svEPA
   United States
   Environmental Protection
   Agency
Geologic CO2 Sequestration Technology and Cost
Analysis
TECHNICAL SUPPORT DOCUMENT
June 2008

-------
Office of Water (4604M)
EPA816-B-08-009
www.epa.gov/safewater
June 2008

-------
                                     Table of Contents
1    INTRODUCTION	1

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

  2.1    COSTING METHODOLOGY	3
  2.2    PRIMARY DATA SOURCES FOR COSTS	3
  2.3    COST YEAR BASIS AND TRENDS IN MAJOR COSTS	4

3    TECHNOLOGIES AND COSTS	7

  3.1    GEOLOGIC SITE CHARACTERIZATION	7
     Maps and Cross Sections	7
     Seismic Surveys	7
     Seismic History	8
     Remote Land Survey	8
     Data on Extent, Thickness, Capacity, Porosity of Receiving Formations	8
     Geomechanical Information	8
     Potentially Affected Underground Sources of Drinking Water (USDWs)	9
     Geochemical and Other Information on Formations	9
     Information on Water-Rock Geochemistry	9
     List of Penetrations of Injection Zone	9
     List of Penetrations of Containment System	9
     List of Water Wells within Area of Review	9
     Geologic Characterization Report	10
     Geologic Site  Characterization  Unit Costs	10
  3.2    MONITORING	12
     Fluid Geochemical Analysis	12
     Surface CO2 and Soil Flux Baseline	13
     Gravity Data	14
     Topographic Information	14
     Front-End Engineering and Design	15
     Rights of Way for Surface Use	15
     Downhole Safety Valve	16
     Standard Monitoring Well Costs	16
     Pressure and Temperature Gauges and Equipment for Monitoring Wells	16
     Salinity and Other Monitoring Equipment	17
     Surface Monitoring Program	17
     Surface Microseismic Equipment	17
     Monitoring Well O&M Costs	17
     Annual Costs of Air and Soil Surveys	18
     Annual Cost of Passive Seismic Surveys	18
     Periodic Seismic Surveys	18
     Fluid Flow Calculations and Modeling	19
     Reports to Regulators	20
     Monitoring Unit Costs	20
  3.3    INJECTION WELL CONSTRUCTION	22
     Rights of Way for Surface and Subsurface Uses	22
     Land Use, Air Emissions, and Water Permits	22
     UIC Permit Filing	22
     Standard Injection Well Cost	22
     Corrosion Resistant Tubing and Casing	23
     Well Cementing	24
     Pumps and Wellhead Control Equipment	25
                                                                                                  ill

-------
    Pipeline Costs	26
    Injection Well Construction Unit Costs	26
  3.4     AREA OF REVIEW STUDY AND CORRECTIVE ACTION	27
    Complex Modeling of Fluid Flow	27
    Physical Survey to Find Old Wells	27
    Mechanical Integrity of Old Wells	27
    Remediate Old Wells in Area of Review	28
    Area of Review and Corrective Action Unit Costs	29
  3.5     WELL OPERATION	29
    Corrosion Monitoring and Prevention	30
    Measuring and Monitoring Equipment	30
    Equipment to Add Tracers	30
    Electricity Costs for Pumps and Equipment	30
    Injection Well Operating and Maintenance Costs	30
    Land Use Rents and Right of Way	30
    Pore Space Unit Costs	30
    Property Taxes and Insurance	30
    Tracers in Injected Fluid	31
    Contribution to Long Term Monitoring, Insurance, and Remediation	31
    Repair or Replace Wells and Equipment.	32
    General Failure of Containment Site	32
    Well Operation Unit Costs	32
  3.6     MECHANICAL INTEGRITY TESTS	33
    Mechanical Integrity Pressure Tests	33
    Internal Mechanical Integrity	33
    Radioactive Tracer Survey of Cement	33
    External Mechanical Integrity Test	33
    Pressure Falloff Tests	34
    Mechanical Integrity Test Unit Costs	34
  3.7     POST-INJECTION WELL PLUGGING, EQUIPMENT REMOVAL, AND SITE CARE	35
    Plug Injection Wells	35
    Plug Monitoring Wells	35
    Remove Surface Equipment	35
    Document Plugging and Post-Injection Process	35
    Post-Injection Monitoring Well O&M.	35
    Post-Injection Air and Soil Surveys	35
    Post- Injection Seismic Surveys	35
    Post- Injection Reports to Regulators	36
    Post-Injection Well Plugging, Equipment Removal, and Site Care Unit Costs	36
  3.8     FINANCIAL RESPONSIBILITY	36
    Performance Bond or Demonstration of Financial Ability for Well Plugging	37
    Performance Bond or Demonstration of Financial Ability for Post-Injection Site Care Period	37
    Financial Responsibility Unit Costs	37
  3.9     GENERAL AND ADMINISTRATIVE COSTS	37

4   CHARACTERISTICS OF EXAMPLE PROJECTS FOR COSTING	39

  4.1     INTRODUCTION	39
  4.2     LAWRENCE BERKELEY STUDY	39
  4.3     REGIONAL DOE PARTNERSHIP PILOT PROJECTS AND FUTUREGEN	40
  4.4     PROJECT CHARACTERISTICS - SALINE RESERVOIR (COMMERCIAL SCALE)	43
  4.5     PROJECT CHARACTERISTICS - DEPLETED GAS RESERVOIR (COMMERCIAL SCALE)	45
  4.6     CURRENT PROJECT CHARACTERISTICS - DEPLETED OIL RESERVOIR (COMMERCIAL SCALE)	49
  4.7     PILOT SCALE EXAMPLE PROJECTS	50

5   UNCERTAINTIES IN ANALYSIS	51
                                                                                                  IV

-------
6   BIBLIOGRAPHY	53

APPENDIX A- CHARACTERISTICS OF PILOT SCALE EXAMPLE PROJECTS	56
                                      List of Tables
Table 1: Major Sources of Geologic Sequestration Cost Information	4
Table 2: Geologic Site Characterization Unit Costs	11
Table 3: Monitoring Unit Costs	21
Table 4: Injection Well Construction Unit Costs	26
Table 5: Area of Review and Corrective Action Unit Costs	29
Table 6: Well Operation Unit Costs	32
Table 7: Mechanical Integrity Tests Unit Costs	34
Table 8: Post-Injection Well Plugging, Equipment Removal, and Site Care Unit Costs	36
Table 9: Financial Responsibility Unit Costs	37
Table 10: General and Administrative Unit Costs	37
Table 11: Lawrence Berkeley Study Parameters for Their Economic Analysis	40
Table 12: DOE CO2 Sequestration Pilot Projects (DOE Phase III) and FutureGen Project	41
Table 13: Details of Sequestration Pilot Projects	42
Table 14: Saline Reservoir Type Case Characteristics (Commercial Scale Proj ect)	44
Table 15: Summary of GASIS Reservoir Database Parameters for Depleted Gas Reservoir and Depleted Oil
Reservoir Example Cases	46
Table 16: Depleted Gas Reservoir Type Case Characteristics (Commercial Scale Project)	47
Table 17: Depleted Oil Reservoir Type Case Characteristics (Commercial Scale Project)	49
                                     List of Figures

Figure 1: U.S. Carbon Steel Plate Prices	5
Figure 2: Nickel Prices	5
Figure 3: Gas Pipeline Costs by Component	6
Figure 4: U.S. Drilling Rig Day Rates	6
Figure 5: Diagram of Typical CO2 Injection Wellhead	25

-------
                                     Acknowledgements
This document was prepared by ICF International under a contract with the Office of Air and Radiation to
support EPA's proposed rule-making, Federal Requirements Under the Underground Injection Control
(UIC) Program for Carbon Dioxide (CCh) Geologic Sequestration (GS) Wells.
                                                                                          VI

-------
  1      Introduction

The Environmental Protection Agency is developing a set of regulatory alternatives for the geological
sequestration (GS) of carbon dioxide. EPA's rule, which will be part of EPA's Underground Injection
Control regulations, will provide federal requirements for owners and operators of sequestration operations.
It is intended to protect underground sources of drinking water and provide regulatory certainty and
permitting consistency for industry.

