002

99

1998

19

1995

1996

1997

94

1993

Dollars per Inch-Mile

Misc.

R.O.W.

Labor

Material

Average of large-diameter gas pipelines 30 to 36 inches FERC data compiled by Oil & Gas Journal
Technology and Cost Document 

for the final GS Rule 8 November 2010 

Figure 4: U.S. Drilling Rig Day Rates 

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

$16,000

Q1.99Q2.99Q3.99Q4.99Q1.00Q2.00Q3.00Q4.00Q1.01Q2.01Q3.01Q4.01Q1.02Q2.02Q3.02Q4.02Q1.03Q2.03Q3.03Q4.03Q1.04Q2.04Q3.04Q4.04Q1.05Q2.05Q3.05Q4.05Q1.06Q2.06Q3.06Q4.06Q1.07Q2.07Q3.07Q4.07Q1.08Q2.08Q3.08Q4.08Q1.09Q2.09Q3.09Q4.09Q1.10

Quarter

Dollars per Day
Technology and Cost Document 

for the final GS Rule 9 November 2010 

3 Technologies and Costs 

3.1 Site Characterization 

Site characterization is a fundamental component of the UIC program. Owners or operators must 

identify the presence of suitable geologic characteristics at a site to ensure the protection of 

USDWs from endangerment associated with injection activities. To accomplish this, site 

characterization includes an assessment of the geologic, hydrogeologic, geochemical, and 

geomechanical properties of the proposed GS site. Characterization is designed to provide the 

geologic and hydrologic data and needed to design the infrastructure, develop computational 

models, determine appropriate operation parameters, and design the monitoring program. In this 

phase of site development, a determination is made of whether the formation has adequate porosity, 

permeability, and continuity for long term injection. An assessment is also made about the ability 

of overlying units to restrict upward movement of the injected CO2 and prevent the endangerment 

of USDWs. This includes evaluation for the presence of non-sealing faults or other potential 

pathways for migration. Other types of evaluation include geomechanical data on the mechanical 

properties of the reservoir, information on the occurrence and characteristics of USDWs, and 

information on past drilling into the proposed injection zone and overlying formation. 

Maps and Cross Sections 

The basic element of geologic analysis and characterization is the development of regional and sitespecific geologic maps and cross sections to provide an understanding of stratigraphy and structure. 

The primary source of information for this analysis is well log data, which allows the geologist to 

map the depth to various formation tops, thickness variations (i.e., with isopach maps), and 

lithologies (e.g., sandstone, shale, or carbonates). Where available, seismic or other geophysical 

and engineering data are also used to aid the development of the subsurface interpretation. 

Seismic Surveys 

Seismic data acquisition and interpretation is an important aspect of site characterization. Seismic 

data will be acquired either on the surface, or in a well. Borehole techniques require one or more 

wells for sources and receivers. Surface seismic data can be either two-dimensional (2-D) or threedimensional (3-D), with the latter providing a higher degree of resolution but being much more data 

intensive and costly to obtain and interpret. Seismic data may also be used for monitoring during 

operations and PISC.11

 

3-D seismic techniques use man-made source signals and a receiver array to image the subsurface. 

In the site characterization phase, 3-D seismic surveys may be used to evaluate the detailed 

 

11 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006. 
Technology and Cost Document 

for the final GS Rule 10 November 2010 

structural geology and stratigraphy of the site. 3-D seismic data may also be used in the site 

characterization phase to inform computational models to estimate the volume of CO2 that can be 

stored at a potential site.12 The technology is mature and has been used in the oil and gas 

exploration and development for decades. 

The cost of 3-D seismic acquisition varies widely, ranging from $40,000 to $160,000 per square 

mile.13 14 15 Factors other than area affecting cost include acquisition parameters, terrain, geology, 

reservoir depth, and remoteness of location. A recent large seismic survey by a major operator in 

Louisiana averaged $85,000 per square mile.16 A Canadian study indicated a range in cost of 

$21,000 to $104,000 per square mile.17 A cost of $100,000 per square mile has been cited in 

industry articles as an average for the United States onshore. 

Seismic (Earthquake) History 

The natural long-term seismic history of a potential GS site must be evaluated to gain a picture of 

potential failure risks, including the inherent potential for a seismic event and for induced 

seismicity. Historic data on seismic activity can be obtained from the U.S. Geological Survey. 

Evaluation will include the frequency and intensity of historic activity and its relationship to known 

geology. The presence of regional faults and the activity on those faults is of significance in 

assessing site suitability. 

Remote Land Survey 

An airborne survey of the potential site may be carried out to locate and identify dwellings and 

other manmade structures affected within the area of review. The AoR is defined in the final rule as 

“the region surrounding the geologic sequestration 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 CO2 stream and is based on available 

site characterization, monitoring, and operational data as set forth in §146.84” of the rule. 

Data on Extent, Thickness, Capacity, Porosity of Receiving Formations 

Perhaps the most fundamental aspect of site characterization is the determination of the receiving 

and storage properties of the proposed injection zone interval. In order to develop the analysis, it is 

necessary to obtain regional well log, well history, pressure test, and other subsurface data. 

 

12 Doughty, Christine, Barry Freifeld, and Robert Trautz, 2007, “Site Characterization for CO2 Geologic Storage,” 

Environmental Geology, vol. 54, no. 8, June 2008. 13 McFarland, John, 2009, “How Do Seismic Surveys Work?” http://www.oilandgaslawyerblog.com/2009/04/how-doseismic-surveys-work.html 14 Dix, Manfred and Greg Albrecht, 2008, “An Economic Impact Analysis of the Haynesville Shale Natural Gas 

Exploration, Drilling, and Production,” Louisiana Department of Natural Resources report, August, 2008 

http://dnr.louisiana.gov/haynesvilleshale/manfred-dix-impact-analysis.pdf

15 Percival, Pamela, 2008, “Chesapeake Exec Discusses 3D Seismic in Major Shale Plays,” Basin Oil and Gas 

Magazine, May 2010. 16 Hill, Kevin. B., 2010?, “A Seismic Oil and Gas Primer,” Hill Geophysical Consulting, Shreveport, LA. 

http://www.loga.la/flash/HS/kevinhillLSUS.pdf

17 Cooper, N.M, 2010, “The Value of 3D Seismic in Today’s Exploration Environment – In Canada and Around the 

World,” Mustagh Resources, Calgary, Alberta. www.mustagh.com/abstract/opi_3D.doc
Technology and Cost Document 

for the final GS Rule 11 November 2010 

Included is the acquisition of core data, drill stem test data, production test data, and other 

engineering data on wells in the AoR. The geologist uses this information to map the thickness, 

structure, and injection zone characteristics in the subsurface. The goal is to fully evaluate storage 

capacity and injectivity, and the expected variability in these parameters. Some sites, such as 

depleting oil or gas fields, will have a large amount of existing subsurface data in a specific area. In 

saline formations, the amount of subsurface data may be limited or more regional in distribution. 

Geomechanical Information 

The mechanical properties of a potential storage reservoir play an important role in its ability to 

withstand injection pressures. If not designed properly, CO2 injection could lead to deformation of 

the injection zone or confining rock, resulting in fracturing and potential leakage that may endanger 

USDWs. 18 19 The maximum injection pressure for CO2 must be less than the formation fracture 

pressure at the depth of injection. If the injection pressure exceeds the fracture pressure, failure and 

leakage can occur. 

Geomechanical information on in-situ stress state, rock strength, and in-situ fluid pressures may be 

obtained from existing databases and literature as well as from new cores and tests. Sources of 

geomechanical data include well logs, seismic, pressure fall-off tests, and direct physical 

measurements of rock strength in the laboratory. Data parameters include pore pressure, 

overburden stress, horizontal stress and orientation, elastic strength, and expected failure 

mechanisms. 

Potentially Affected Underground Sources of Drinking Water (USDWs) 

A major consideration in site selection and design is the protection of USDWs. As part of the site 

permitting process, the operator must determine the distribution and depth of all potentially affected 

USDWs. 

EPA defines USDWs as follows: 

 

An aquifer or portion of an aquifer that supplies any public water system or that contains a 

sufficient quantity of ground water to supply a public water system, and currently supplies 

drinking water for human consumption, or that contains fewer than 10,000 mg/l total 

dissolved solids and is not an exempted aquifer.20

This cost element is based upon the cost of researching information on the distribution of USDWs 

in the vicinity of the GS site. Such information can be found in the literature or in public well logs. 

 

18 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the 

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer 

(eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp. 

19 Measuring and Modeling for Site Characterization: A Global Approach, D. Vu-Hoang, L. Jammes, O. Faivre, and 

T.S. Ramakrishnan, Schlumberger Carbon Services, March, 2006. 

20 US EPA website, Office of Water, Underground Injection Control: 

http://www.epa.gov/safewater/uic/glossary.html#t. 
Technology and Cost Document 

for the final GS Rule 12 November 2010 

Geochemical and Other Information on Formations 

In addition to determining the distribution of USDWs at the proposed site, owners and operators 

must obtain data on the geochemical water properties of regional formations, as well as an overall 

understanding of their regional thickness and structure. Information on formation water in the 

potential injection zone may be obtained from nearby well logs or from water samples from nearby 

wells. This cost element is based upon the time required to research and evaluate this information 

from public data sources in unit cost A-6 and from new cores and tests in unit cost A-7 in Table 2 

below. 

Information on Water-Rock Geochemistry 

The geochemistry of subsurface fluids can affect whether a site is suitable for GS. Injection of CO2

can result in the presence of carbonic acid, which can react with injection zone rock to liberate 

heavy metals. Another consideration is whether certain minerals may be precipitated that would 

plug the pore space, reducing permeability and reducing the ability to inject CO2. Therefore, 

another requirement during site characterization is the analysis of the chemical characteristics of 

the formation water and the potential reactivity of the injection zone rock with CO2. Information on 

formation water characteristics may be obtained from nearby well logs or from water samples from 

nearby wells. Information on injection zone mineralogy may be obtained from whole or sidewall 

cores, well cuttings or well logs in nearby wells. Analysis will likely include petrographic studies 

of thin sections of injection zone rock to determine mineralogy. EPA expects that laboratory tests 

will be conducted to evaluate chemical reactivity to carbonic acid under injection zone conditions. 

List of Penetrations of Injection Zone 

The location and evaluation of existing penetrations into the injection zone within the area of 

review is a key component of site characterization. Some older wells may have either been 

constructed using substandard methods or their condition may have deteriorated significantly 

through time. Any well penetrating the potential storage reservoir may provide a leakage pathway 

into overlying strata. Therefore, all well penetrations must be located and the condition of the wells 

and casing cement evaluated. It may be possible to correct issues with problematic existing wells. 

In some cases, the presence of such wells can make the use of a particular site for GS economically 

infeasible or pose undue risk of endangerment to USDWs. 

Existing commercial oil and gas well history databases contain information on the location, depth, 

and other characteristics of most historic wells. Because some wells may not be in the database, an 

operator could also carry out a physical survey using airborne or ground-based magnetic methods 

to locate abandoned wells. Such costs are included in item D-4 (AoR review). The cost of locating 

and evaluating existing penetrations into the injection zone is expected to vary widely based on the 

quality and coverage of available well data, the assumption in the current analysis is that well 

database coverage is good and that magnetic tests are not needed in the site characterization phase. 

Costs are based on EPA’s best professional judgment regarding the number of hours needed to 

conduct the research and evaluate the findings. 
Technology and Cost Document 

for the final GS Rule 13 November 2010 

List of Penetrations of Containment System 

It is also important to determine the location, depth, and characteristics of wells that have 

penetrated the containment system within the area of review, but reached total depth before 

penetrating the storage injection zone because these wells could also represent potential leakage 

pathways. As with the previous item, the source of information is primarily commercially available 

well history databases. EPA expects that the coverage in well history databases is good and that 

magnetic tests will generally not be needed. 

List of Water Wells within Area of Review 

Determination of the location and depth of existing water wells is an aspect of site characterization. 

Information may be obtained from databases of well locations or by site inspection. Site inspections 

would include activities such as land surveys and seismic surveys. 

Geologic Characterization Report 

Approval of a specific site for GS involves a thorough understanding of all of the geological 

characteristics, including the suitability of the receiving zone, storage capacity and injectivity, and 

that there is a competent confining system. The report must incorporate aspects of the site 

characterization studies, including geologic, geochemical, geomechanical, hydrological, and 

geophysical studies. It summarizes the results of any pre-injection modeling studies to evaluate the 

size and location of the expected CO2 plume through time. 

Geologic Site Characterization Unit Costs 

Table 2 specifies the estimated costs and data sources for site characterization. 
Technology and Cost Document 

for the final GS Rule 14 November 2010 

Table 2: Geologic Site Characterization Unit Costs 

Tracking 

Number Cost Item Cost Algorithm Data Sources

A-1 Develop maps and cross sections of local geologic structure 60 hours of geologists @$107.23/hr = 

$6,434 per site

AAPG 2009 salary survey of petroleum 

geologists

A-2 Conduct 3D seismic survey to identify faults and fractures in 

primary and secondary containment units

$104,000/square mile for good 

resolution

Several published reports are in range of 

this cost. Cost depends on resolution 

(number of lines shot) of survey.