This Technology and Cost (T&C) Document describes the costs of specific technologies and operating
practices that could be applied to underground geologic  sequestration of CO2. The costs are estimated for
specific technologies, and then are applied to examples of saline reservoirs, depleted gas reservoirs, and
depleted oil reservoirs to estimate total project costs. Examples are provided for both "commercial scale"
and "pilot scale" geologic sequestration projects.

While characteristics vary according to geologic site characteristics, for the purposes of this  analysis we
have developed examples that are representative of different types of geologic sites.  The "commercial
scale" examples represent typical geologic conditions for sequestration and are based upon sequestering the
CO2 emissions from a 275 MW power plant with an injection period for each sequestration site of 20 years.
The "pilot scale" examples are smaller in scale and have characteristics similar to what is planned by the
Department of Energy at several  sites around the U.S.

In a separate Cost Analysis document prepared for this study, the cost of a base case and four proposed
regulatory alternatives is evaluated. This is accomplished through the development of specifications for
which technologies or technology categories are required by each regulatory  alternative. Base case costs  are
assumed to be the costs incurred under the current Underground Injection Control regulations for Class I
non-hazardous waste injection.

The cost elements described in this document are either  attributable to Class I non-hazardous projects, or  are
under consideration in the regulatory alternatives. It should be emphasized that this document includes all
cost elements for GS, not just those costs that incurred only under the new rule.  Some of the cost elements
described here are attributable to regulatory  options 1 through 4, but some costs are baseline costs that
would be incurred anyway under Class 1 non-hazardous waste rules.

Only the geologic sequestration component (including pre-injection, injection, and post injection) of the
overall capture, transport, and storage system is evaluated here. Excluded are carbon capture and CO2
transportation to the sequestration site. The sequestration component is expected to be only  a fraction of the
total cost of an integrated capture and sequestration project, typically in the range of 10 to 20 percent.

The major areas covered by the cost study include geologic characterization of the injection  site, well
construction and operation, monitoring during operations, post-injection operations, and financial
responsibility. Specific costs  are developed for site characterization, remediation of existing wells, land
permitting, drilling and equipping wells, installation of monitoring equipment, operating costs, and
monitoring.

-------
CO2 sequestration can take place in seven reservoir or operational settings:

              Saline reservoirs (non-basalt)
              Depleted and abandoned gas fields
              Depleted and abandoned oil fields
              Enhanced oil recovery (EOR) conversion to sequestration
              Enhanced coal-bed methane recovery
              Enhanced shale gas recovery
              Basalt reservoirs

Various studies of the CO2 sequestration capacity of the U.S. have documented that it is dominated by non-
basalt saline reservoirs, typically in sandstone lithologies. This study develops cost information for the three
following settings:

              Saline reservoirs (non-basalt)
              Depleted and abandoned gas fields
              Depleted and abandoned oil fields

Saline reservoirs are expected to represent the great majority of long-term storage, due to their assessed
potential and other factors, including location, availability, access, and injectability. : Large regions of the
U.S. are underlain by saline-bearing reservoirs extending to depths of 10,000 - 20,000 feet. These
formations contain total dissolved solid concentrations of greater than 10,000 mg/ML, differentiating them
from underground drinking water sources.

Depleted gas reservoirs and depleted oil reservoirs represent a small percentage of currently assessed U.S.
storage capacity.  However it is considered important to characterize costs in such "conversion" scenarios
because these costs may vary significantly from those of saline reservoir development.  In addition, some
depleted oil and depleted gas fields also will likely be considered good candidates for sequestration because
they have proven traps and seals and a great deal of existing subsurface data. These types of settings  have
also been used extensively for methane gas  injection and storage. It is anticipated that depleted oil and gas
reservoirs will be a focus of early GS projects due to existing operational experience with these formations.

Three other potential geologic settings presented above are not covered by the proposed regulations and are
not included in the cost study.  These are:

              Enhanced oil recovery (EOR)
              Enhanced coalbed methane recovery
              Enhanced shale gas recovery

Because these settings represent CO2 injection to increase recovery of oil and gas, they are already covered
under the EPA Class II injection well designation. An exception is the conversion of and existing EOR
operation to only sequestration. In such a case, the new rule would apply. The basalt setting is not included
here in the cost examples because its role in sequestration over the forecast period is expected to be very
minor.
1 U.S. Department of Energy, 2007, "Carbon Sequestration Atlas of the United States and Canada," DOE/NETL.
March, 2007, http://www.netl.doe.gov

-------
         General Costing Methodology, Data Sources, and Cost Trends
                  2.1   Costing Methodology

This report evaluates the costs for geologic sequestration. All of the individual cost components
are evaluated.  These are termed unit costs and include the following categories:

              Geologic Site Characterization
              Monitoring
              Injection Well Construction
              Area of Review and Corrective Action
              Well Operation
              Mechanical Integrity Tests
              Post Injection Well Plugging and Site Care
              Financial Responsibility
              General  and Administrative

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 type cases in a separate study to
estimate total project costs.  The type cases  include specifications for total area, depth, thickness, well
injectivity, number of wells through time, and other parameters.

In the separate Cost Analysis report, costs are estimated for a base case and the four proposed regulatory
alternatives. Each cost item has been evaluated as to whether it is included in the regulatory option, and
whether the cost would 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 scenario 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 cost
components examined in this report are attributable to a particular regulatory alternative.

                  2.2   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 U.S. and Canada. 2 3 4 5The cost of
2 Joint Association Survey of Drilling Costs, American Petroleum Institute, Washington, DC.
http://www.api.org/statistics/accessapi/api-reports.cfm

3 PSAC Well Cost Study - 2008, Petroleum Services Association of Canada, October 30, 2007.

4 Oil and Gas Lease Equipment and Operating Costs, U.S. Energy Information Administration, 2006,
http://www.eia. doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/coststu
dv.html
5 Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September 3, 2007.

-------
drilling and equipping wells represents a large component of sequestration 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.  The number of hours required to carry
out the various characterization or monitoring activities are  ICF estimates that have been reviewed by the
EPA workgroup.

No comprehensive source has been identified that provides  detailed summaries of the full range of
sequestration 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 a recent industry meeting sponsored by the Groundwater Protection Council.6
                  Table 1: Major Sources of Geologic Sequestration Cost Information
Source	Cost Categories	

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

2008 Petroleum Services of Canada Well Cost Study (PSAC)       Drilling costs, plugging costs, logging costs

Oil and Gas Journal Report on Pipeline and Cost Data
Reported to FERC                                       Pipeline costs per inch-mile

Land Rig Newsletter                                      Onshore rig day rates/ well cost algorithms

New Orleans Sequestration Technology Meeting, January, 2008     Monitor station costs in several categories; seismic costs

FutureGen Sequestration Site Submittals                      Monitoring station layout/number of stations

Preston Pipe Report                                      Casing and tubing costs

Hourly Labor Rates                                      U.S. Bureau of Labor Statistics

Selected Presentations and Papers (see below)                 Sensor costs, monitoring costs, number of stations, seismic costs

Significant Papers and Presentations With Cost Data	
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.


                    2.3   Cost Year Basis and Trends in  Major Costs


The costs reported here represent price levels in late 2007 and early 2008 in the U.S.  and are presented in
2007 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
 ' Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008.

-------
cryogenic applications such as LNG liquefaction plants and LNG storage tanks). 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 report.

                                 Figure 1: U.S. Carbon Steel Plate Prices
             $900 -,
             $800
             $700
             $600
             $500
             $400
             $200
             $100
             $300
                   ,   X        .           .   N                   .
                  ^  ^ oc ^ ^  ^ d3 ^ ^ ^ d3  ^ ^  ^ o* ^ Vs  ^ o*  ^ 
-------
                    Figure 3: Gas Pipeline Costs by Component
Source: Oil and Gas Journal annual surveys; Average of large-diameter gas pipelines 30 to 36 inches; Miscellaneous
category includes surveys, engineering, administration, interest, and overhead.
                        Figure 4: U.S. Drilling Rig Day Rates
c-i4 nnn

nc-in nnn
o
<5
(/)
(5



-------
         Technologies and Costs
                   3.1   Geologic Site Characterization

The purpose of site characterization is to determine whether a site is suitable and safe for sequestration, and
to compile the necessary data for the permit application. The process includes geologic, geophysical, and
engineering evaluation. Characterization is designed to provide the geologic and hydrologic data needed to
design the infrastructure, develop reservoir models, and design the monitoring program. In this phase of
site development, a determination is made of whether the reservoir has adequate porosity, permeability, and
continuity for long term injection.  A  determination is also made about the ability of overlying units to
confine the injected CO2 and prevent  vertical movement.  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 reservoir and overlying strata.