A-3 Obtain and analyze seismic (earthquake) history. 60 hours of geologists @$107.23/hr = 

$6,434 per site

AAPG 2009 salary survey of petroleum 

geologists

A-4

Remote (aerial) survey of land, land uses, structures etc.. 

Should assume survey is twice the project's actual CO2 

footprint due to uncertainty during site characterization phase 

of exact location of facilities and plume.

$3,100/site + $415/square mile 

surveyed. (Should assume survey is 

twice project's actual footprint.)

Advertised cost of an aerial survey 

company for high-resolution (1/2 meter).

A-5 Obtain data on areal extent, thickness, capacity, porosity and 

permeability of receiving formations and confining systems

24 hours of geologists @$107.23/hr = 

$2,574 per site

AAPG 2009 salary survey of petroleum 

geologists

A-6

Obtain geomechanical information on fractures, stress, rock 

strength, in situ fluid pressures (from existing data and 

literature)

120 hours of geologists @$107.23/hr = 

$12,868 per site

AAPG 2009 salary survey of petroleum 

geologists

A-7 Obtain geomechanical information on fractures, stress, rock 

strength, in situ fluid pressures (new cores and tests)

$78/foot for stratigraphic test well + 

$3,100/core

Drilling cost is estimated from drilling cost 

equations developed from JAS and PSAC 

data. Core analysis cost is best professional 

judgement.

A-8 List names and depth of all potentially affected USDWs 24 hours of geologists @$107.23/hr = 

$2,574 per site

AAPG 2009 salary survey of petroleum 

geologists

A-9 Provide geochemical information and maps/cross section on 

subsurface aquifers.

60 hours of geologists @$107.23/hr = 

$6,434 per site

AAPG 2009 salary survey of petroleum 

geologists

A-10 Provide information on water-rock-CO2 geochemistry and 

mineral reactions.

240 hours of geologists @$107.23/hr 

+$10,300 lab fees = $36,035 per site

Best professional judgement of time 

required and lab fee.

A-11 Develop list of penetrations into injection zone within AoR 

(from well history data bases)

12 hours @$107.23/hr = $1,287 per 

square mile

Best professional judgement of time 

required. Hourly rate derived from AAPG 

2009 salary survey of petroleum geologists. 

Cost expected to vary widely based on well 

ages and quality of record keeping.

A-12 Develop list of penetrations into containment systems within 

AoR (from well history data bases)

12 hours @$107.23/hr = $1,287 per 

square mile

Best professional judgement of time 

required. Hourly rate derived from AAPG 

2009 salary survey of petroleum geologists. 

Cost expected to vary widely based on well 

ages and quality of record keeping.

A-13 Develop list of water wells within AoR (from public data) 36 hours @$107.23/hr = $3,860 per 

square mile

Best professional judgement of time 

required. Hourly rate derived from AAPG 

2009 salary survey of petroleum geologists. 

Cost expected to vary widely based on well 

ages and quality of record keeping.

A-14

Prepare geologic characterization report demonstrating: 

suitability of receiving zone, storage capacity and injectivity, 

trapping mechanism free of nonsealing faults, competent 

confining system, etc.

240 hours of geologists @$107.23/hr = 

$25,735 per site

Best professional judgement of time 

required. Hourly rate derived from AAPG 

2009 salary survey of petroleum geologists.

A-15 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 15 November 2010 

3.2 Monitoring

Once injection begins, a program for monitoring of conditions in the injection zone and CO2

distribution is required.21 This is needed in order to: 

 Manage the injection process 

 Delineate and identify leakage risk or actual leakage that may endanger USDWs 

 Verify and provide input into computational models 

 Provide early warnings of failure 

Per the GS rule, monitoring components must, at a minimum, include the following: 

 Analysis of the carbon dioxide stream 

 Installation and use of continuous recording devices to monitor injection pressure, 

rate, and volume; the pressure on the annulus between the tubing and the long string 

casing; and the annulus fluid volume added 

 Corrosion monitoring 

 Monitoring of ground water quality and geochemical changes above the confining 

zone(s) 

 A demonstration of mechanical integrity 

 A pressure fall-off test 

 Testing and monitoring to track the extent of the carbon dioxide plume and the 

presence or absence of elevated pressure 

 Any additional monitoring required by the UIC Director 

The GS rule provides more detailed and specific monitoring requirements. Monitoring of the wells, 

deep subsurface, shallow subsurface and ground surface is expected to continue for long periods 

after the injection is terminated for safety and to confirm predictions of storage behavior. 

As mentioned in the Introduction to this Technology and Cost document, to cost the potential few 

cases where a waiver of the required injection depth would be permitted, EPA applied a unit cost 

multiplier to existing unit costs to account for the additional requirements, in particular for 

monitoring. These and other applicability factors are presented in Appendix B (Project Algorithms) 

of the Cost Analysis.22 

Develop Geochemical Baseline of Formation Water 

Prior to injection of CO2, owners and operators must develop a baseline of geochemical properties 

and characteristics of water in the injection zones, confining zones, and USDWs. During injection 

or in the post-injection monitoring phase, regular sampling continues. In this way, changes in 

geochemistry through time can be interpreted, allowing analysis of plume movement or leakage. 

Geochemical analysis of water samples includes the quantification of gases (methane, ethane, CO2, 

 

21 The Future of Coal, Options for a Carbon-constrained World, An Interdisciplinary MIT Study, 

Massachusetts Institute of Technology, 2007. 

22 Cost Analysis for the Final GS Rule, EPA 816-R-10-013. 
Technology and Cost Document 

for the final GS Rule 16 November 2010 

N2), carbonate, and total alkalinity, metals (Na, K, Ca), salinity (total dissolved solids, or TDS), and 

stable isotopes (C, O).23 24 

Downhole fluid samples can be collected for surface analysis using wireline formation testers and 

U-Tube sampling devices. The Schlumberger Modular Formation Dynamics Tester (MDT) is a 

wireline tool that is used to collect multiple subsurface samples at formation pressure and 

temperature (PVT samples) for surface analysis.25 U-Tube technology was developed for the DOE 

Frio Brine project and allows sample extraction at injection zone pressure and temperature.26 As its 

name implies, it is a U-shaped tube device inserted in the well. A valve is opened to collect samples 

from the interval of interest at pressure and transport them to the surface for analysis. 

It is necessary to establish a baseline of existing groundwater properties. After injection begins, 

periodic testing of groundwater can detect leakage. In many areas, local and regional groundwater 

wells will be present and are a source of data on chemical properties. New wells may also be 

needed for sampling. Geochemical analysis of water samples for parameters such as resistivity and 

pH are routine. For groundwater samples, Schlumberger has developed the Westbay sampling 

system. This is a sampling assembly that is lowered into a groundwater well of generally less than 

3,300 feet in depth. Discrete samples can be taken from multiple intervals. The hardware can be left 

in place for subsequent testing. In sampling for CO2 concentrations, care must be taken to account 

for rapid degassing of CO2 from the water. Misleadingly low values can be obtained unless 

precautions are taken.27 

In depleted/depleting oil and gas formations, there may is a need to monitor for petroleum escaping 

from an oil field structure that is being filled with CO2. This could occur as injected CO2 forces oily 

fluids down below the lowermost “spill-point” of an ER site or a CO2 flood project that is 

converted to GS. Petroleum leaks could be detected by bringing up water samples using a U-tube or 

other sampling system. A third option is a fiber optic device which can monitor downhole 

concentrations of hydrocarbons in aquifers. The near-infra-red light source (1.0-1.7 micrometers) 

and matching optical sensor are kept at the surface, linked by a fiber optic cable bundle to the IR 

absorption path deep in the well. APS Technology, Inc. has developed such a system under the 

name PetroMax system.28 The PetroMax system has completed all laboratory tests and a field 

prototype has been designed. The PetroMax system provides real-time monitoring of downhole 

fluid composition and provides continuous oil, water and gas concentrations from multiple 

downhole locations. The PetroMax system distinguishes among chemicals passing the downhole 

 

23 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006. 24 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide, S. Benson and L. Myer, 

Lawrence Berkeley Laboratory, Berkeley, California, 2002. 25 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006. 26 The U-Tube – Novel System for Sampling and Analyzing Mulit-Phase Borehole Fluid Samples, by Barry M. Freifeld, 

et al, Lawrence Berkeley National Laboratory, Berkeley, CA. (publication date unknown). 27 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2, Report No. COAL R285 

DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Bentham, S. Holloway, and G. Kirby, British Geological 

Survey, Coordinator of the European Network of Excellence on Underground CO2 Storage (CO2GeoNet), Keyworth, 

Nottingham, UK, March 2005. 

28 Bill Turner, APS Technology, “Downhole Fluid Analyzer Development, Phase I Final Report,” DOE Award DEAC26-98FT40481, U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA, March, 2004. 

See also: http://www.aps-tech.com/other/petromax.htm; and PetroMax brochure: http://www.aps-tech.com/tds/APSPetroMax.pdf. 
Technology and Cost Document 

for the final GS Rule 17 November 2010 

sensor by directly measuring the composition of the downhole fluid. The light that is not absorbed 

in the sample volume returns to the surface and is analyzed and presented in real time. 

Standard sampling and analysis is done by personnel at the well site supplemented as needed with 

analyses at commercial labs. There is the possibility of continuous automated monitoring of 

geochemical data using downhole sensors. Although downhole pH and optical sensors for wells 

exist, additional R&D and commercial operations are needed in this area. Thus, geochemical data 

acquisition may rely partially upon surface testing of water samples. 

Eddy Covariance Air Monitoring 

Direct measurement and testing of CO2 concentrations above a GS site can be made in the air or 

vadose zone (the vadose zone is the unsaturated zone between the ground surface and the water 

table). This type of monitoring may be required at the discretion of the UIC Director. If this type of 

monitoring is to be part of the monitoring program, it will be necessary to develop a baseline of 

ambient conditions as part of the site characterization. Establishment of a representative baseline of 

the concentration of CO2 in the air or soil may be somewhat problematic in many instances, due to 

the potential for a relatively large amount of natural variability. The background variability may be 

high relative to what is of interest for site monitoring. 

Basic technologies include eddy covariance, light detection and ranging (LIDAR), soil gas 

sampling with ground-surface accumulation chambers, and direct vadose zone sampling using 

subsurface probes. 

The eddy covariance technique is used to measure CO2 concentration in the air above a GS site. It 

combines an open path infra-red gas analyzer on a tower alongside a sensitive anemometer that 

measures wind speed and direction. The size and shape of the sampling footprint is derived 

mathematically from the anemometer data.29,30 A typical station consists of sensors mounted on a 

tower from 10 to 30 feet high. The stations can be operated with solar power and can be set up for 

data telemetry for transmission to a central facility. Deployment of a grid of such detectors over a 

GS site provides information regardless of wind direction. 

Capital costs for eddy covariance monitoring are based upon cost per station and specifications of 

number of monitoring stations. Annual costs are estimated separately. 

 

29 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2, Report No. COAL R285 

DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Bentham, S. Holloway, and G. Kirby, British Geological 

Survey, Coordinator of the European Network of Excellence on Underground CO2 Storage (CO2GeoNet), Keyworth, 

Nottingham, UK, March 2005. 

30 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide, S. Benson and L. Myer, 

Lawrence Berkeley Laboratory, Berkeley, California, 2002.
Technology and Cost Document 

for the final GS Rule 18 November 2010 

Front-End Engineering and Design- Monitoring Wells 

This encompasses front-end engineering and design of the monitoring wells only. The monitoring 

wells may be completed above the injection zone or into the injection zone. These items have 

separate costs in the model. 

Rights of Way for Surface Use – Monitoring Wells and Air Monitoring Sites 

Owners or operators must obtain rights-of-way for surface use to set up and operate monitoring 

facilities. In the cost model for this analysis, the costs for right-of-way are estimated separately for 

monitoring wells above the injection zone, monitoring wells into the injection zone, and for air 

monitoring sites. 

Downhole Safety Valve or Check Valve 

Injection wells must be equipped with alarms and automatic downhole shutoff systems (or, at the 

discretion of the UIC Director, other mechanical devices that provide equivalent protection). 

Downhole safety valves will be installed to automatically shut in the well if surface equipment fails 

so that no surface release occurs and backflow into surface facilities is prevented. 

Costs for this item are input as a base cost and an incremental cost as a function of installation 

depth. 

Standard Monitoring Well Costs 

To ensure the protection of USDWs, multiple monitoring wells will be required to monitor the 

movement of CO2 in the subsurface. Various types of sensor technologies and fluid sampling 

methods can be used to provide such information. A 2006 FutureGen report listed the various 

categories of monitoring wells:31

 Injection Zone Monitoring Wells – monitoring wells that are perforated across the injection 

zone. 

 Above the Confining Zone Monitoring Wells – monitoring wells that are perforated just 

above the primary seal. They are used for fluid sampling and in situ pressure and 

temperature. 

 Drinking Water Monitoring Wells – wells that are completed in the deepest drinking water 

interval and are monitored with fluid sampling to detect CO2 or salinity. 

 Microseismic Wells – wells extending to the top of the primary seal and are used for 

microseismic monitoring. 