Maps and Cross Sections

The basic element of geologic analysis and characterization is the development of regional and site-specific
geologic maps and cross sections to provide an understanding of stratigraphy and structure.  The primary
source of data for this analysis is well log data, which allows the geologist to map the depth to various
formation tops, thickness variations (isopach maps), and lithologies (sand, 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 may
be acquired either on the surface, which is typical, or in a well. Borehole techniques require one or more
wells for source or receivers. Surface seismic data may be either 2-dimensional (2-D) or 3-dimentional (3-
D), with the latter being much more data intensive and  costly to obtain and interpret, but providing a higher
degree of resolution. Seismic data may be used also for monitoring during operations and post-injection.7

3-D seismic uses man-made source signals and a receiver array to image the subsurface. In the site
characterization phase, 3-D may be used to evaluate the detailed structural geology and stratigraphy of the
site.  Seismic data may in some  settings allow the imaging of CO2 in the reservoir since CO2 is less dense
than formation water, resulting in an acoustic contrast and seismic signature. When 3-D surveys are
conducted periodically, a time-lapse analysis can be conducted (termed 4-D seismic).
7 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006.

-------
3-D seismic data may be used in the site characterization phase as input into reservoir models to estimate the
volume of CO2 that can be stored at a potential site. 8  The technology is mature and has been used in the oil
and gas exploration and development for decades.
Seismic History

The natural long-term seismic history of a potential sequestration site may be evaluated to gain a picture of
potential failure risks. Historic data on seismic activity can be obtained from the U.S. Geological Survey.
Evaluation would 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 should be carried out to  locate and identify dwellings and other
manmade structures affected within the area of review. The size of the survey should be such that it covers
an area significantly larger than the expected ultimate dimensions of the subsurface plume and pressure
front.

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 reservoir interval.  In order to develop the analysis, it is necessary to
obtain regional well log, well history, pressure test, and other subsurface data. Included is the acquisition of
core data, drill stem test data, production test data,  and other engineering data on area wells. The geologist
uses this information to map the thickness, structure, and reservoir characteristics in the subsurface. The
goal is to fully evaluate storage capacity and injectability, and the expected variability in these parameters.
Some sites, such as abandoned  oil or gas fields, will have a large amount of subsurface data in a specific
area.  In saline reservoirs, 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 reservoir or seal
rock, resulting in fracturing  and potential leakage that may endanger USDWs. 9  10 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
8 Doughty, Christine, Barry Freifeld, and Robert Trautz, 2007, "Site Characterization for CO2 Geologic Storage,"
Environmental Geology, vol. 54, no. 8, June 2008.

9IPCC, 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.

10 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.

-------
include well logs, seismic, pressure leak-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 would determine the distribution and depth of all potentially affected USDWs.

Geochemical and Other Information on Formations

In addition to determining the distribution of USDWs at the proposed site, it is desirable to obtain data on
water properties of regional formations, as well as an overall understanding of their regional thickness and
structure.

Information on  Water-Rock Geochemistry

The geochemistry of subsurface fluids can affect whether a site is suitable for sequestration. Injection of
CO2 can result in the presence of carbonic acid, which may react with reservoir 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.

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 sequestration uneconomic.

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.

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
reservoir.  These wells could also represent potential leakage pathways.

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.

-------
Geologic Characterization Report

Approval of a specific site for sequestration 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 will 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.
                                                                                                  10

-------
Table 2: Geologic Site Characterization Unit Costs
Cost Reporting
Heading
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Geologic Site
Characterization
Unit Cost Heading
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Tracking
Number
A-1
A-2
A- 3
A-4
A-5
A-6
A-7
A- 8
A-9
A-10
A-11
A-1 2
A-1 3
A-1 4
Cost Item
Develop maps and cross sections of local geologic structure
Conduct 3D seismic survey to identify faults and fractures in
primary and secondary containment units
Obtain and analyze seismic (earthquake) history.
Remote (aerial) survey of land, land uses, structures etc.
Obtain data on areal extent, thickness, capacity, porosty and
permeability of receiving formations and confining systems
Obtain geomechanical information on fractures, stress, rock
strength, in situ fluid pressures (from existing data and
literature)
Obtain geomechanical information on fractures, stress, rock
strength, in situ fluid pressures (new cores and tests)
List names and depth of all potentially affected USDWs
Provide geochemical information and maps/cross section on
subsurface aquifers.
Provide information on water-rock-CO2 geochemistry and
mineral reactions.
Develop list of penetrations into injection zone within AoR
(from well history data bases)
Develop list of penetrations into containment systems within
AoR (from well history data bases)
Develop list of water wells within AoR (from public data)
Prepare geologic characterization report demonstrating:
suitability of receiving zone, storage capacity and injectivity,
trapping mechanism free of nonsealing faults, competent
confining system, etc.
Cost Algorithm
60 hours of geologists @$1 06.31 /hr =
$6379 per site
375,000/square mile for good
resolution
60 hours of geologists @$1 06.31 /hr =
$6379 per site
$3,000/site + $400/square mile
surveyed. (Should assume survey is
twice project's actual footprint.)
24 hours of geologists @$1 06.31 /hr =
$2551 per site
120 hours of geologists @$1 06. 31/hr =
$12757 per site
$75/foot for stratigraphic test well +
$3,000/core
24 hours of geologists @$1 06.31 /hr =
$2551 per site
60 hours of geologists @$1 06.31 /hr =
$6379 per site
240 hours of geologists @$1 06. 31/hr
+$10,000 labefees = $35514 per site
12 hours @$106.31/hr= $1276 per
square mile
12 hours @$106.31/hr= $1276 per
square mile
36 hours @$106. 31/hr = $3827 per
square mile
240 hours of geologists @$1 06. 31/hr =
$25514 per site
Data Sources
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
Several published reports are in range of
this cost. Estimates givwn at N.O. meeting
were $15,000 to $30,000 per square
kilometer ($39,000 to $78,000 per square
mile).
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
Advertised cost of an aerial survey
company for high-resolution (1/2 meter).
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
Drilling cost is estimated fom drilling cost
equations developed from JAS and PSAC
data. Core analysis cost is a placeholder
until more data are obtained.
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
ICF estimate of time required. Lab fee is a
placeholder until more data are obtained.
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
Cost expected to vary widely based on well
ages and quality of record keeping.
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
Cost expected to vary widely based on well
ages and quality of record keeping.
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
Cost expected to vary widely based on well
ages and quality of record keeping.
ICF estimate of time required. Hourly rate
m ay change based on labor survey data.
                                                                     11

-------
                   3.2   Monitoring

Once injection begins, a program for monitoring of CO2 distribution is required. n  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 reservoir models
              Provide early warnings of failure

Monitoring components may include the following12:
              Measurements to determine the mass of CO2 injected, principally derived from the fluid
               pressure, temperature, flow rate and gas composition at the wellhead
              Monitoring of pressure during the injection process
              Monitoring of the migration and distribution of the CO2 in the deep subsurface, focusing on
               the intended storage reservoir, but including any unintended migration out of the storage
               reservoir
              Monitoring of the shallow subsurface to detect and quantify any CO2 migrating out of the
               storage reservoir towards the ground surface
              Monitoring of the ground surface and atmosphere to detect and quantify CO2 leaking into
               the biosphere

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.

Fluid Geochemical Analysis

Prior to injection of CO2, it may be necessary to develop a baseline of geochemical properties and
characteristics of reservoir fluids in the injection zones, confining zones, and groundwater. 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, N2), carbonate, and total
alkalinity, metals (Na, K, Ca), salinity, and stable isotopes (C, O). 13 14

Downhole fluid samples can be collected for surface  analysis using wireline formation testers and U-Tubes.
The Schlumberger Modular Formation Dynamics Tester (MDT) is a wireline tool that is used to collect
11  The Future of Coal, Options for a Carbon-constrained World, An Interdisciplinary MIT Study, Massachusetts
Institute of Technology, 2007.
12  Discussion Paper: Identifying Gaps in CO 2 Monitoring and Verification of Storage, by B. Reynen, M. Wilson, N.
Riley, T. Manai, O. M. Mathiassen, and S. Holloway, A Task Force under the Technical Group of the Carbon
Sequestration Leadership Fora, (CSLF), Paper No. CSLF-T-2005-3, Presented at the Technical Group Meeting, April
30, 2005.
13 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006.
14 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide, S. Benson and L. Myer,
Lawrence Berkeley Laboratory, Berkeley, California, 2002.