With injection zone monitoring wells there is a tradeoff between improved ability to monitor the 

injection zone and a potential increase in leakage risk. Monitoring wells completed in intervals 

above the injection zone do not carry this risk. In the current cost study, it is assumed that 

monitoring wells are completed just above the primary seal. 

 

31 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006. 
Technology and Cost Document 

for the final GS Rule 19 November 2010 

The drilling and completion of CO2 monitoring wells represents a large component of overall 

monitoring costs. For example, a 5,000 foot well with an average cost per foot of $180 will cost 

$900,000. The overall cost is a function of depth and well design and characteristics. 

In the Cost Analysis32 for this rule, monitoring well costs are determined for wells completed either 

above the injection zone or into the injection zone. 

Pressure and Temperature Gauges and Equipment for Monitoring Wells 

Monitoring wells may have permanently installed downhole equipment to continuously measure 

pressure and temperature in the injection and containment zone. Measurements of subsurface 

pressure are routine in oil and gas field operations. 33 A wide variety of pressure sensors are 

available, including piezo-electric transducers, strain gauges, diaphragm gauges, capacitance 

gauges, and the newer fiber optic pressure and temperature sensors are available. Fiber optic cables 

from the surface to the formation can provide real-time formation pressure measurements. 

These items in the cost model are for the capital costs of such equipment. The annual operating 

costs for monitoring wells are input separately. 

Salinity, CO2 , and Tracer Equipment for Monitoring Wells 

Salinity and fluid characteristics may be measured downhole in a monitoring well to help determine 

composition of fluids and to monitor CO2 movement. Samples can also be analyzed for injected 

chemical tracers. At the discretion of the UIC Director, owners and operators may be required to 

add tracers to the injected CO2 and conduct subsequent monitoring with monitoring wells to detect 

the tracers, indicating CO2 leakage. 

Samples can be collected directly from the formation using a U-tube downhole sampler, which was 

developed by the Lawrence Berkeley National Laboratory (LBNL). Once collected and brought to 

the surface, the samples can be analyzed for major ions, pH, alkalinity, stable isotopes of carbon, 

oxygen, and hydrogen, and gases such as hydrocarbon vapors, CO2, and its associated isotopes.34 

At the Texas Frio Brine Pilot Tests, a U-tube downhole sampler was used to collect high-frequency 

samples at the monitoring well.35 A U-shaped tube was equipped with a series of one-way check 

valves at the cusp of the U bend in the tube and was inserted to the sampling depth. The pressure in 

the U-tube was decreased below formation pressure to allow sample fluids to enter the tube through 

the check valves. The U-tube pressure was then increased using compressed nitrogen gas, and the 

sample was rapidly transported to the surface for analysis. 

 

32 Cost Analysis for the Final GS Rule, EPA 816-R-10-013. 

33 Overview of Monitoring Techniques and Protocols for Geological Storage Projects, S. M. Benson, E. Gasperikova, 

and G. M. Hoversten, IEA Greenhouse Gas R&D Program report, Report Number PH4/29, November 2004. 

34 Overview of Monitoring Techniques and Protocols for Geological Storage Projects, S. M. Benson, E. Gasperikova, 

and G. M. Hoversten, IEA Greenhouse Gas R&D Program report, Report Number PH4/29, November 2004. 

35 Monitoring Geologically Sequestered CO2 during the Frio Brine Pilot Test using Perfluorocarbon Tracers, by S. D. 

McCallum, D. E. Reistenberg, D. R. Cole, B. M. Freifeld, R. C. Trautz, S. D. Hovorka, and T. J. Phelps, Conference 

Proceedings, Fourth Annual Conference on Carbon Capture and Sequestration, DOE/NETL, May 2-5, 2005. 
Technology and Cost Document 

for the final GS Rule 20 November 2010 

There are three components in this category for equipment costs only: 

 Monitoring equipment for wells above the injection zone 

 Monitoring equipment for wells into the injection zone 

 U-tube monitoring equipment for sensing oil movement away from the bottom of the 

formation (Enhanced Recovery only) 

Develop Plan and Implement Eddy Covariance Air Monitoring 

Eddy covariance is an established technology for potentially monitoring the CO2 concentration in 

the air above a GS site. It combines an open path infra-red gas analyzer (IRGA) on a tower 

alongside a sensitive, high-speed, three-dimensional anemometer, a device used for measuring 

instantaneous wind speed and direction. Time series data are recorded and evaluated using 

computer methods. Eddy covariance systems are research tools that are assembled from a variety of 

commercially available components. The size and shape of the sampling footprint (the surface area 

that is sampled by the instrument) is derived mathematically from the anemometer data. A typical 

station consists of sensors mounted on a tower from several meters to 30 meters or more high. 

The stations can be operated with solar power and can be set up for data telemetry for transmission 

to a central facility. Deployment of a grid of such detectors over an area provides information 

regardless of wind direction. CO2 concentration data are integrated with meteorological data 

including wind speed and direction, relative humidity, and temperature. Such methods have the 

ability to measure CO2 concentration in the atmosphere over relatively large areas. 

This cost component incorporates the expenditures for planning and equipment costs for air 

monitoring using Eddy Covariance technology. Annual operating costs are included as a separate 

data item. 

Costs are broken out into a planning component and a capital expenditure component. 

Develop Plan and Implement Digital Color Infrared Ortho-imagery and Hyper-spectral Imaging 

Digital color ortho-imagery and hyper-spectral imaging are airborne remote sensing technologies 

used to detect changes in vegetation resulting from CO2 leakage. Hyper-spectral sensors are used to 

image changes in the electromagnetic spectrum from vegetation. The object is to detect a specific 

spectral signature that is known to result from CO2 uptake. The advantage of these methods is that 

they can efficiently cover a large surface area. 

This cost component incorporates the expenditures for planning and quality assurance. Annual 

operating costs are included as a subsequent data item. 
Technology and Cost Document 

for the final GS Rule 21 November 2010 

Develop Plan and Implement LIDAR Airborne Survey 

LIDAR is an optical remote sensing technology that can be used to detect CO2 concentration in the 

air above a GS site.36 Another technology for measurement of CO2 in air is Raman LIDAR. LIDAR 

is the optical analog of radar, and it is based upon the use of laser radiation to measure various 

compounds in the air, including CO2. The Raman LIDAR method involves transmitting laser light 

into the atmosphere and then detecting the scattered laser radiation that has been shifted in 

wavelength due to interaction with the target scattering molecules (e.g., CO2) along the resolved 

path length. By comparing the Raman signal of the CO2 to the Raman signal of N2 or O2, a direct 

measurement of CO2 concentration can be obtained. 

A similar method, Differential Absorption LIDAR (DIAL), uses two wavelengths of laser light to 

measure the CO2 concentration in the atmosphere. The wavelengths used are specific to CO2. One 

wavelength is selected to correspond to a CO2 spectral absorption line, while the other is a nonabsorbing wavelength. The average CO2 concentration over the path length can be determined from 

the ratio of the backscatter signals for the two laser wavelengths. The instrumentation for both 

methods (Raman LIDAR and DIAL) can be truck or airplane mounted and can provide similar 

precision at similar cost. Truck methods can cover up to tens of square kilometers per day. Plane 

mounted platforms can cover a much larger area. 

Airborne DIAL methods are currently in use for methane leakage detection along gas pipelines. 

Instrumentation includes the LIDAR, a digital mapping camera, a color video system, and an 

optical guidance system. The airplane flies a survey over the pipeline at an altitude of about 1,000 

feet, approximately perpendicular to the wind direction. The LIDAR instrumentation measures the 

concentration of methane by measuring how much of the reflected laser pulse has been absorbed. 

These data are integrated with real time wind direction and velocity to define the leakage footprint 

and estimate a leakage rate. 

This cost component incorporates the expenditures for planning and quality assurance. Annual 

operating costs are included as a subsequent data item. 

Develop Plan and Implement Soil Zone Monitoring 

The soil zone is generally present within the first few inches to possibly tens of feet beneath the 

Earth’s surface. A monitoring program to detect the vertical CO2 flux in the soil zone can be 

established. Background levels (which vary with time of day and season) must be determined to 

provide a baseline against which statistically significant anomalies can be detected. This may 

consist of a grid of accumulation chambers in which the CO2 flux is periodically measured.37 

Commercially available accumulation chamber instrument packages are used to evaluate seasonal 

variations in CO2 flux. The accumulation chamber is a method of measuring soil CO2 flux that 

 

36 U.S. Department of Energy NETL http://www.netl.doe.gov/publications/factsheets/project/Project642.pdf. 37 Oldenberg, C.M., Jennifer L. Lewicki, and Robert P. Hepple, 2003, “Near-Surface Monitoring Strategies for Carbon 

Dioxide Storage Verification,” Earth Sciences Division, Lawrence Berkeley National Laboratory, publication LBNL54089. 
Technology and Cost Document 

for the final GS Rule 22 November 2010 

involves the placement of a collection chamber directly on or into the soil surface, with the rate of 

CO2 accumulation measured periodically with an IRGA. 

This cost component incorporates the expenditures for planning and equipment installation. Annual 

operating costs are included as a subsequent data item. 

Develop Plan and Implement Vadose Zone Monitoring 

The vadose zone is the relatively shallow zone beneath the surface that is not saturated with 

groundwater. Due to absence of water, monitoring in this zone therefore is limited to testing the 

chemistry of the air contained within the pore space. The CO2 concentration of air samples taken in 

this zone can be measured using commercially available infrared gas analyzers (IRGAs), which 

measure the absorption of specific portions of the infrared spectrum to determine the concentration 

of CO2 (or other gases) in the air sample. 

 This cost component incorporates the expenditures for planning and equipment installation. 

Annual operating costs are included as a subsequent data item. 

Develop Plan and Implement Water Table Monitoring 

The water table is the subsurface zone that lies beneath the vadose zone. The water table can be 

monitored in shallow water wells to detect CO2 leakage at a GS site. This cost component 

incorporates the expenditures for planning and equipment installation. Annual operating costs are 

included as a subsequent data item. 

Periodic Monitoring of Groundwater Quality and Geochemistry 

As discussed above, the ground water must be monitored periodically to detect leakage. This cost 

component details the costs of periodic testing of water wells. Water samples are obtained from the 

well and tested at the laboratory. 

Surface Microseismic Equipment 

Microseisms are very small earthquakes that are assumed to be caused naturally or by the pressure 

front of the injected CO2. 38 Technologies that allow the determination of the location of 

microseisms in three dimensions through time are used to monitor plume movement. 

Passive seismic methods detect seismic signals other than those created by “active” sources. In this 

technology, sensors (geophones) are deployed downhole. Downhole receivers are cemented in a 

monitoring well and continuously record a signal from microseismic activity in the injection 

zone.39,40,41

 

38 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006. 

39 Monitoring of Sequestered CO2: Meeting the Challenge with Emerging Geophysical Technologies, S.N. Dasgupta, 

Saudi Aramco, 2005. 

40 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2, Report No. COAL R285 

DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Bentham, S. Holloway, and G. Kirby, British Geological 
Technology and Cost Document 

for the final GS Rule 23 November 2010 

Passive seismic is used to detect microfractures created during injection. The microfractures result 

from the change in pressure brought about by injection. Passive seismic is used to monitor CO2

plume movement, and to help determine the risk of developing through-going fractures that may 

impact migration or seal integrity. A series of surveys through time results in a time-lapse picture 

of CO2 movement. An advantage of microseismic monitoring is that, once the sensors are in place, 

there is little maintenance needed, and the data can be collected remotely.42 

Not all storage injection zones are amenable to passive seismic methods. Factors that play a role 

include rock mechanics, lithology, and natural seismic activity. 

This cost item includes the installation of microseismic detection equipment. Annual costs are 

itemized separately. 

Monitoring Well O&M Costs - Above Injection Zone 

This includes the annual costs of operating and maintaining monitoring wells completed above the 

injection zone including operating labor and system maintenance. 

Costs are specified as a base cost per year plus a depth based cost. 

Monitoring Well O&M Costs - Into Injection Zone 

This includes the annual costs of operating and maintaining monitoring wells completed in the 

injection zone including operating labor and system maintenance. 

Costs are specified as a base cost per year plus a depth based cost. 

U-Tube Sampling O&M – Enhanced Recovery 

This includes the annual costs of U-tube sampling for enhanced recovery operations. The U-tube 

technology was described previously. 

Annual Costs of Air and Soil Surveys – Eddy Covariance 

This component is the annual cost of continuous air sampling using eddy covariance equipment. 

This technology was described previously. 

 

Survey, Coordinator of the European Network of Excellence on Underground CO2 Storage (CO2GeoNet), Keyworth, 

Nottingham, UK, March 2005. 

41 SACS – 2, Work Package 4, Monitoring Well Scenarios, by I. M. Carlsen, S. Mjaaland, and F. Nyhavn, SINTEF 

Petroleum Research, Trondheim, Norway, for SACS group, April 6, 2001. 

42 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006.
Technology and Cost Document 

for the final GS Rule 24 November 2010 

Annual Costs of Air and Soil Surveys – Digital Color Infrared Orthoimagery or Hyperspectral 

Imaging 

This component is the annual cost of digital imagery for monitoring of the site. The technologies 

were described previously. 

Annual Costs of Air and Soil Surveys –LIDAR 

This component is the annual cost of a LIDAR airborne survey to detect surface CO2 leaks. This 

technology was described previously. 

Annual Costs of Air and Soil Surveys –Soil Zone Monitoring 

This component is the annual cost of soil zone monitoring. The technologies were described 

previously. The costs are based upon labor and a fee for lab testing. 

Annual Costs of Air and Soil Surveys –Vadose Zone Monitoring 

 This component is the annual cost of vadose zone monitoring. The technologies were described 

previously. The costs are based upon labor and a fee for lab testing. 

Annual Costs of Air and Soil Surveys – Samples from Water Table 

 This component is the annual cost of water table monitoring. The costs are based upon labor and a 

fee for lab testing. 

Annual Cost of Passive Seismic Equipment 

This component is the annual cost of passive seismic detection. The technologies were described 

previously. The cost is based upon an annual cost for each detection station. 

Periodic Seismic Surveys – 3D 

Seismic methods and costs were described above in the section on site characterization. Seismic 

data may also be used as a monitoring technology to evaluate CO2 plume movement during and 

after injection. Seismic data can detect plume movement by evaluating changes in fluid properties 

due to displacement of brine with CO2. Surveys may be repeated during injection and through the 

PISC monitoring phase.43 Three dimensional (3D) data are much more useful but are more costly to 

obtain and interpret than 2D data. Both velocity and amplitude anomalies may result from CO2

movement. 

Seismic data sources (the energy sources) may be either vibroseis or dynamite. A vibroseis truck is 

a mobile source that shakes to put energy into the ground. Small dynamite shots in shallow holes 

may also be used. Both of these methods have been used for decades in petroleum exploration. 

 

43 Matoon Site Environmental Information Volume, FutureGen Alliance, www.futuregenalliance.org, 

December 1, 2006. 
Technology and Cost Document 

for the final GS Rule 25 November 2010 

The ability to monitor CO2 in the subsurface using seismic depends upon numerous factors, and not 

all sites or injection zone formations will be amenable to seismic monitoring. For example, a 

storage formation that has low porosity or is very deep (certainly below 10,000 feet, and in some 

cases less) will be less amenable to seismic monitoring. Some geological settings may preclude the 

use of seismic because of near surface factors as well. Such factors may include irregular 

topography, unusual lithologies, surface water, manmade structures or impediments or other access 

factors. Where conditions are right, however, it is possible to detect plume movement and it can be 

possible to detect injected CO2 volumes of as little as 1,000 tons.44

In addition to surface seismic, vertical seismic profiling (VSP) and cross-well seismic may be used 

for subsurface monitoring to obtain very high resolution data over a small area. VSP is a technique 

in which surface sources are arrayed around a well that is in close proximity to a CO2 plume.45 The 

sensors are deployed downhole. The advantage of VSP is that it offers high quality resolution in the 

vicinity of the test well. It can also be used to detect upward migration of CO2. 

In cross-well seismic methods, seismic sources suspended on a cable are lowered into one well, and 

the receivers are lowered into an adjacent well.46 Both wells must penetrate to the base of the 

storage injection zone under investigation. This method results in a two-dimensional vertical slice 

of the subsurface with high resolution at the injection zone level. The method has been successfully 

tested at the Frio site in Texas. 

The VSP and cross-well approaches are not included in the cost model. The cost of 3D seismic is 

specified in terms of square mile area. A discussion of costs was presented in section 3.1 (site 

characterization) of this Technology and Cost document. 

Complex Modeling of Fluid Flows and Migration 

Reservoir modeling methods are numerical methods that employ a representation of a reservoir to 

evaluate and predict fluid pressures and flows. They can be used in an injection project to forecast 

the movement of CO2 in the reservoir. Modeling of subsurface CO2 flow must be used to define the 

area of review. Modeling is also used to help determine the location, number, and specifications for 

the injection and monitoring wells. 

CO2 flow from injection wells can be modeled and the injection zone capacity can be estimated 

with basic engineering methods. However, complex numerical models providing multi-phase and 

multi-component reservoir simulation may be used to understand the injection project and its 

 

44 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2, Report No. 

COAL R285 DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Bentham, S. Holloway, and G. Kirby, 

British Geological Survey, Coordinator of the European Network of Excellence on Underground CO2 

Storage (CO2GeoNet), Keyworth, Nottingham, UK, March 2005. 

45 Measurement, Monitoring, and Verification, L. H. Spangler, Zero Emission Research and Technology 

Center, Carbon Sequestration Leadership Forum, date unknown. 

46 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, 

December 1, 2006. 
Technology and Cost Document 

for the final GS Rule 26 November 2010 

impacts in much greater detail.47 Different models are needed to analyze the well-bore flow and to 

simulate the large-scale flow processes in the reservoir. Models may be designed to evaluate flow 

over periods of tens of years to thousands of years into the future. 

Reservoir modeling costs are specified in the cost model in terms of labor hours for the site plus 

additional labor hours per injection well. 

Reports to Regulators 

This cost item includes the labor costs to complete periodic reports to regulatory bodies. The cost is 

based upon an estimate of the number of hours of labor required. 

Monitoring Unit Costs 

Table 3 specifies the estimated costs and data sources for monitoring. 

 

47 GEO-SEQ Best Practices Manual, Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation, by 

the GEO-SEQ Project Team, Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, California, 

September 30, 2004. 
Technology and Cost Document 

for the final GS Rule 27 November 2010 

Table 3: Monitoring Unit Costs 

Tracking 

Number Cost Item Cost Algorithm Data Sources

B-1 Develop geochemical baseline for injection zones and 

confining zone.

$207 per sample. Assume 4 samples 

per injection well = $828 per injection 

well

Lab analysis fee of $100 to $200 discussed 

in N.O. meeting.

B-2 Develop baseline of surface air CO2 flux for Eddy Covariance 

leakage monitoring. $36,200 per station

Range of costs discussed at N.O. meeting 

Jan 2008 was $20,000 to $50,000 per 

station.

B-3a Conduct front-end engineering and design (monitoring wells 

ABOVE injection zone)

$20,700 + $5,200/shallow monitoring 

well Best professional judgement.

B-3b Conduct front-end engineering and design (monitoring wells 

INTO injection zone) $5,200/deep monitoring well Best professional judgement.

B-4a Obtain rights-of-way for surface uses. (monitoring wells 

ABOVE injection zone) $10,400 per monitoring well site Best judgement. Cost of land rights are 

highly variable.

B-4b Obtain rights-of-way for surface uses. (monitoring wells INTO 

injection zone) $10,400 per monitoring well site Best judgement. Cost of land rights are 

highly variable.

B-5 Obtain rights-of-way for surface uses. (monitoring sites)

$5,200 per air monitoring station site 

(microseismic is done inside montoring 

well and has no extra land costs)

Best judgement. Cost of land rights are 

highly variable.

B-6a Downhole safety shut-off valve $15,500 + $2.10/ft depth. Would be 

placed 100 or more feet above packer Best professional judgement.

B-6b Downhole check valve $500 Best professional judgement.

B-7

Standard monitoring well stopping above the injection zone 

(used lookup table). Standard monitoring wells for ER 

projects stop below the injection zone.

Use look-up table. $/foot = $155 to 

$207 per foot typical down to 9,000 ft.

Drilling cost is estimated from drilling cost 

equations developed from JAS and PSAC 

data.

B-8 Standard monitoring well drilled into the injection zone (used 

lookup table); applies to RA 3-4 only).

Use look-up table. $/foot = $155 to 

$207 per foot typical down to 9,000 ft.

Drilling cost is estimated from drilling cost 

equations developed from JAS and PSAC 

data.

B-9a Pressure, temperature, and resistivity gauges and related 

equipment for monitoring wells ABOVE injection zone $10,400/well Best professional judgement.

B-9b Pressure, temperature, and resistivity gauges and related 

equipment for monitoring wells INTO injection zone $10,400/well Best professional judgement.

B-10a

Salinity, CO2, tracer, etc. monitoring equipment for wells 

ABOVE injection zone (portion of equipment may be at 

surface such as for in situ sampling using U-tubes)

$10,400/well Best professional judgement.

B-10b

Salinity, CO2, tracer, etc. monitoring equipment for wells 

INTO injection zone (portion of equipment may be at surface 

such as for in situ sampling using U-tubes)

$10,400/well Best professional judgement.

B-10c ER Only. U-tube for sensing oil movement away from bottom 

of formation. Applies to 2 of 8 EOR wells. $16/ft + $30,000 per well Best professional judgement.

B-11a Develop plan and implement Eddy Covariance air monitoring. 40 hours @$107.23/hr = $4,289 for 

plan plus $75,000/monitoring site

Best professional judgment of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists. 

Monitoring station cost estimate from 

Benson 2004.

B-11b

Develop plan and implement Digital Color Infrared 

Orthoimagery (CIR) or Hyperspectral Imaging to detect 

changes to vegetation.

No construction costs, but planning 

and quality assurance costs would add 

$10,000 per square mile.

Best professional judgement.

B-11c Develop plan and implement LIDAR airborne survey to detect 

surface leaks. Works best where vegetation is sparse.

No construction costs, but planning 

and quality assurance costs would add 

$10,000 per square mile.

Best professional judgement.

B-11d Develop plan and implement soil zone monitoring 40 hours @$107.23/hr = $4,289 for 

plan plus $6,000/monitoring site Best professional judgement.

B-11e Develop plan and implement vadose zone monitoring wells to 

sample gas above water table.

40 hours @$107.23/hr = $4,289 for 

plan plus $8,000/monitoring site Best professional judgement.

B-11f Develop plan and implement monitoring wells for samples 

from water table.

40 hours @$107.23/hr = $4,289 for 

plan plus $80,000/monitoring site Best professional judgement.

B-12 Conduct periodic monitoring of groundwater quality and 

geochemistry. (146.90(d) of GS Rule).

$200/sample and 4 samples per well = 

$800 per well plus 0.5 hours of 

engineer labor for sampling per well 

per month.

Lab analysis fee of $100 to $200 discussed 

in New Orleans mtg.
Technology and Cost Document 

for the final GS Rule 28 November 2010 

Table 3 (continued): Monitoring Unit Costs 

Tracking 

Number Cost Item Cost Algorithm Data Sources

B-13 Surface microseismic detection equipment $52,000/ site (geophone arrays go into 

monitoring wells) Best professional judgement.

B-14a Monitoring well O&M (ABOVE injection zone) Annual O&M costs are $25,900 + 

$3.10/ft per well per year

Operating and maintenance costs adapted 

from EIA Oil and Gas Lease Equipment and 

Operating Cost estimates.

B-14b Monitoring well O&M (INTO injection zone) Annual O&M costs are $25,900 + 

$3.10/ft per well per year

Operating and maintenance costs adapted 

from EIA Oil and Gas Lease Equipment and 

Operating Cost estimates.

B-14c ER Only; U-tube O&M; for 2 of 8 wells drilled 200 feet below 

injection zone

$10,000 per year base O&M costs plus 

monthly sampling (=12*8 hrs/sample * 

$110.62/hr + 12* $200 (chromatograph 

cost) per sample = $10,000 plus 

$13,019 for 12 samples annually per 

well.

Best professional judgement with reference 

to Benson, 2004

B-15a Annual cost of air and soil surveys: Eddy Covariance $10,000 per station per year Best professional judgement with reference 

to Benson, 2004

B-15b

Annual cost of air and soil surveys: Digital Color Infrared 

Orthoimagery (CIR) or Hyperspectral Imaging to detect 

changes to vegetation.

Airborne survey costs of $6,250 per 

square mile plus mobilization costs of 

$5,000 per site.

Best professional judgement with reference 

to Benson, 2004

B-15c Annual cost of air and soil surveys: LIDAR airborne survey to 

detect surface leaks. Works best where vegetation is sparse.

Airborne survey costs of $6,250 per 

square mile plus mobilization costs of 

$5,000 per site.

Best professional judgement with reference 

to Benson, 2004

B-15d Annual cost of air and soil surveys: Soil zone monitoring $200 lab fee per sample plus $100 to 

collect.

Best professional judgement with reference 

to Benson, 2004

B-15e Annual cost of air and soil surveys: Vadose zone monitoring 

wells to sample gas above water table.

$200 lab fee per sample plus $100 to 

collect.

Best professional judgement with reference 

to Benson, 2004

B-15f Annual cost of air and soil surveys: Monitoring wells for 

samples from water table.

$200 lab fee per sample plus $1,000 to 

collect.

Best professional judgement with reference 

to Benson, 2004

B-16 Annual cost of passive seismic equipment $10,500 per station per year Best professional judgement with reference 

to cited Mattoon site report

B-17 Periodic seismic surveys: 3D $104,000/square mile for good 

resolution

Several published reports are in range of 

this cost. Cost depends on resolution 

(number of lines shot) of survey.

B-18 Complex modeling of fluid flows and migration (reservoir 

simulations) over 100 years (RA0-3) or 10,000 years (RA4).

180 hours of engineers @$110.62/hr = 

$19,912 per site + 64 hours of 

engineers @$110.62/hr = $7,080 per 

injection well

Best judgement of time required. Hourly 

rate derived from SPE 2009 salary survey 

of petroleum geologists.

B-19 Annual reports to regulators and recordkeeping for all data 

gathering activities.