                                                                                                  12

-------
multiple subsurface samples at formation pressure and temperature (PVT samples) for surface analysis.15
U-Tube technology was developed for the DOE Frio Brine project and allows sample extraction at reservoir
pressure and temperature. 16  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 may be 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 zone 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. Discreet
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. 1?

Standard sampling and analysis is done by personnel at the wellsite. There is the possibility of continuous
automated monitoring of geochemical data using downhole sensors.  Although downhole pH sensors for
wells exist, additional R&D is needed in this area.  Thus, geochemical data acquisition will generally rely
upon surface testing of water samples.

Surface CO2  and Soil Flux Baseline

Direct measurement and testing of CO2 concentrations above a sequestration 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). 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, soil gas sampling with ground-surface accumulation chambers,
and direct vadose zone sampling using subsurface probes.

Eddy Covariance is used to measure CO2 concentration in the air above a sequestration 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
15 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1,
2006.

16 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).

17 Technology Status Review -Monitoring Technologies for the Geological Storage ofCO2, 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.
                                                                                                13

-------
data.18 19 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 sequestration site provides information regardless of wind
direction.

Surface CO2 flux monitoring is used to measure the amount of CO2 moving across the earth's surface and is
used as a leak detection technology. Surface flux is measured using an accumulation chamber. One type of
accumulation chamber is made of stainless steel and is placed at the sample location. In some cases, pits are
dug and are used for accumulation. Samples are taken from the air inside the chamber and are analyzed in
the laboratory. If CO2 is the only sample of interest, an open path infrared analyzer can be used. However,
additional analysis is needed to detect tracers  and other chemicals. 20

Vadose zone sampling and monitoring can be carried out using one-inch diameter probes. Samples are
collected with a vacuum pump and are evaluated at the surface for CO2 content.  Correct installation would
allow sampling at various depths in the vadose zone. 21

Gravity Data

Gravity surveys measure subsurface density contrasts. Such contrasts may result from structure, lithology, or
pore content. During injection, a density  contrast change through time may occur where CO2 moves into
pore space previously occupied by water.  Thus, in some cases gravity data can be used to monitor plume
movement.

Surface gravity data are obtained through  a survey with measurement stations spaced a uniform distance
apart across an area. Gravity data may also be taken from the air.  A baseline gravity survey may be carried
out above a planned sequestration site to establish pre-injection conditions. The ability of gravity to detect
and map CO2 movement is much less precise  than that of seismic. It has been estimated that a minimum of
several hundred thousand tons of CO2 would be injected before a significant effect was observed. 22  This
volume of CO2 would be an order of magnitude greater than the detection limits of seismic.

Establishment of a gravity baseline is not included in the cost analysis because of uncertainty that it would
be used in monitoring.

Topographic Information

One method of monitoring an injection site is to evaluate ground surface distortion through time.
Underground injection can cause measurable  surface distortion over time due to volumetric effects. The
overall approach is to establish a baseline  prior to injection, and then use various techniques to monitor
deformation after injection begins.  A space-borne geodetic tool called INSAR (Interferometric Synthetic
18 Technology Status Review -Monitoring Technologies for the Geological Storage ofCO2, 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.
19 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide, S. Benson and L. Myer,
Lawrence Berkeley Laboratory, Berkeley, California, 2002.
20 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1,
2006.
21 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1,
2006.
22/PCC,ibid.
                                                                                                 14

-------
Aperture Radar) allows development of a detailed spatial picture of land topography. When combined with
surface and downhole tiltmeters, there is the potential to monitor extremely small topographic changes over
time during injection. 23 24

Tiltmeters are instruments that measure very minute changes in the land surface, with detection limits of
micro-or nano-radians. The sensors themselves are installed in shallow boreholes, typically less than 10
meters in depth because they are sensitive to temperature changes. 25  The shallow boreholes are arrayed
around the injector wells and are installed prior to injection as part of the baseline topographic analysis.

As with gravity methods, topographic distortion methods have much lower resolution that seismic, in terms
of plume monitoring, despite the extreme accuracy of the surface measurement.  A greater depth of injection
would result in less resolution, due to much smaller surface movement. Topographic detection methods are
only applicable in areas where natural variations are not present.  Natural movement can result from frost
heave or surface water conditions. These technologies are relatively new, although they have been used for
groundwater investigation.

Establishment of a topographic baseline is not included in the cost analysis because of uncertainty that it
would be used in monitoring.

Front-End Engineering and Design

This encompasses front-end engineering and design of the project.  Included are site layout  and engineering
design of surface structures, piping, and pumping equipment. It also includes injection well design,
monitoring well design, the drilling plan, casing plan, wellhead equipment design, downhole equipment
selection, and monitoring equipment selection.

Rights of Way for Surface Use

It will be necessary to obtain rights of way for surface use to set up and operate monitoring  facilities. An
example of such a monitoring site would be an eddy covariance station.
23 Monitoring of Sequestered CO2: Meeting the Challenge with Emergng Geophysical Technologies, S.N. Dasgupta,
Saudi Aramco, 2005.

24 CO2 Storage in Saline Aquifers, by M. Bentham and G. Kirby, Oil and Gas Science and Technology, vol. 60, no. 3,
2005.

25 Measurement, Monitoring, and Verification, L. H. Spangler, Zero Emission Research and Technology Center,
Carbon Sequestration Leadership Forum, date unknown.
                                                                                                 15

-------
Downhole Safety Valve

Injection wells may be equipped with one or two well control valves, one at the surface and an optimal
second one in the tubing string down hole. 26 The downhole safety valve can be installed to automatically
shut in the well if surface equipment fails so that no surface release occurs and to prevent back flow into
surface facilities.
Standard Monitoring Well Costs

It may be necessary as part of an overall monitoring system to drill and complete one or more monitoring
wells 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: 2?

       Injection Reservoir Monitoring Wells - monitoring wells that are perforated across the injection
        zone.
       Primary Seal 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 reservoir
and a potential increase in leakage risk. Monitoring wells completed in  intervals above the reservoir do not
carry this risk. In the current cost study, it is assumed that monitoring wells are completed just above the
primary seal.

The drilling and completion of CO2 monitoring wells, should they be needed or required represents a large
component of overall monitoring costs. For example, a 5,000 foot well with an average cost  per foot of
$100 would cost $500,000. The overall cost is a function of depth and well design  and characteristics.
Pressure and Temperature Gauges and Equipment for Monitoring Wells

Monitoring wells may have permanently installed downhole equipment to continuously measure pressure,
temperature, resistivity, salinity, and pH. Measurements of subsurface pressure are routine in oil and gas
field operations. 28  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
26IPCC, 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
27 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006.

28  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.
                                                                                                 16

-------
sensors are available. Fiber optic cables from the surface to the formation can provide real-time formation
pressure measurements.

Salinity and Other Monitoring Equipment

Salinity and fluid characteristics may be measured downhole to determine composition and to monitor CO2
movement. Fluid and gas samples can be collected directly from the formation using a U-tube downhole
sampler. 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. 29

At the Texas Frio Brine Pilot Tests, a U-tube downhole sampler was used to collect high-frequency samples
at the monitoring well.30 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.

Surface Monitoring Program

Surface and near surface monitoring equipment includes CO2 concentration equipment for air or soil
sampling and microseismic equipment for monitoring plume movement.  Some surface monitoring
technologies require specific equipment be installed. Most surface monitoring costs will be non-equipment
or labor costs to conduct the surveys and analyze the data. The actual monitoring costs are described in
section 3.10.

The proposed regulations for sequestration include varying specifications for surface and near surface
monitoring. It may be necessary to implement a monitoring program that includes not only the expected
plume area but also the monitoring of all wells within the area of review and other sensitive areas such as
buildings to ensure that CO2 has not migrated in this manner.

The surface monitoring program of each site is customized for the geologic, engineering, and surface
characteristics of the site.