20 hours of engineers @$110.62/hr = 

$2,212 per report plus 24 hours 

annually of engineer labor @110.62 

per hour = $2,655 for recordkeeping

Best judgement of time required. Hourly 

rate derived from SPE 2009 salary survey 

of petroleum geologists.

B-20

Semi-Annual (RA3) or quartery (RA4) reports to regulators 

and recordkeeping for all data gathering activities and 

recordkeeping.

15 hours of engineers @$110.62/hr = 

$1,659 per report plus 36 hours of 

engineer labor @$110.62/hr for 

recordkeeping = $3,982

Best judgement of time required. Hourly 

rate derived from SPE 2009 salary survey 

of petroleum geologists.

B-21 Monthly reports to regulators and recordkeeping for all data 

gathering activities and recordkeeping.

8 hours of engineers @$110.62/hr = 

$885 per report

Best judgement of time required. Hourly 

rate derived from SPE 2009 salary survey 

of petroleum geologists.

B-22 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 29 November 2010 

3.3 Injection Well Construction 

Front End Engineering and Design 

Front-end engineering and design are carried out for the overall site and for the injection wells. 

Design of the monitoring wells is included under the monitoring section. Injection well 

construction costs include development of standard plans associated with current UIC regulations 

(e.g., the drilling and casing plan, wellhead equipment plan, and downhole equipment selection), as 

well as pre-operational logging, sampling, and testing. 

Costs are specified as a base cost per site and a cost per injection well. 

Rights of Way for Surface Uses 

This element includes costs of the right-of-way for surface use for injection wells and for 

subsurface or pore space use. The issue of subsurface property rights varies by state and is 

discussed in detail in the IPCC report.48 Rights to use subsurface pore space could be granted 

separately from surface ownership. Obtaining the right to use subsurface pore space may represent 

a significant cost component of GS. Pore space costs are outside the scope of SDWA and are not 

attributable to the GS rule. In the Cost Analysis, pore space costs for the final rule, in incremental 

terms, are zero because they occur under both the baseline alternative and the final rule (pore space 

costs in incremental terms are zero for each of the regulatory alternatives in comparison to the 

regulatory baseline). These costs are presented in the analysis for completeness only. 

Costs are specified as a fixed cost per injection well. It is assumed that half of the cost is legal fees 

for the developer and the other half is a bonus payment to the landowner. Pipeline right-of-ways are 

specified as pipeline costs. 

Lease Rights for Subsurface Pore Space 

This includes the upfront costs only for use of pore space. The ongoing pore space costs during the 

project are specified separately under the discussion of well operation. 

Costs are specified on the basis of pore space area in acres. 

Land Use, Air Emissions, and Water Permits 

This unit cost item covers the estimated labor cost to obtain permits for land use, air emissions, and 

water use. 

Costs are specified as a base cost plus cost per impacted square mile. 

 

48 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the 

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer 

(eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp. 
Technology and Cost Document 

for the final GS Rule 30 November 2010 

UIC Permit Filing 

This unit cost item covers the estimated labor cost to prepare a UIC injection permit. Each well will 

require its own UIC permit (EPA will not issue area permits), but there will be economies of scale 

in compiling the group of permits submitted for each project site. 

Costs are specified as a base cost per site and a cost per injection well. 

Standard Injection Well Drilling Cost 

The technologies for drilling and equipping CO2 injection wells are well developed. Most aspects 

of drilling and completing such wells are similar or identical to that of drilling and completing a 

producing gas well. Many CO2 enhanced oil recovery projects are active in the U.S., especially in 

the Permian Basin of West Texas, and technologies have been developed to complete, produce, and 

maintain CO2 injection and CO2 EOR production wells for long periods of time. 

The design of a CO2 injection well is similar to that of a conventional gas (or other) injection well 

or a gas storage well, with the exception that much of the downhole equipment (e.g. casing and 

tubing, safety valves, cements, blowout preventers) must be upgraded for high pressure and 

corrosion resistance.49 A well program is designed prior to drilling to determine the drilling plan 

and casing points. This design incorporates what is known about the geology and engineering 

aspects of the location. 

Injection wells typically consist of several strings of casing extending to different depths. Multiple 

casing strings are required to isolate the well from shallow drinking water and to prevent problems 

with weak sections of the well bore.50 The innermost, deepest casing string is cemented in place 

across the storage injection zone and then perforated to allow movement of the CO2 into the well. 

Then a small diameter tube is run into the well inside the innermost casing. This injection tubing is 

sealed off from the casing with a double grip packer. 

The well is completed at the surface by installing a wellhead and “Christmas Tree” that sits on top 

of the wellhead and is an assembly of valves, pressure gauges and chokes. Devices are connected to 

the “Christmas Tree” that allow the monitoring of pressure, temperature, and injection rates. A 

blowout preventer is used to prevent well blowouts due to unexpected pressure (downhole devices 

are now required). A Supervisory Control and Data Acquisition (SCADA) is used to monitor the 

data. The system is set up to automatically shut down the injection if needed. 

Basic injection well drilling costs are specified on a per-foot of total depth basis. Cost per foot is 

typically in the range of $220 to $290 per foot. Additional costs such as the use of specialized 

tubing and casing, cementing, and wellhead equipment are evaluated separately (see below). 

Operating and maintenance costs are also not included here. 

 

49 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the 

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer 

(eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp. 

50 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006.
Technology and Cost Document 

for the final GS Rule 31 November 2010 

Well Stimulation 

In some cases, it may be necessary to artificially fracture the injection well to allow for efficient CO2 

injection. This is accomplished by injecting a mixture of water and sand or other proppant material. This 

type of well stimulation is now carried out on a large percentage of gas wells drilled in the U.S. Cost 

information was modified from the PSAC well cost study. For the current study, any such costs included in 

the model would be based upon the pounds of proppant injected. The expected range is 25,000 to 200,000 

pounds of proppant for the stimulation. 

Corrosion Resistant Tubing and Casing 

Operators of CO2 EOR projects have developed guidelines for the use of special materials to 

prevent or minimize corrosion caused by carbonic acid. As discussed in the Preamble of the final 

GS Rule, supercritical CO2 in the absence of water will not be corrosive. Corrosiveness of CO2 in 

the presence of water is well documented. An API report on injection technology lays out a set of 

guidelines that were developed to address this corrosivity:51 

Because of the corrosive effects of carbonic acid, H2CO3, on metal 

components, induced by the alternating water and gas (WAG) injection cycles 

during CO2 EOR operation, a significant fraction of scientific and technical work 

has been devoted to developing robust solutions to corrosion problems. 

Supplemental work has also been done on identifying and developing 

elastomeric materials for packers and seals that can withstand the solvent effects 

of supercritical CO2 that induce swelling and degradation. Throughout this 

process, the underlying strategy of the industry has been to select materials 

based on their durability and corrosion resistance. As a result of these efforts, 

tubular components can be expected to have a service life of 20 to 25 years 

before replacement. 

The following guidelines were published on page 23 of the report: 

Component Materials 

Upstream metering and piping runs 316 Stainless Steel (SS)/ Fiberglass 

Christmas Tree (Trim) 316 SS Nickel, Monel 

Valve Packing and Seals Teflon, Nylon 

Wellhead (Trim) 316 SS Nickel, Monel 

Tubing Hangar 316 SS Incoloy 

 

51 Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology, J.P. Meyer, Contek 

Solutions, for the American Petroleum Institute, 2007. 
Technology and Cost Document 

for the final GS Rule 32 November 2010 

Component Materials 

Tubing Glass Reinforced Epoxy (GRE) - lined carbon steel; 

IPC carbon steel, Corrosion Resistant Alloys (CRA) 

Tubing Joint Seals Seal ring (GRE), Coated threads and collars 

ON/OFF Tool, Profile Nipple Nickel plated wetted parts 

Packers Internally coated hardened rubber, etc. Nickel plated 

wetted parts 

Cements and Cement Additives API cements and/or acid resistant cements 

The nickel content of steel can be varied, with higher nickel content resulting in more corrosion 

resistance but higher costs. 

Corrosion Resistant Tubing

The tubing is the injection well tubular component through which the CO2 is injected into the 

formation. Cost assumptions for corrosion resistant tubing include glass reinforced epoxy (GRE). 

Costs are specified on the basis of tubing footage and diameter. 

Corrosion Resistant Casing

The casing is the injection well steel tubular component that is inserted in each section of drillhole 

after drilling and is subsequently cemented in place to prevent fluid movement. Cost assumptions 

are specified for corrosion resistant materials on the basis of casing diameter and footage. 

Cementing of the Injection Well Casing 

This cost item includes the cost of cementing the well from the surface through the base of the 

lowermost USDW and throughout the injection zone. Costs are specified on the basis of casing 

diameter and footage. Costs specified are for standard Portland cement. (Wells having waivers of 

the injection depth requirement will be cemented through the base of the USDW immediately 

above the injection zone.) 

Use of CO2-Resistant Cement 

The type of cement that is used in well cementing operations may be subject to chemical reactions 

in a CO2 injection zone. Casing and cement or other materials used in the construction of a GS well 

must have sufficient structural strength and be designed for the life of the geologic sequestration 

project. In addition, the GS rule specifies that all well materials must be compatible with fluids with 

which the materials may be expected to come into contact and must meet or exceed standards 

developed for such materials by the American Petroleum Institute, ASTM International, or 

comparable standards acceptable to the UIC Director. Thus, it may in some cases be necessary to 
Technology and Cost Document 

for the final GS Rule 33 November 2010 

use specialty cements in remediation or new well construction. The following text is taken from the 

API report on injection well technology used in CO2 EOR operations:52

Because CO2 corrosion of cement is thermodynamically favored and cannot 

be entirely prevented, various solutions have been developed to limit CO2 attack 

on the cement sheath. Most of these approaches involve substituting materials 

such as fly ash, silica fume or other non-affected filler or other cement 

materials for a portion of the Portland cement. The water ratio of the cement 

slurry is designed to be low to reduce the permeability of the set cement. The 

permeability of the set cement may be further lowered through the addition of 

materials such as latex (styrene butadiene) to the design. 

Recently, investigators took samples from a 52 year old SACROC well with 

conventional, Portland-based well cement exposed to CO2 for 30 years and 

found limited evidence of cement degradation. Preliminary evaluation suggests 

that the mixture of gelled and solid-particulate, (CO2 and cement), reaction 

products sealed the cement permeability pore throats to significantly delay or 

prevent further CO2 migration. While the evidence is limited, significant wellbore 

failure as indicated by over pressurization of over-lying formations and leakage to 

the surface has not been observed. 

Non-Portland solutions, marketed as specialty cements, have not been widely 

used in CO2 EOR applications, most likely due to the observed adequate 

performance of current formulations, as well as the higher cost and logistic 

issues associated with such systems. However, in some cases, these systems 

have been applied to resist very severe acid gas (CO2 and H2S) and highly 

corrosive geothermal brine exposure conditions, in place of conventional 

systems. 

Costs are specified on the basis of an incremental cost over standard cementing operations. 

Pumps 

Pumps, wellhead and control equipment, and measuring and monitoring equipment are required 

elements of the injection system. The pumps are those needed to move the CO2 to the injectors. 

Pump costs are a function of horsepower. Installation of electrical service also adds a cost 

component. 

Wellhead Control Equipment 

A diagram of typical injection well wellhead and control equipment is shown in Figure 5. The cost 

of injection equipment is a function of injectivity and the intended rate of injection. Injection well 

monitoring equipment is described in the 2007 API report and includes a lubricator valve for 

 

52 Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology, J.P. Meyer, Contek 

Solutions, for the American Petroleum Institute, 2007. 
Technology and Cost Document 

for the final GS Rule 34 November 2010 

running wireline tools, master valves to isolatethe tubing from the CO2 source, casing head valves 

to permit monitoring of pressure in the annulus between the production casing and the tubing string 

to ensure mechanical integrity, and a Bradenhead valve to monitor the pressure between the 

production casing and surface casing.53

Figure 5: Diagram of Typical CO2 Injection Wellhead 

Source: 2007 API report (cited on previous page). 

Costs are specified on the basis of the maximum number tons injected per day per well. Operating 

costs are not included here. 

Pipeline Costs 

Included in the cost analysis is the cost for a CO2 pipeline for the immediate GS site. As described 

previously in this Technology and Cost document, costs to transport the CO2 to the GS site are 

 

53 Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology, supporting information 

provided by J. P. Meyer, Contek Solutions, for the American Petroleum Institute, 2007. 
Technology and Cost Document 

for the final GS Rule 35 November 2010 

outside the scope of the rule and are excluded. Pipeline costs are specified in terms of cost per 

“inch-mile,” which is the pipeline diameter in inches times the miles of pipeline. 

Injection Well Construction Unit Costs 

Table 4 specifies the estimated costs and data sources for injection well construction. 
Technology and Cost Document 

for the final GS Rule 36 November 2010 

Table 4: Injection Well Construction Unit Costs 

Tracking 

Number Cost Item Cost Algorithm Data Sources

C-1 Conduct front-end engineering and design (general and 

injection wells), pre-op logging, sampling, and testing. $207,000/site + $41,400/injection well Best professional judgement.

C-2 Obtain rights-of-way for surface uses. (equipment, injection 

wells)

$20,700 per injection (pipeline right of 

ways included in pipeline costs) Half of 

cost is legal fees for developer, other 

half is bonus to landowner.