Surface Microseismic Equipment

Microseismic sensors are used to continuously detect the microseismic activity that may be associated with
injection and movement of CO2. Such a monitoring array includes both surface  and subsurface equipment.
The subsurface component is installed in monitoring wells.

Monitoring Well O&M Costs

This includes the annual costs of operating and maintaining the monitoring wells including operating labor
and system maintenance.
29  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.

30  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.


                                                                                                17

-------
Annual Costs of Air and Soil Surveys

The annualized cost of air and soil monitoring surveys includes the cost of continuous air sampling using
eddy covariance equipment and soil zone surveys for CO2 and tracers.

Annual Cost of Passive Seismic Surveys

Microseisms are very small earthquakes that are assumed to be caused by the pressure front of the injected
CO2 or other fluids. 31 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 reservoir.32 33 34

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.35

Not all storage reservoirs are amenable to passive seismic methods. Factors that play a role include rock
mechanics, lithology, and natural seismic activity.

Periodic Seismic Surveys

Seismic data are used in the monitoring phase 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 post injection monitoring phase.
36 3D data are much more useful but  are more costly to obtain and interpret than 2D  Both velocity and
amplitude anomalies may result from CO2 movement.

Seismic data 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 may also be used as a seismic source, and the charges
placed in shallow boreholes holes.
31 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1,
2006.
32 Monitoring of Sequestered CO2: Meeting the Challenge with Emerging Geophysical Technologies, S.N. Dasgupta,
Saudi Aramco, 2005.

33 Technology Status Review -Monitoring Technologies for the Geological Storage ofCO2, 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.

34 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.

35 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1,
2006.
36 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1,
2006.
                                                                                                 18

-------
The ability to monitor CO2 in the subsurface using seismic depends upon numerous factors, and not all sites
or reservoir 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) would be less amenable to
seismic monitoring. Some geological settings may preclude the use of seismic because of near surface
factors as well. Near surface factors may include irregular topography, unusual lithologies, surface water,
man made structures or impediments  or other access factors. Where conditions are right, however, it may be
possible to detect injected CO2 volumes of as little as 1,000 tons.37

There are two major subsurface seismic methods for monitoring, Vertical Seismic Profiling and  Cross-Well
Seismic.  Vertical Seismic Profiling (VSP) is a technique in which surface sources are arrayed around a well
that is in close proximity to a CO2 plume.38  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.39  Both wells must penetrate to the base of the storage reservoir
under investigation. This method results in a two-dimensional vertical slice of the subsurface with high
resolution at the reservoir level. The  method has been successfully tested at the  Frio site in Texas.
Fluid Flow Calculations and Modeling

Modeling of subsurface CO2 flow can be used to define the area of review and area within which existing
wells need to be evaluated for possible remediation.  It is 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 reservoir capacity can be estimated with basic
engineering methods. However, complex, numerical methods providing multi-phase and multi-component
reservoir simulations may be used to understand the injection project and its impacts in much greater detail.
40


Different models are needed to analyze the well-bore flow and to simulate the large-scale flow processes in
the reservoir.
37 Technology Status Review -Monitoring Technologies for the Geological Storage ofCO2, 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.

38 Measurement, Monitoring, and Verification, L. H. Spangler, Zero Emission Research and Technology Center,
Carbon Sequestration Leadership Forum, date unknown.

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

40  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.
                                                                                                  19

-------
Reports to Regulators




This includes the labor costs to complete periodic reports to regulatory bodies.




Monitoring Unit Costs




Table 3 specifies the estimated costs and data sources for monitoring.
                                                                                                20

-------
Table 3: Monitoring Unit Costs
Cost Reporting
Heading
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Monitoring
Unit Cost Heading
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Land and Land Use
Rights
Land and Land Use
Rights
Drilling and Equipping
Injection Wells
Drilling and Equipping
Monitoring Wells
Drilling and Equipping
Monitoring Wells
Down hole Monitoring
Equipment (for
Monitoring Wells or
Injection Wells)
Down hole Monitoring
Equipment (for
Monitoring Wells or
Injection Wells)
Surface or Near-
Surface Monitoring
Equipment
Surface or Near-
Surface Monitoring
Equipment
Surface or Near-
Surface Monitoring
Equipment
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Tracking
Number
B-1
B-2
B-3
B-4
B-5
B-6
B-7
B-8
B-9
B-10
B-11
B-12
B-13
B-14
B-15
B-1 6
B-1 7
B-18
B-19
B-20
B-21
Cost Item
Develop geochemical baseline for injection zones and
confining zone.
Develop baseline of surface air CO2 flux for leakage
monitoring.
Conduct front-end engineering and design (monitoring wells)
Obtain rights-of-way for surface uses, (monitoring wells)
Obtain rights-of-way for surface uses, (monitoring sites)
Downhole safety shut-off valve
Standard monitoring well cost (ABOVE injection zone)
Standard monitoring well cost (INTO injection zone)
Pressure and temperature gauges and related equipment for
monitoring wells
Salinity, CO2, tracer, etc. monitoring equipment for wells
(portion of equipment may be at surface such as for in situ
sampling using U-tubes)
Develop plan and implement surface air and/or soil
monitoring within current plume footprint
Develop plan and implement surface air and/or soil
monitoring within current plume footprint, at artificial
penetrations and sensitive locations (human occupancy)
Surface microseismic detection equipment
Monitoring well O&M
Annual cost of air and soil surveys & equipment
Annual cost of passive seismic equipment
Periodic seismic surveys: 3D
Complex modeling of fluid flows and migration (reservior
simulations) every five years
Annual reports to regulators
Quarterly reports to regulators
Monthly reports to regulators
Cost Algorithm
$200 per sample. Assume 4 samples
per injection well = $800 per injection
well
$35,000 per station
$20,000 + $5,000/shallow monitoring
well
$10,000 per monitoring well site
$5,000 per air monitoring station site
(microseismic is done inside montoring
well)
$15,000+ $2/ft depth. Would be
placed 100 or more feet above packer
Use look-up table. $/foot = $100 to
$1 30 per foot typical for slim-hole
design down to 9,000 ft.
Use look-up table. $/foot = $100 to
$1 30 per foot typical for slim-hole
design down to 9,000 ft.
$10,000/well
$10,000/well
40 hours @$106.31/hr= $4252 for
plan plus $70,000/monitoring site
40 hours @$106.31/hr = $4252 for
plan plus $70,000/monitoring site
$50,000/ site (geophone arrays go into
monitoring wells)
Annual O&M costs are $25,000 + $3/ft
per well per year
$10,000 per station per year
$10,000 per station per year
$75,000/square mile for good
resolution
180 hours of engineers @$53.52/hr =
$9634 per site + 24 hours of engineers
@$53.52/hr = $1 284 per injection well
20 hours of engineers @$53.52/hr =
$1070 per report
15 hours of engineers @$53.52/hr =
$803 per report
8 hours of engineers @$53.52/hr =
$428 per report
Data Sources
Lab analysis fee of $1 00 to $200 discussed
in N.O. meeting.
Range of costs discussed at N.O. meeting
Jan 2008 was $20,000 to $50,000 per
station.
ICF estimate.
ICF estimate. Cost of land rights are highly
variable.
ICF estimate. Cost of land rights are highly
variable.
Initial cost estimate until more data are
obtained.
Drilling cost is estimated fom drilling cost
equations developed from JAS and PSAC
data.
Drilling cost is estimated fom drilling cost
equations developed from JAS and PSAC
data.
Initial cost estimate until more data are
obtained.
Initial cost estimate until more data are
obtained.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
Monitoring station cost estimate from
Benson 2004.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
Monitoring station cost estimate from
Benson 2004.
Initial cost estimate until more data are
obtained.
Operating and maintenance costs adapted
From ElAOil and Gas Lease Equipment and
Operating Cost estimates.
ICF estimate.
ICF estimate.
Several published reports are in range of
this cost.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
                                                           21

-------
                   3.3   Injection Well Construction

Rights of Way for Surface and Subsurface Uses

This includes the right of way for surface use for injection and monitoring 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. 41  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
sequestration. While pore space costs are included in the analysis, they are not a part of the new rule.

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.

UIC Permit Filing

This unit cost item covers the estimated labor cost to prepare an Underground Injection Control injection
permit.

Standard Injection Well 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 injection well or a gas storage
well, with the exception that much of the downhole equipment must be upgraded for high pressure and
corrosion resistance. 42 Upgrades may include special casing and tubing, safety valves,  cements, and
blowout preventers.  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.

The injection well typically consists 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. 43  The innermost, deepest casing string is cemented in place across the
storage  reservoir and then perforated to  allow movement of the CO2 into the well.  Then a small diameter
41 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
42 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
43 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1,
2006.
                                                                                                 22

-------
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." The Christmas Tree 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 blowout due to unexpected pressure.  A Supervisory Control and Data
Acquisition (SCADA) is typically used to monitor the data. The system is set up to automatically shut down
the injection if needed.

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. An API report on injection technology lays out a set of
guidelines that were developed.
44
       "Because of the corrosive effects of carbonic acid, H2CC>3, on metal
       components, induced by the alternating water and gas (WAG) injection cycles
       during CCh 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 CCh 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 (continued on next page):
Component
Upstream metering and piping runs
Christmas Tree (Trim)
Valve Packing and Seals
Wellhead (Trim)
Tubing Hangar
Tubing
Materials
316 Stainless Steel (SS)/ Fiberglass
3 16 SS Nickel, Monel
Teflon, Nylon
3 16 SS Nickel, Monel
316SSIncoloy
Glass Reinforced Epoxy (GRE) - lined carbon steel;
IPC carbon steel, Corrosion Resistant Alloys (CRA)
44 Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology, J.P. Meyer,, Contek
Solutions, for the American Petroleum Institute, 2007.
                                                                                             23

-------
Tubing Joint Seals
ON/OFF Tool, Profile Nipple
Packers
Cements and Cement Additives
Seal ring (GRE), Coated threads and collars
Nickel plated wetted parts
Internally coated hardened rubber, etc. Nickel
wetted parts
plated
API cements and/or acid resistant cements
It should also be noted that the nickel content of steel can be varied, with higher nickel content resulting in
more corrosion resistance but higher costs.


Well Cementing


The type of cement that is used in well cementing operations may be subject to chemical reactions in a CO2
injection zone. Thus, it may in some cases be necessary to 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: 45

        "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
                                        O                   J             OO
        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."
45 Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology, J.P. Meyer,, Contek
Solutions, for the American Petroleum Institute, 2007.
                                                                                                24

-------
Pumps and Wellhead Control Equipment


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 and installation of electrical service also adds a cost component.

A diagram of typical injection well wellhead and control equipment is shown in Figure 5. The cost of
injection equipment is a function of capacity. Injection well monitoring equipment are described in the 2007
API report and 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. 46
                        Figure 5: Diagram of Typical CO2 Injection Wellhead

                           Source: 2007 API report (cited on previous page).
                                                      Lubricator
                             Christmas Tree
                               Wellhead
                                                      Master Valves
                                                            CO,,' w<
                                                                 ter Source
                                                           Casing Ar nulas Valves
                                                             BrarJent ead Valve
46 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.
                                                                                                 25

-------
Pipeline Costs

Included in the cost analysis is a CO2 pipeline component of costs. The pipeline costs included here are only
for the immediate sequestration site. Costs to transport the CO2 to the sequestration site 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.

                           Table 4: Injection Well Construction  Unit Costs
Cost Reporting
Heading
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Injection Well
Construction
Unit Cost Heading
Site Selection and
Evaluation
Land and Land Use
Rights
Land and Land Use
Rights
Permitting Costs
Permitting Costs
Drilling and Equipping
Injection Wells
Drilling and Equipping
Injection Wells
Drilling and Equipping
Injection Wells
Drilling and Equipping
Injection Wells
Drilling and Equipping
Injection Wells
Drilling and Equipping
Injection Wells
Drilling and Equipping
Injection Wells
Drilling and Equipping
Injection Wells
Injection Equipment
(pumps, valves,
measurement
equipment)
Injection Equipment
(pumps, valves,
measurement
equipment)
CO2 Pipeline (within
storage facility)
Tracking
Number
C-1
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-11
C-1 2
C-1 3
C-1 4
C-1 5
C-1 6
Cost Item
Conduct front-end engineering and design (general and
injection wells)
Obtain rights-of-way for surface uses, (equipment, injection
wells)
Lease rights for subsurface (pore space) use.
Land use, air emissions, water emissions permits
UIC permit filing
Standard injection well cost
Corrosion resistant tubing
Corrosion resistant casing
Cement entire length of well
Use CO2-resistant cement
Set packer no more than 1 00 ft above highest perforation
Set packer no more than 300 ft above highest perforation
Injection pressure limited to 90% of fracture pressure of
injection formation
Pumps
Wellhead and Control Equipment
All elements of pipeline costs
Cost Algorithm
$200,000/site + $40,000/injection well
$20,000 per injection (pipeline right of
ways included in pipeline costs) Half of
cost is legal fees for developer, other
half is bonus to landowner.
Upfront payment of $50/acre
(additional injection fees under O&M
costs)
$100,000/site + $20,000/square mile
$10,000/site + $5,000/injection well
Use look-up table. $/foot = $21 0 to
$280 per foot typically down to 9, 000
ft.
Additional $1.10/foot length - inch
diameter for glass reinforced epoxy
(GRE) lininq
Additional $1.75/foot length - inch
diameter for corrosion resistant casing
$1.15/foot length - inch diameter
Adds 25% to total cementing costs
Affects tubing length
Affects tubing length
Affects maximum flow of well, number
of wells needed
$1500/HP. Installation of electrical
service adds $20,000 per well site.
Cost per well is $500*(maximum tons
per day injected per well)A0.6
$60,000/inch-mile
Data Sources
ICF estimate.
ICF estimate. Cost of land rights are highly
variable.
ICF estimate. Cost of land rights are highly
variable.
ICF estimate.
ICF estimate.
Drilling cost is estimated fom drilling cost
equations developed from JAS and PSAC
data.
Based on SPE article on economics of GRE
tubing.
PSAC and Preston Pipe Report
Cementing cost based on 2008 PSAC Well
Cost Study.
Initial cost estimate until more data are
obtained.
Assumed to be in standard cost.
Reduces feet of tubing used. Standard
tubing cost based on 2008 PSAC Well Cost
Study.
Due to uncertainty of injectability, this
pressure impact is ignored.
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.
Based on 2008 PSAC Well Cost Study.
From pipeline cost data reported to FERC.
Publised annually in Oil and Gas Journal.
                                                                                                  26

-------
                   3.4   Area of Review Study 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 can be extremely involved using sophisticated numerical reservoir
simulation models. It was determined that two basic types of analysis should be included in the cost
analysis:, one a simple approach using basic reservoir parameters, and the other based upon advanced
reservoir simulation.

This cost element is for a simple flow calculation that would provide basic information on subsurface CO2
movement.


Complex Modeling of 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.

Physical Survey to Find Old Wells

This cost item involves a method in which an airborne magnetic survey is carried out using a helicopter
which flies over the area of review to detect well casings from all cased wells. This may turn up 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.

Mechanical Integrity of Old Wells

Existing wells at a planned sequestration 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 sequestration. The
wells that are most critical in this analysis are those that penetrate the proposed injection reservoir and
confining zone units. Factors that must be evaluated include the condition of the cement and overall well
maintenance. 4? 48
47IPCC, 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.
48 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.
                                                                                                 27

-------
A description of the process of evaluating and remediating old wells is provided by Meyer in a recent report
published by API: 49

        "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."
Remediate Old Wells in Area of Review

It may be necessary to remediate existing wells at a potential sequestration 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 reservoirs, there may be few, if any, existing wellbores. However, with old abandoned
oil and gas fields, remediation costs may be significant, especially with old wells.