Best professional judgement. Cost of land 

rights are highly variable.

C-3 Lease rights for subsurface (pore space) use.

Upfront payment of $52/acre 

(additional injection fees under O&M 

costs)

Best professional judgement. Cost of land 

rights are highly variable.

C-4 Land use, air emissions, water discharge permits $103,400/site + $20,700/square mile Best professional judgement.

C-5 UIC permit filing, including preparation of attachments

$10,400/site + $6,000/injection well for 

first 5 wells at a site, then $2,000 

thereafter

Best professional judgement.

C-6a Standard injection well cost

Use look-up table. $/foot = $220 to 

$290 per foot typically down to 9,000 

ft.

Drilling cost is estimated from drilling cost 

equations developed from JAS and PSAC 

data.

C-6b Well stimulation

Total cost of stimulation based on cost 

per pound of proppant injected (coated 

sand); $1.25 /lb. of sand; 25,000 to 

200,000 lbs per frac

Modified from PSAC cost study

C-7 Corrosion resistant tubing

Additional $1.15/foot length - inch 

diameter for glass reinforced epoxy 

(GRE) lining

Based on SPE article on economics of GRE 

tubing.

C-8 Corrosion resistant casing

Additional $1.81/foot length inch 

diameter (low alloy) or $2.70/ft (higher 

alloy) - for corrosion resistant casing

PSAC and Preston Pipe Report

C-9 Cement well from surface through base of lowermost USDW 

and througout injection zone. $1.20/foot length - inch diameter Cementing cost based on 2008 PSAC Well 

Cost Study. 

C-10 Use CO2-resistant cement Adds 25% to total cementing costs Best professional judgement.

C-13 Injection pressure limited to 90% of fracture pressure of 

injection formation

Affects maximum flow of well, number 

of wells needed

Due to uncertainty of injectability, this 

pressure impact is ignored.

C-14 Pumps $1550/HP. Installation of electrical 

service adds $20,700 per well site.

Electrification cost based on EIA Oil and 

Gas Lease Equipment and Operating Cost 

estimates. Pump costs based on pipeline 

prime mover and compressor cost reported 

to FERC.

C-15 Wellhead and Control Equipment Cost per well is $520*(maximum tons 

per day injected per well)^0.6 Based on 2008 PSAC Well Cost Study. 

C-16 All elements of pipeline costs $83,000/inch-mile From pipeline cost data reported to FERC. 

Published annually in Oil and Gas Journal.

C-17 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 37 November 2010 

3.4 Area of Review and Corrective Action 

This aspect of the cost analysis includes fluid flow and reservoir modeling to predict the movement 

of the injected CO2 and pressure changes during and after injection. It also includes those cost 

elements pertaining to the identification, evaluation, and remediation of existing wells within the 

area of review. 

Simple Fluid Flow Calculations to Predict CO2 Flow 

Modeling of fluid flow in the subsurface can be based on relatively simple, straightforward 

approaches that are not particularly data intensive, or it can be extremely involved and use 

sophisticated numerical reservoir simulation models. Two basic types of analysis are included in 

the cost analysis, one simple approach using basic reservoir parameters, and the other based upon 

advanced reservoir simulation. 

This cost element is for a simple flow calculation that provides basic information on subsurface 

CO2 movement. 

Complex Modeling of CO2 Fluid Flow 

This cost element is an estimation of the number of hours of labor required to set up, run, and 

interpret a sophisticated subsurface reservoir simulation model. Cost items are included for a 100 

year simulation model and a 10,000 year simulation model. 

Aerial Survey to Find Old Wells 

This cost item involves an airborne magnetic survey using a helicopter that flies over the area of 

review to detect well casings from all cased wells. This may identify old wells that are not in 

existing databases. Magnetic surveys can also be carried out from ground vehicles, but airborne 

surveys can cover the large expected survey areas much more efficiently. If such well casings are 

identified, additional follow-up, research of well records and physical inspection can be used to 

obtain additional data on the condition of these wells. 

Evaluate Mechanical Integrity of Existing Wells Penetrating Containment System 

Existing wells at a planned GS site are potential conduits for the leakage of CO2. The goal in 

evaluating these wells is to assess risk and to develop a plan of corrective action prior to GS. The 

wells that are most critical in this analysis are those that penetrate the proposed injection zone and 

confining zone units. Factors that must be evaluated include the condition of the cement and overall 

well maintenance.54,55 

 

54 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the 

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer 

(eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp. 
Technology and Cost Document 

for the final GS Rule 38 November 2010 

A description of the process of evaluating and remediating old wells is provided by Meyer in a 

recent report published by API: 56

More recently, the 100 year old Salt Creek Field in Wyoming has been 

converted to a CO2 EOR development in which over 4,500 wells were re-completed. 

To do so, the following re-completion process was used: 

1. Where they existed, cement bond logs were examined to ascertain the 

condition of individual wellbores with regard to bonding between the 

casing and the adjoining formation. 

2. For wells that were plugged and abandoned, a pulling unit was set up and 

the wellbore drilled, from the top of the surface conductor to the bottom of 

the target formation to remove any accumulated debris (cement, bridge 

plugs, tree stumps, etc). 

3. For those wells with cement bond logs, if insufficient or inadequate 

bonding was detected, a squeeze cement procedure was used to place 

cement behind the casing and the cement bond log rerun to validate 

successful wellbore remediation. 

4. For every well, a casing mechanical integrity test was run. This required 

pressurizing the wellbore and monitoring it, to see if any pressure falloff 

occurred. If not, the wellbore was competent. 

5. When pressure fall off was observed, it was indicative of casing leaks. 

The leaking section of casing was first identified and then re-sealed by 

squeeze cementing. In extreme cases, it was necessary to install a liner 

over the leaking section. 

This cost item includes the labor costs to evaluate the integrity of wells penetrating the containment 

system at the site. Costs are specified on the basis of hours of labor costs at specified labor rates. 

Evaluate Integrity of Shallow Wells 

Existing shallow wells may pose a threat to USDWs. This cost item includes labor costs to evaluate 

the record of completion and plugging of shallow wells. 

 55 Measuring and Modeling for Site Characterization: A Global Approach, D. Vu-Hoang, L. Jammes, O. 

Faivre, and T.S. Ramakrishnan, Schlumberger Carbon Services, March, 2006. 

56 Summary of Carbon Dioxide Enhanced Oil Recovery Injection Well Technology, by James P. Meyer, API, 

http://www.gwpc.org/e-library/e-library_documents/e-library_documents_co2/API%20CO2%20Report.pdf

(no publication date provided)
Technology and Cost Document 

for the final GS Rule 39 November 2010 

Remediate Old Wells in Area of Review 

It may be necessary to remediate existing wells at a potential GS site. Existing wells that penetrate 

the injection zone or overlying seal units may provide conduits for the vertical movement of 

injected CO2. Well remediation may involve the removal of existing plugs and casing strings, and 

re-completing the well. In some cases this may involve the use of CO2 resistant cements in portions 

of the well. 

In the case of saline formations, there may be few, if any, existing wellbores. However, with older 

oil and gas fields, remediation costs may be significant, especially with old wells. The major 

difficulty in estimating the scope and nature of remediation is that there is little definitive research 

on the subject of the need for application of CO2-resistant cement in acid gas wells.57 

Remediate Old Wells that Pose a Risk to USDWs

Owners and operators must remediate wells that are in a condition that poses a risk to a USDW to 

ensure well integrity. This cost item includes well cleanout, logging, and re-plugging. 

Remediate Old Wells in AOR that Lack High Quality Cementing Information

Wells that lack adequate information on cementing must undergo remediation to ensure integrity. 

This cost item includes well cleanout, logging, and re-plugging. 

Area of Review and Corrective Action Unit Costs 

Table 5 specifies the estimated costs and data sources for area of review and corrective action. 

 

57 EPA workgroup, January, 2008. 
Technology and Cost Document 

for the final GS Rule 40 November 2010 

Table 5: Area of Review and Corrective Action Unit Costs 

Tracking 

Number Cost Item Cost Algorithm Data Sources

D-1 Simple fluid flow calculations to predict CO2 fluid flow.

36 hours of engineers @$110.62/hr = 

$3982 per site + 12 hours of engineers 

@$110.62/hr = $1327 per injection well

Best professional judgement of time 

required. Hourly rate may change based on 

labor survey data.

D-2 Complex modeling of CO2 fluid flows and migration (reservoir 

simulations) over 100 years

180 hours of engineers @$110.62/hr = 

$19,912 per site + 24 hours of 

engineers @$110.62/hr = $2,655 per 

injection well

Best professinoal judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

D-3 Complex modeling of CO2 fluid flows and migration (reservoir 

simulations) over 10,000 years

180 hours of engineers @$110.62/hr = 

$19,912 per site + 36 hours of 

engineers @$110.62/hr = $3,982 per 

injection well

Best professinoal judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

D-4 Areal search for old wells (artificial penetrations)

helicopter magnetic survey requires 

about 9 hours/square mile @$1,240 

per hour. Cost = $5,200 mobilization + 

$11,160 per square mile. Follow-up 

ground surveys will add another 

$2,070 per square mile. (helicopter 

survey interline spacing is about 80 

feet with speed of 10 ft/sec)

Based on DOE sponsored research at Salt 

Creek WY . Helicopter hourly rate is in 

range of several published estimates, 

adjusted for fuel costs.

D-5

Evaluate integrity of construction and record of completion 

and/or plugging of existing wells that penetrate containment 

system.

24 hours @$107.23/hr = $2,574 per 

site + 6 hours @$110.62/hr = $664 

per well

Best judgement of time required. Hourly 

rate derived from AAPG 2009 salary survey 

of petroleum geologists.

D-6

Evaluate integrity of construction and record of completion 

and/or plugging of existing shallow wells that pose a treat to 

USDWs.

6 hours @$110.62/hr = $664 per well

Best professinoal judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

D-7 Remediate old wells in AoR that pose a risk to USDWs

$31,200 for clean out, $13,500 to 

replug and $11,400 to log (two cement 

plugs - one in producing formation and 

one for surface to bottom of USDWs, 

remainder of borehole filled with mud). 

Water well remediation is $20,700.

Plugging and logging cost based on 2008 

and 2009 PSAC Well Cost Studies. Clean 

out cost will vary widely. Cost here is 3 days 

of rig use @ $10,400 per day. Rig cost 

from Land Rig Newsletter US Land Rig 

Rates.

D-8 Remediate old wells in AoR that lack high quality cementing 

information

$31,200 for clean out, $13,500 to 

replug and $11,400 to log (two cement 

plugs - one in producing formation and 

one for surface to bottom of USDWs, 

remainder of borehole filled with mud). 

Water well remediation is $20,700.

Plugging and logging cost based on 2008 

and 2009 PSAC Well Cost Studies. Clean 

out cost will vary widely. Cost here is 3 days 

of rig use @ $10,400 per day. Rig cost 

from Land Rig Newsletter US Land Rig 

Rates.

D-9 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 41 November 2010 

3.5 Well Operation 

This cost category includes those cost elements related to the operation of the injection wells, 

including measuring and monitoring equipment, electricity costs, O&M costs, pore space costs, 

repair and replacement of wells and equipment, and estimated costs for the possibility of failure at 

the site and the need to relocate a GS operation. As discussed previously in this Technology and 

Cost document, pore space costs are included for completeness in the analysis, but are not 

attributable to this rulemaking. 

Corrosion Monitoring and Prevention Program 

Because of the potential for CO2 to be corrosive in the presence of water, owners and operators 

must develop a corrosion monitoring and prevention program for the operation. The cost is 

specified as labor hours to develop the program. 

Corrosion Monitoring 

This cost item includes the labor costs and sample analysis costs for the corrosion monitoring 

program. Corrosion monitoring includes quarterly analysis of the injectate stream and the 

measurement of corrosion well material coupons. 

Measuring and Monitoring Equipment 

Measuring and monitoring equipment include a lubricator valve for running wireline tools, master 

valves to permit isolation of the tubing from the CO2 source, casing head valves to permit 

monitoring of pressure in the annulus between the production casing and the tubing string to ensure 

mechanical integrity, and a Bradenhead valve to permit monitoring of the pressure between the 

production casing and surface casing.58

This cost item includes the equipment costs for equipment to monitor injection volumes, pressure, 

flow rates, and annulus pressure. It is specified as a cost per injection well. 

Equipment to Add Tracers 

Tracer testing is implemented at the Director’s discretion, and involves the incorporation of trace 

amounts of chemical compounds into the injected CO2. The objective is to confirm the migration 

and location of CO2 within the injection zone and potentially in overlying groundwater or soil 

zones. A number of tracers with very low detection limits are available and more are under 

development. 

 

58 Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology, supporting information 

provided by J. P. Meyer, Contek Solutions, for the American Petroleum Institute, 2007. 
Technology and Cost Document 

for the final GS Rule 42 November 2010 

The use of tracers for monitoring was investigated under GEO-SEQ59. Natural and artificial tracers 

have the potential to assist in characterizing injection zones, and calibrating models as well as 

indicating leakage and seepage. 