With some marginally deficient wells, it may be determined that a monitoring program alone may be
acceptable, rather than remediation.  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.50
49 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)
50 EPA workgroup, January, 2008.
                                                                                                28

-------
Area of Review and Corrective Action Unit Costs

Table 5 specifies the estimated costs and data sources for area of review and corrective action.
                     Table 5: Area of Review and Corrective Action Unit Costs
Cost Reporting
Heading
AoR Study &
Corrective Action
AoR Study &
Corrective Action
AoR Study &
Corrective Action
AoR Study &
Corrective Action
AoR Study &
Corrective Action
AoR Study &
Corrective Action
AoR Study &
Corrective Action
AoR Study &
Corrective Action
Unit Cost Heading
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Site Selection and
Evaluation
Construction Site
Remediation (Old
Wells)
Construction Site
Remediation (Old
Wells)
Tracking
Number
D-1
D-2
D-3
D-4
D-5
D-6
D-7
D-8
Cost Item
Simple fluid flow calculations to predict CO2 fluid flow.
Complex modeling of CO2 fluid flows and migration (reservoir
simulations) over 100 years
Complex modeling of CO2 fluid flows and migration (reservoir
simulations) over 10,000 years
Search physically for old wells (artificial penetrations)
Evaluate integrity of construction and record of completion
and/or plugging of existing wells that penetrate
containment system.
Evaluate integrity of construction and record of completion
and/or plugging of existing shallow wells that pose a treat
to USDWs.
Remediate old wells in AoR that pose a risk to USDWs
Remediate old wells in AoR that lack high quality cementing
information
Cost Algorithm
36 hours of engineers @$53.52/hr =
$1927 per site + 12 hours of engineers
@$53.52/hr = $642 per injection well
180 hours of engineers @$53.52/hr =
$9634 per site + 24 hours of engineers
@$53.52/hr= $1284 per injection well
180 hours of engineers @$53.52/hr =
$9634 per site + 36 hours of engineers
@$53.52/hr = $1927 per injection well
helicopter magnetic survey requires
about 9 hours/square mile @$1 ,200
per hour.Cost = $5,000 mobilization +
$11,000 per square mile. Follow-up
ground surveys will add another
$2,000 per square mile, (helicopter
survey interline spacing is about 80
feet w
24 hours @$106.31/hr= $2551 per
site + 6 hours @$53.52/hr = $321 per
well
6 hours @$53.52/hr = $321 per well
$30,000 for clean out, $1 3,000 to
replug and $11,000 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 $20,000.
$30,000 for clean out, $1 3,000 to
replug and $1 1,000 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 $20,000.
Data Sources
ICF estimate of time required. Hourly rate
may change based on labor survey data.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
Based on DOE sponsored research at Salt
Creek WY . Helicopter hourly rate is in
range of several publised estimates,
adjustd for higher fuel costs.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
Plugging and logging cost based on 2008
PSAC Well Cost Study. Clean out cost will
vary widely. Cost here is 3 days of rig use
@ $10,000 per day. Rig cost from Land Rig
ewsletter US Land Rig Rates, Novemebr
2007.
Plugging and logging cost based on 2008
PSAC Well Cost Study. Clean out cost will
vary widely. Cost here is 3 days of rig use
@ $10,000 per day. Rig cost from Land Rig
Newsletter US Land Rig Rates, November
2007.
                   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, contribution to a long
term monitoring fund, repair and replacement of wells and equipment, and estimated costs for the possibility
of failure at the site and the need to relocate a sequestration operation. While pore space costs are  included
in the analysis, they are not a part of the new rule.
                                                                                                29

-------
Corrosion Monitoring and Prevention

Because of the propensity of CO2 injection for corrosion, it will be necessary to develop a corrosion
monitoring and prevention program for the operation.

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. 51


Equipment to Add Tracers

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.

Electricity Costs for Pumps and Equipment

Electricity costs represent a significant component of overall operating costs.

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.

Land Use Rents and Right of Way

This unit cost includes the ongoing annual costs for land use and right of way. This is distinct from the
upfront land use costs associated with site characterization.
Pore Space Unit Costs

This unit cost includes an estimate of pore space cost per metric ton 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 a part of the new rule.

Property Taxes and Insurance

This unit cost includes the ongoing expense of property tax and liability insurance.
51 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.
                                                                                                 30

-------
Tracers in Injected Fluid

Tracer testing 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 reservoir and potentially in
overlying groundwater or soil zones. A number of tracers with very low detection limits are available and
more are under development.

The use of tracers for monitoring was investigated under GEO-SEQ52.  Natural and artificial tracers have the
potential to assist in characterizing reservoirs, 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).  53
Perfluorocarbon Tracers (PFTs) have many advantages in that they are  soluble in water, non-toxic, non-
radioactive, and have an extremely small detection limit. 54 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 reservoir 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.55  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.

One potential problem or uncertainty in the use of chemical tracers is the degree to which the tracers move
differently through the reservoir or at different rates than the injected CO2.

Contribution to Long Term Monitoring, Insurance, and Remediation

This cost component represents those costs potentially incurred to establish a long-term post-injection
monitoring program, along with insurance and necessary remediation activity. This cost would be applied
only if such a program is required. Because of the focus of the Safe Drinking Water Act on endangerment to
USDWs and the absence of provisions to allow transfer of liability no such long term program has yet been
proposed and therefore we have not included any potential costs in this report. The IPCC report  (page 241)
includes a description of aspects of long term stewardship. 56
52 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.
53 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide, S. Benson and L. Myer,
Lawrence Berkeley Laboratory, Berkeley, California, 2002.
54 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.

55 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.
56 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
                                                                                                 31

-------
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.

General Failure of Containment Site

There is a small statistical probability that a given sequestration site does not perform adequately, due to
unforeseen subsurface conditions.  This may in some cases require the abandonment of the site and re-
location. The best method of incorporating such a cost is through a risked approach, taking the entire cost
times the small probability of occurrence.

Well Operation Unit Costs

Table 6 specifies the estimated costs and data sources for well operation unit costs.
                                Table 6: Well Operation Unit Costs
Cost Reporting
Heading
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Well Operation
Unit Cost Heading
Permitting Costs
Injection Equipment
(pumps, valves,
measurement
equipment)
Injection Equipment
(pumps, valves,
measurement
equipment)
Injection Equipment
(pumps, valves,
measurement
equipment)
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Remediation During
Operation
Remediation During
Operation
Tracking
Number
E-1
E-2
E-3
E-4
E-5
E-6
E-7
E-8
E-9
E-10
E-11
E-1 2
E-1 3
Cost Item
Develop a corrosion monitoring and prevention program
Standard measurement / monitoring equipment: injected
volumes, pressure, flow rates and annulus pressure
Continuous measurement/ monitoring equipment: injected
volumes, pressure, flow rates and annulus pressure
Equipment to add tracers
Electricity cost for pump, equipment
Injection well O&M
Land use rent, rights-of-way
Pore space use costs
Property Taxes & Insurance
Tracers in injected fluid
Contribution to Long-term Monitoring, Insurance,
Remediation Fund
Repair, replace wells and equipment
General failure of containment at site. Need to build new site,
remove and relocate CO2
Cost Algorithm
24 hours of engineers @$53.52/hr =
$1284 per site
$10,000/well
$15,000/well
$10,000/well
$0.064/kWh
Annual O&M costs are $75,000 + $3/ft
per well per year
$5/acre/year
30.05/barrel or about $0.35 per metric
ton
$0. 03/31 CAPEX
$0.05/ton of CO2 injected
SO.O/unit CO2 injected
Assume 1 %/year of initial well and
equipment cost
Assuming a 1% chance of failure over
injection life, then something like
0.083% of total capital costs each year
would cover such a contingency
Data Sources
ICF estimate of time required. Hourly rate
may change based on labor survey data.
Initial cost estimate until more data are
obtained.
Initial cost estimate until more data are
obtained.
Initial cost estimate until more data are
obtained.
2007 average industrial sector electricity
price reported by EIA.
Operating and maintenance cost based on
EIA Oil and Gas Lease Equipment and
Operating Cost estimates.
ICF estimate based on oil & gas industry
costs. Cost of land rights are highly
variable.
ICF estimate based on oil 8- gas industry
costs. Cost of land rights are highly
variable.
ICF estimate.
Initial cost estimate until more data are
obtained.
not used
ICF assumption
ICF assumption
                                                                                                32

-------
                   3.6   Mechanical Integrity Tests

A CO2 injection well will periodically undergo integrity testing 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.

Mechanical Integrity Pressure Tests


The most common internal MIT is the standard annular pressure test (SAPT).  The annulus between the
casing and injection tubing is pressured and monitored to see if the pressure holds. 5? The EPA and state
regulatory agencies have specific  requirements for pressure testing injection wells and for performing other
mechanical integrity tests. 58 59  Testing occurs prior to injection and periodically thereafter.  Wells which
fail the mechanical integrity test must be shut in until repaired, reworked, or plugged. 60 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.