Tracers may consist of natural tracers (isotopes of C, O, H, and noble gases) that are associated 

with the injected CO2, and introduced tracers including noble gases, SF6, and perfluorocarbons 

(PFC’s). 60 Perfluorocarbon Tracers (PFTs) have many advantages in that they are soluble in water, 

non-toxic, non-radioactive, and have an extremely small detection limit. 61 Thus, much smaller 

amounts are required to be injected compared to other compounds such as sulfur hexafluoride. 

Tracers may be detected in monitoring wells either within the storage injection zone or in shallower 

zones, groundwater, or soil gases. At the Frio Brine pilot in Texas, there were three types of 

monitoring installations to test for CO2 in shallow zones.62 These included capillary absorbent tubes 

(CATs) and soil gas wells for the soil zone and water wells for groundwater testing. Soil gas wells 

may be only a few feet deep and are sampled with a syringe. CAT samples are removed and 

shipped to a laboratory for analysis. Fresh CATs are then installed and the sample tubes sealed. 

Groundwater wells are sampled for the headspace atmosphere. 

If chemical tracers are to be injected into the CO2 stream for monitoring purposes, it will be 

necessary to incur costs related to the injection equipment. This cost is specified as a cost per 

injection well. 

Electricity Costs for Pumps and Equipment 

Electricity costs represent a significant component of overall operating costs. This cost item 

specifies the electricity costs for pumps and equipment. The cost is specified as dollars per kilowatt 

hour. 

Injection Well Operating and Maintenance Costs 

The annual costs of operating and maintaining the injection wells include operating labor, system 

maintenance, and CO2 compression costs (if needed). Not included in this unit cost are the costs for 

mechanical integrity pressure tests, mechanical integrity logging, and the repercussions from those 

tests, such as the cost to repair, rework, or plug the injection well. 

Costs are specified as a base rate per year plus a cost per foot per well. 

 

59 GEO-SEQ Best Practices Manual, Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation, by 

the GEO-SEQ Project Team, Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, California, 

September 30, 2004. 

60 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide, S. Benson and L. Myer, 

Lawrence Berkeley Laboratory, Berkeley, California, 2002. 61 Surface Environmental Monitoring at the Frio CO2 Sequestration Test Site, Texas, H.S. Nance, Texas Bureau of 

Economic Geology, Austin, Texas, DOE/NETL Conference on Carbon Capture and Storage, May, 2005. 

62 Surface Environmental Monitoring at the Frio CO2 Sequestration Test Site, Texas, H.S. Nance, Texas Bureau of 

Economic Geology, Austin, Texas, DOE/NETL Conference on Carbon Capture and Storage, May, 2005. 
Technology and Cost Document 

for the final GS Rule 43 November 2010 

Land Use Rents and Right of Way 

This unit cost includes the ongoing annual costs for land use and right of way during site operation. 

This is distinct from the upfront land use costs associated with site characterization. 

 

Costs are specified in terms of dollars per acre per year. 

Pore Space Unit Costs 

This unit cost includes an estimate of pore space cost per barrel of CO2 injected. This is distinct 

from the upfront payment unit cost included under site characterization. While pore space costs are 

included in the analysis, they are not attributable to the final rule. 

Property Taxes and Insurance 

This unit cost includes the ongoing expense of property tax and liability insurance. It is specified as 

a cost per dollar of capital expenditures. 

Tracers in Injected Fluid 

The use of injected tracers to detect leakage is discussed above. This cost item specifies the cost of the tracer 

material, estimated as a cost per unit volume of CO2 injected. 

Repair or Replace Wells and Equipment 

This cost component includes remediation of wells and equipment that occurs during the injection 

phase. This is in addition to the remediation that is completed during the initial site remediation 

work. The cost is based upon an assumption of 1 percent per year of initial well and equipment 

cost. 

General Failure of Containment Site – Remove and Relocate CO2

There is a small probability that a given GS site will not perform adequately, due to unforeseen 

subsurface conditions that are not detected during the site characterization and construction phases. 

This may require in a small percentage of cases the closure of the site and re-location sometime 

during the operating life or in the post-injection period. The best method of incorporating such a 

cost is through a risk-based accounting approach, taking the entire cost times the small probability 

of occurrence. An assumption is made of a 1 percent chance of site failure after it is constructed 

and begins operations. 

Well Operation Unit Costs 

Table 6 specifies the estimated costs and data sources for well operation unit costs. 
Technology and Cost Document 

for the final GS Rule 44 November 2010 

Table 6: Well Operation Unit Costs 

Tracking 

Number Cost Item Cost Algorithm Data Sources

E-1 Develop a corrosion monitoring and prevention program 24 hours of engineers @$110.62/hr = 

$2655 per site

Best professional judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

E-2 Corrosion monitoring; quarterly analysis of injectate stream 

and measurement of corrosion of well material coupons.

6 hours a@ $110.62/hr= $663.72/well 

plus $25/well (quarterly) plus $300 per 

sample (4 samples per injection well)

Best professional judgement.

E-3 Continuous measurement / monitoring equipment: injected 

volumes, pressure, flow rates and annulus pressure $15,500/well Best professional judgement.

E-4 Equipment to add tracers $10,400/well Best professional judgement.

E-5 Electricity cost for pump, equipment $0.066/kWh 2007 average industrial sector electricity 

price reported by EIA.

E-6 Injection well O&M Annual O&M costs are $77,500 + 

$3.10/ft per well per year

Operating and maintenance cost based on 

EIA Oil and Gas Lease Equipment and 

Operating Cost estimates.

E-7 Land use rent, rights-of-way $5.20/acre/year

Best professional judgement based on oil & 

gas industry costs. Cost of land rights are 

highly variable.

E-8 Pore space use costs $0.052/barrel or about $0.36 per metric 

ton

Best professional judgement based on oil & 

gas industry costs. Cost of land rights are 

highly variable.

E-9 Property Taxes & Insurance $0.03/$1CAPEX Best professional judgement.

E-10 Tracers in injected fluid $0.05/ton of CO2 injected Best professional judgement. Cost will 

depend of type of tracer.

E-12 Repair, replace wells and equipment Assume 1%/year of initial well and 

equipment cost Best professional judgement

E-13 General failure of containment at site: cost to remove and 

relocate CO2

Assuming a 1% chance of failure over 

injection life, then approximately 

0.083% of total capital costs each year 

would cover such a contingency

Best professional judgement

E-14 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 45 November 2010 

3.6 Mechanical Integrity Tests 

Owners or operators of CO2 injection wells must periodically evaluate well integrity to ensure 

mechanical soundness, lack of corrosion, and ability to sustain pressure. There are several such 

tests that are typically used, and they include both pressure tests and wireline logs. These 

technologies are well established and have been used for decades for underground injection 

operations. 

Internal Mechanical Integrity Tests 

An injection well has internal mechanical integrity if it can be demonstrated that there is no leakage 

in the tubing, casing, or packers. This is differentiated from an external mechanical integrity that 

evaluates the bond between casing and rock. 

Annular pressure under normal operating conditions will be continuously monitored and recorded 

as one means of assuring internal mechanical integrity. In addition, periodic internal MITs can be 

performed. The most common internal periodic MIT is the standard annular pressure test (SAPT). 

The annulus between the casing and injection tubing is pressured far above normal operating 

conditions and monitored to see if the pressure holds.63 

EPA and state regulatory agencies have specific requirements for pressure testing injection wells 

and for performing other mechanical integrity tests.64,65 Testing occurs prior to injection and 

periodically thereafter. Wells that fail the mechanical integrity test must be shut in until repaired, 

reworked, or plugged.66 In addition if after a mechanical integrity test is performed, a well 

operation causes the injection packer to be unseated or if the tubing or packer was pulled, repaired, 

or replaced, the well must be re-tested for mechanical integrity. 

Casing Inspection Log 

Following is a definition of the casing inspection log: 

An in situ record of casing thickness and integrity, to determine whether and to what extent 

the casing has undergone corrosion. The term refers to an individual measurement, or a 

combination of measurements using acoustic, electrical and mechanical techniques, to 

evaluate the casing thickness and other parameters. The log is usually presented with the 

basic measurements and an estimate of metal loss. It was first introduced in the early 1960s. 

 

63 Carbon Dioxide Storage: Geological Security and Environmental Issues – Case Study on the Sleipner Field, Norway, 

S. Soloman, Bellona Foundation, May, 2007. 

64 UIC Program Mechanical Integrity Testing: Lessons for Carbon Capture and Storage, Jonathan Koplos, Bruce 

Kobelski, Anhar Karimjee, and Chi Ho Sham, Fifth Annual Conference on Carbon Capture and Sequestration, 

DOE/NETL, May, 2006. 

65 Determination of the Mechanical Integrity of Injection Wells, EPA Region 5 website, 

www.epa.gov/region5/water/uic/r5guid/r5_05.htm

66 Underground Injection Control Rules, Montana Board of Oil and Gas Conservation, 

www.bogc.dnrc.state.mt.us/uicrules.htm.
Technology and Cost Document 

for the final GS Rule 46 November 2010 

Today the terms “casing-evaluation log” and “pipe-inspection log” are used 

synonymously.67

Radioactive Tracer Survey of Bottom Hole Cement 

A radioactive tracer survey is a mechanical integrity test in which a slug of radioactive material is 

injected into the well, and gamma ray detection equipment is used to detect specific movement of 

the tracer material between the well and the surrounding rock that indicates problems with the 

cement, in which the injected material moves in vertical channels outside the casing. 

External Mechanical Integrity Test 

A number of wireline logging tools are used to evaluate external integrity, which is the integrity of 

the bond between the cement and surrounding rock or between the casing and the cement. These 

include cement bond, temperature, noise, and oxygen activation logs.68 Cement bond logs are used 

to assess the presence, bond and continuity of cement. Periodic cement bond logs can detect 

deterioration of the cement through time or any indication of reaction with CO2.

69 Descriptions of 

these technologies are available at the EPA Region 5 website 70

Costs are specified for annual tests or tests every six months. 

Pressure Falloff Tests 

A falloff test is a pressure transient test that consists of shutting in an injection well and measuring 

the pressure falloff. 71 Falloff tests provide injection zone pressure data and are used to characterize 

both the injection zone and the completion condition of the injection well. For Class I nonhazardous injection wells, operators are required to perform the test annually. 

Mechanical Integrity Test Unit Costs 

Table 7 specifies the estimated costs and data sources for mechanical integrity test unit costs. 

 

67 http://www.glossary.oilfield.slb.com/Display.cfm?Term=casing-inspection%20log 68 UIC Program Mechanical Integrity Testing: Lessons for Carbon Capture and Storage, Jonathan Koplos, Bruce 

Kobelski, Anhar Karimjee, and Chi Ho Sham, Fifth Annual Conference on Carbon Capture and Sequestration, 

DOE/NETL, May, 2006. 

69 Carbon Dioxide Storage: Geological Security and Environmental Issues – Case Study on the Sleipner Field, 

Norway, S. Soloman, Bellona Foundation, May, 2007. 

70 Determination of the Mechanical Integrity of Injection Wells, EPA Region 5 website, 

www.epa.gov/region5/water/uic/r5guid/r5_05.htm

71 UIC Pressure Falloff Requirements, USEPA Region 9, August, 2002.
Technology and Cost Document 

for the final GS Rule 47 November 2010 

Table 7: Mechanical Integrity Tests Unit Costs 

Note: Schedule/periodicity for each unit cost is described in Appendix B (Project Algorithms) of the Cost 

Analysis of the Final GS Rule.72

3.7 Well Plugging, Equipment Removal, and Post-Injection Site Care (PISC) 

After the injection phase has ended, the owner or operator must close the site in a safe and secure 

manner that protects USDWs from endangerment and monitor the site during the PISC period. This 

involves the plugging of injection wells, removal of surface equipment, and land restoration. It also 

includes long term requirements for monitoring the site to ensure safety and to confirm that the CO2

moved as expected in the subsurface. 

Flush Wells with Buffer Fluid before Plugging 

Prior to plugging, the well is flushed with a buffer fluid. This cost includes a fixed component and a 

cost per inch-foot of casing diameter. 

Plug Injection Wells 

Upon completion of injection operations and PISC, prior to site closure, an owner or operator will 

plug those injection wells not intended for further use as monitoring wells. Monitoring wells will be 

plugged following a phase of long-term monitoring. Closure of injection and monitoring wells 

involves the placement of cement plugs over all or part of the well, with special care taken to seal 

off USDWs. While most aspects of plugging CO2 injection wells are similar to procedures used in 

conventional wells, it may be required to plug more of the well and may be necessary to use 

 

72 Cost Analysis for the Final GS Rule, EPA 816-R-10-013. 

Tracking 

Number Cost Item Cost Algorithm Data Sources

F-1 Internal mechanical integrity pressure tests $2,070/test Best professional judgement.

F-2 Casing inspection log $2,070 plus $4.15/foot

Based on 2008 and 2009 PSAC Well Cost 

Studies for wireline log suite. Cost of MIT 

log could be lower.

F-3 Conduct a tracer survey of the bottom-hole cement using a 

CO2-soluble isotope $5,200/test Best professional judgement.

F-5 External mechanical integrity tests to detect flow adjacent to 

well using temperature or noise log $2,070 plus $4.15/foot

Based on 2008 PSAC Well Cost Study for 

wireline log suite. Cost of external MIT log 

could be lower.

F-6 External mechanical integrity tests to detect flow adjacent to 

well using temperature or noise log $2,070 plus $4.15/foot

Based on 2008 PSAC Well Cost Study for 

wireline log suite. Cost of external MIT log 

could be lower.

F-7 Conduct pressure fall-off test $2,070/test Best professional judgement.

F-9 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 48 November 2010 

corrosion resistant cement. (Reference: IPCC report). A guide to the plugging and closure 

requirements for injection wells is available on the EPA website.73

Costs are specified as a cost per well for logging and plugging. Cement plugging involves two 

plugs – one in the injection zone and one from the surface to the base of the USDWs. 

Perform Mechanical Integrity Test Prior to Plugging 

An important aspect of proper well closure is mechanical integrity testing. This testing confirms 

that the casing and cement have integrity and will not provide a pathway for fluid movement. 

Various types of mechanical integrity tests are described in the previous section. Costs are specified 

as a base cost per well and cost per foot. 

Plug Monitoring Wells 

Monitoring wells at the site may be conduits for leakage and also will require eventual plugging 

after the long-term monitoring period. Costs are specified for three cases: 

 Plug monitoring wells above injection zone 

 Plug monitoring wells into injection zone 

 Plug monitoring wells below injection zone (for waivered wells) 

Remove Surface Equipment, Structures, Restore Vegetation 

For both injection and monitoring wells, surface equipment will be removed and the site restored. 

Injection well site restoration occurs after the injection period and monitoring well restoration 

occurs before closing the site. 

Costs are specified for four cases: 

 Injection wells 

 Monitoring wells above injection zone 

 Monitoring wells into injection zone 

 Monitoring wells below injection zone (waivered wells) 

Costs are specified as a fixed cost per well and cost per monitoring station. 

Document Plugging and Post-Injection Process 

This cost item includes the labor costs for notification to regulators of intent to cease injection, 

including well plugging, PISC, and site closure plans. 

 

73 U.S. EPA, http://www.epa.gov/r5water/uic/r5guid/r5_04.htm#iv.
Technology and Cost Document 

for the final GS Rule 49 November 2010 

PISC Monitoring Well O&M 

The annual costs of operating and maintaining the monitoring wells will extend through the end of 

the PISC monitoring period. 

Costs are specified for three cases: 

 Monitoring wells above injection zone 

 Monitoring wells into injection zone 

 Monitoring wells below injection zone (waivered wells) 

Post-Injection Air and Soil Surveys 

The annual costs of air and soil surveys will extend through the end of the PISC monitoring period. 

Costs are specified per station per year. 

Post- Injection Seismic Surveys 

The annual costs of seismic surveys will extend through the end of the PISC monitoring period. 

Costs are specified on a square mile basis. 

Post- Injection Reports to Regulators 

Periodic reports to regulators will continue during PISC monitoring. The frequency and duration of 

reports is dependent upon the regulatory alternative and is specified in Chapter 5 of the Cost 

Analysis.74 Costs are specified as labor costs. 

Well Plugging, Equipment Removal, and PISC Unit Costs 

Table 8 specifies the estimated costs and data sources for plugging, equipment removal and postinjection care. 

 

74 Cost Analysis for the Final GS Rule, EPA 816-R-10-013. 
Technology and Cost Document 

for the final GS Rule 50 November 2010 

Table 8: Well Plugging, Equipment Removal, and PISC Costs 

Note: Schedule/periodicity for each unit cost is described in Appendix B (Project Algorithms) of the Cost 

Analysis of the Final GS Rule.75

 

75 Cost Analysis for the Final GS Rule, EPA 816-R-10-013. 

Tracking 

Number Cost Item Cost Algorithm Data Sources

G-1 Flush wells with a buffer fluid before closing $1000 + $0.085/inch-foot casing 

diameter Best professional judgement.

G-2 Plug injection wells (done to all wells)

$13,500 to plug and $11,400 to log 

(two cement plugs - one in injection 

formation and one for surface to 

bottom of USDWs, remainder of 

borehole filled with mud)

Plugging and logging cost based on 2008 

PSAC Well Cost Study. 

G-3 Perform a mechanical integrity test prior to plugging to 

evaluate integrity of casing and cement to remain in ground $2,070 plus $4.15/foot Based on 2008 PSAC Well Cost Study for 

wireline log suite.

G-4a Plug monitoring wells ABOVE injection zone

$6,700 to plug and $5,700 to log (one 

cement plugs - surface to bottom of 

USDWs, remainder of borehole filled 

with mud)

Plugging and logging cost based on 2008 

PSAC Well Cost Study. 

G-4b Plug monitoring wells INTO injection zone

$6,700 to plug and $5,700 to log (one 

cement plugs - surface to bottom of 

USDWs, remainder of borehole filled 

with mud)

Plugging and logging cost based on 2008 

PSAC Well Cost Study. 

G-5 Remove surface equipment, structures, restore vegetation 

(injection wells) $25,900/injection well Best professional judgement.

G-6a Remove surface equipment, structures, restore vegetation 

(monitoring wells ABOVE injection zone)

$10,400/monitoring well, $5,200 for 

monitoring stations Best professional judgement.

G-6b Remove surface equipment, structures, restore vegetation 

(monitoring wells INTO injection zone)

$10,400/monitoring well, $5,200 for 

monitoring stations Best professional judgement.

G-7

Document plugging and closure process (well plugging, postinjection plans, notification of intent to close, post-closure 

report)

120 hours of engineers @$110.62/hr = 

$13,274 per site

Best professional judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

G-8a Post-closure monitoring well O&M (ABOVE injection zone) Annual O&M costs are $25,900 + 

$3.10/ft per well per year

Operating and maintenance costs adapted 

from EIA Oil and Gas Lease Equipment and 

Operating Cost estimates.

G-8b Post-closure monitoring well O&M (INTO injection zone) Annual O&M costs are $25,900 + 

$3.10/ft per well per year

Operating and maintenance costs adapted 

from EIA Oil and Gas Lease Equipment and 

Operating Cost estimates.

G-9 Post-injection air and soil surveys $10,400 per station per year Best professional judgement.

G-10 Post-closure seismic survey $104,000/square mile for good 

resolution

Several published reports are in range of 

this cost. Cost depends on resolution 

(number of lines shot) of survey.

G-11 Periodic post-injection monitoring reports to regulators 40 hours @$110.62/hr = $4,425 per 

report

Best professional judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

G-12 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 51 November 2010 

3.8 Financial Responsibility 

To ensure that resources are available to protect USDWs from endangerment, today's rule identifies 

qualifying financial instruments, the time frames over which financial responsibility must be 

maintained, procedures for estimating the costs of activities covered by the financial instruments, 

procedures for notifying the Director of adverse financial conditions, and requirements for 

adjusting cost estimates to reflect changes to the project plans. Today’s rule requires the owner or 

operator to have a detailed written estimate, in current dollars, of the cost of: 1) performing 

corrective action on wells in the AoR, 2) plugging the injection well(s), 3) PISC and site closure, 

and 4) emergency and remedial response. The cost estimate must be prepared separately for each 

injection activity and be based on the costs to the owner or operator of hiring a third party (who is 

neither a parent nor a subsidiary of the owner or operator) to perform the activities. The following 

unit costs were used: 

Performance Bond or Demonstration of Financial Ability to Close Site 

This cost item includes the labor costs to prepare a report demonstrating financial responsibility for 

well plugging. 

Performance Bond or Demonstration of Financial Ability for PISC 

This cost item includes the labor costs to prepare a report demonstrating financial responsibility for 

post injection monitoring period, including remediation. The duration of the period is dependent 

upon the regulatory alternative, and is specified in Chapter 2 of the Cost Analysis.76 

Financial Responsibility Unit Costs 

Table 9 specifies the estimated costs and data sources for financial responsibility unit costs. 

Table 9: Financial Responsibility Unit Costs 

 

76 Cost Analysis for the Final GS Rule, EPA 816-R-10-013. 

Tracking 

Number Cost Item Cost Algorithm Data Sources

H-1 Performance bond or demonstrate financial ability to close 

site (including an inflation factor)

8 hours @$110.62/hr = $885 per 

financial report

Best professional judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

H-2 Performance bond or demonstrate financial ability for postinjection monitoring, remediation (including an inflation factor)

4 hours @$110.62/hr = $442 per 

financial report

Best professional judgement of time 

required. Hourly rate derived from SPE 

2009 salary survey of petroleum geologists.

H-3 Operating G&A 20% of annual operating costs Best professional judgement based on oil 

and gas industry factors.
Technology and Cost Document 

for the final GS Rule 52 November 2010 

4 Uncertainties in Analysis 

As with any technology and cost analysis, there are many sources of uncertainty, including current 

costs and likely future costs. In this analysis, uncertainty is characterized as follows: 

Uncertainties are related to: 

 Unit costs of technology (e.g. dollars per foot to drill and complete an injection well) 

 Characteristics of the example case which determines how the unit costs are multiplied. 

(e.g. number of feet to injection zone) (presented in the Cost Analysis) 

 How many times the costs are applied through the life of the project. (e.g. number of 

surveys) (presented in the Cost Analysis) 

 Number of hours and hourly rates for large scale aspects such as geologic characterization 

 Costs changes through time due to: 

o Worldwide demand for materials 

o Improved technology 

o Better knowledge of what works and what amount of data needed 

o Availability of workforce and their experience. 

o Labor costs 

Uncertainty in Unit Costs

Generally speaking, the unit costs for which there is greater certainty are those directly or indirectly 

related to conventional drilling and completion practices and geophysical techniques used in 

exploration and development. This includes drilling costs and day rates, completion costs including 

tubulars and wellhead equipment, and so forth. The cost of 2D and 3D seismic is well known, 

although there is considerable variation related to the geology and depth of each site, and the 

spacing and resolution needed. The cost of pipelines of different diameters and capacity are known 

to industry but vary based on market forces affecting supply and demand for materials and labor. 

In addition to equipment costs, the operating cost component is also well known by region and well 

characteristics. 
Technology and Cost Document 

for the final GS Rule 53 November 2010 

Well remediation unit costs are known through conventional oil and gas field development as well 

as through underground injection and EOR projects. 

The costs of specialty cements and corrosion resistant tubulars are known to industry, although 

there is uncertainty as where this will apply and how much impact it will have. 

Uncertainty on a unit cost basis for specific technologies is larger with site characterization and 

monitoring technologies that are not generally used in the oil and gas industry or rarely used. 

Factors include a general paucity of data in the literature, the fact that GS technologies are in an 

early stage of development and are not commercially deployed and because companies do not 

publicize such individual unit costs due to competitive factors. In addition, the service companies 

package these technologies and tailor them to specific projects. EPA has obtained useful 

information from the literature and from a UIC Technology Conference in New Orleans 77 for the 

basis of unit costs such as eddy covariance, geochemical testing, and tracer injection. In addition, 

unit cost input has been received from the Department of Energy, public comment on the rule, and 

other sources. The specific unit costs of monitoring equipment, for example, do affect the cost 

analysis, but since the overall uncertainty includes how often and how much the technology is 

applied, the impact of this uncertainty is expected to be minimal. 

It is important to note that the cost of drilling and completing injection and monitoring wells 

represents a large component of sequestration costs, and these costs are relatively well known. 

Number of Hours and Hourly Rates

Several of the cost categories described in this document are labor intensive projects requiring 

many hours of time at relatively high labor rates. Due to the expected large variability in projects, it 

is difficult to estimate the number of hours required for activities such as geological site 

characterization. The hours required for such analysis are estimates, while the labor rates are 

generally known. Uncertainty in labor rates involves the level of technical expertise required and 

other factors such as whether the work will be done in-house by employees or contracted out. 

Fluctuation in Unit Costs over Time

A significant element of uncertainty is associated with potential changes in technology or labor 

costs through time. As listed above, these may relate to improved technology, changes in the 

experience of the technical workforce, better understanding of what information is needed and what 

activities should be implemented, and general labor cost changes. 

For example, sequestration projects initiated over the next decade or so may incur higher labor 

costs than those deployed further into the future, due to a shortage of experienced technical staff 

that specializes in injection operations. As more projects become operational and the technology 

more developed, costs may decline due to better knowledge and more efficient site 

characterization, operation, and monitoring approaches.

 

77 Joint GWPC/EPA CO2 MMV meeting, New Orleans, LA January 16, 2008. 
Technology and Cost Document 

for the final GS Rule 54 November 2010 

Overall Cost Analysis Uncertainty 

Chapter 5 of the Cost Analysis78 discusses uncertainty related to the overall cost analysis. Briefly, 

EPA used best professional judgment in determining the characteristics of the pro forma projects 

developed to represent baseline projects for saline and ER sites, the schedule of cost incurrence 

throughout the period of analysis, and the applicability of each unit cost under each regulatory 

alternative considered. 

Various sources in the literature informed development of the pro forma site characteristics and the 

number of monitoring stations and frequency of monitoring. However, industry has not yet reached 

consensus on issues such as the appropriate number of monitoring wells for a GS project. 

 

78 Cost Analysis for the Final GS Rule, EPA 816-R-10-013. 
Technology and Cost Document 

for the final GS Rule 55 November 2010 

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