Internal Mechanical Integrity

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.

Radioactive Tracer Survey of 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
57 Carbon Dioxide Storage: Geological Security and Environmental Issues - Case Study on the Sleipner Field,
Norway, S. Soloman, Bellona Foundation, May, 2007.
58 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.
59 Determination of the Mechanical Integrity of Injection Wells, EPA Region 5 website,
www.epa.gov/region5/water/uic/r5guid/r5 05.htm

60 Underground Injection Control Rules, Montana Board of Oil and Gas Conservation,
www.bogc.dnrc.state.mt.us/uicrules.htm
                                                                                                  33

-------
bond, temperature, noise, and oxygen activation logs.61   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 CO2.62   Descriptions of these technologies are available at the EPA
Region 5 website 63

Pressure Falloff Tests


A falloff test is a pressure transient test that consists of shutting in an injection well and measuring the
pressure  falloff. 64 Falloff tests provide reservoir pressure data and are used to characterize both the
reservoir and the completion condition of the injection well. For Class I non-hazardous 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.
                            Table 7: Mechanical Integrity Tests Unit Costs
Cost Reporting
Heading
Mechanical
Integrity Tests
Mechanical
Integrity Tests
Mechanical
Integrity Tests
Mechanical
Integrity Tests
Mechanical
Integrity Tests
Mechanical
Integrity Tests
Mechanical
Integrity Tests
Mechanical
Integrity Tests
Unit Cost Heading
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Operating Costs
Tracking
Number
F-1
F-2
F-3
F-4
F-5
F-6
F-7
F-8
Cost Item
Internal mechanical integrity pressure tests
Mechanical integrity internal log and video every 5 years
Conduct a radioactive tracer survey of the bottom-hole
cement using a CO2-soluble isotope annually (every 2 years
RA2)
Conduct a radioactive tracer survey of the bottom-hole
cement using a CO2-soluble isotope every Q months
External mechanical integrity tests to detect flow adjacent to
well using temperature or noise log at least annually
External mechanical integrity tests to detect flow adjacent to
well using temperature or noise log at least every Q months
Conduct pressure fall-off test every five years
Conduct pressure falloff test every 6 months
Cost Algorithm
$2,000/test
$2,000 plus $4/foot
$5,000/test
$5,000/test
$2,000 plus $4/foot
$2,000 plus $4/foot
$2,000/test
$2,000/test
Data Sources
Initial cost estimate until more data are
obtained.
Based on 2008 PSAC Well Cost Study for
wireline log suite. Cost of MIT log could be
lower.
Initial cost estimate until more data are
obtained.
Initial cost estimate until more data are
obtained.
Based on 2008 PSAC Well Cost Study for
wireline log suite. Cost of external MIT log
could be lower.
Based on 2008 PSAC Well Cost Study for
wireline log suite. Cost of external MIT log
could be lower.
Initial cost estimate until more data are
obtained.
Initial cost estimate until more data are
obtained.
  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.
62 Carbon Dioxide Storage: Geological Security and Environmental Issues - Case Study on the Sleipner Field,
Norway, S. Soloman, Bellona Foundation, May, 2007.

63 Determination of the Mechanical Integrity of Injection Wells, EPA Region 5 website,
www.epa. gov/region5/water/uic/r5 guid/r5_05 .htm

64  UIC Pressure Falloff Requirements, USEPA Region 9, August, 2002.
                                                                                                    34

-------
                  3.7  Post-Injection Well Plugging, Equipment Removal, and Site
                        Care

After the injection phase has ended, it is necessary to prepare the site for long-term monitoring and eventual
closure in a safe and secure manner that protects USDWs. 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  an understanding of the CO2 distribution in the subsurface.

Plug Injection Wells

Injection wells will be plugged upon completion of injection operations, while monitoring wells will be
plugged after long-term monitoring, since they will be part of the long-term monitoring operation.  Well
abandonment of injection and monitoring wells involves the placement of cement plugs over all or part of
the well, with special care taken to seal of drinking water zones. 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 corrosion resistant cement. (Reference:  IPCC report).

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.

Remove Surface Equipment

For both injection and monitoring wells, surface equipment will be removed as part of site restoration.
Injection well site restoration occurs after the injection period and monitoring well restoration occurs before
closing the site.

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, post injection site care, and closure plans.

Post-Injection Monitoring Well O&M


The annual costs of operating and maintaining the monitoring wells will extend through the end of the post-
injection site care monitoring period.


Post-Injection Air and Soil Surveys


The annual costs of air and soil surveys will extend through the end of the post- injection site care
monitoring period.


Post- Injection Seismic Surveys


The annual costs of seismic surveys will extend through the end of the post-injection site care monitoring
period.
                                                                                               35

-------
Post- Injection Reports to Regulators

Periodic reports to regulators will continue during post Injection Site Care monitoring.
Post-Injection Well Plugging, Equipment Removal, and Site Care Unit Costs

Table 8 specifies the estimated costs and data sources for plugging, equipment removal and post-injection
care.

        Table 8: Post-Injection Well Plugging, Equipment Removal, and Site Care Unit Costs
Cost Reporting
Heading
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Plugging and
Post- Inject! on
Site Care
Unit Cost Heading
Post-Injection MIT,
Plugging, and Remove
Surface Equip.
Post-Injection MIT,
Plugging, and Remove
Surface Equip.
Post-Injection MIT,
Plugging, and Remove
Surface Equip.
Post-Injection MIT,
Plugging, and Remove
Surface Equip.
Post-Injection MIT,
Plugging, and Remove
Surface Equip.
Post-Injection MIT,
Plugging, and Remove
Surface Equip.
Post-Injection MIT,
Plugging, and Remove
Surface Equip.
Post- Inject! on
Monitoring and
Remediation
Post- Injection
Monitoring and
Remediation
Post- Injection
Monitoring and
Remediation
Post- Injection
Monitoring and
Remediation
Tracking
Number
G-1
G-2
G-3
G-4
G-5
G-6
G-7
G-8
G-9
G-10
G-11
Cost Item
Flush wells with a buffer fluid before plugging
Plug injection wells (done to all wells, percents refer to
intensity)
Perform an MIT prior to plugging to evaluate integrity of
casing and cement to remain in ground
Plug monitoring wells
Remove surface equipment, structures, restore vegetation
(injection)
Remove surface equipment, structures, restore vegetation
(monitoring wells)
Document plugging and post- injection process (notification of
intent, post- injection plan, post-injection report)
Post- injection monitoring well O&M
Post- injection air and soil surveys
Post- injection seismic survey (assume every five years)
Periodic post- injection reports to regulators (every 5 years)
Cost Algorithm
$500 + $0.10/foot
$13,000 to plug and $11, 000 to log
(two cement plugs - one in injection
formation and one for surface to
bottom of USDWs, remainder of
borehole filled with mud)
$2,000 plus $4/foot
$6,500 to plug and $5,500 to log (one
cement plugs - surface to bottom of
USDWs, remainder of borehole filled
with mud)
$25,000/injection well
$10,000/monitoring well, $5,000 for
monitoring stations
1 20 hours of engineers @$53.52/hr =
$6422 per site
Annual O&M costs are $25,000 + $3/ft
per well per year
$10,000 per station per year
$75,000/square mile for good
resolution
40 hours @$53.52/hr= $2141 per
report
Data Sources
Initial cost estimate until more data are
obtained.
Plugging and logging cost based on 2008
PSAC Well Cost Study.
Based on 2008 PSAC Well Cost Study for
wireline log suite. Cost of external MIT log
could be lower.
Plugging and logging cost based on 2008
PSAC Well Cost Study.
ICF estimate
ICF estimate
ICF estimate of time required. Hourly rate
may change based on labor survey data.
Operating and maintenance costs adapted
Torn EIA Oil and Gas Lease Equipment and
Operating Cost estimates.
ICF estimate.
Several published reports are in range of
this cost.
ICF estimate of time required. Hourly rate
may change based on labor survey data.
                  3.8  Financial  Responsibility

It will be necessary for the operator to demonstrate and maintain financial responsibility, and have the
resources for activities related to closing and remediating GS sites.  The rule only specifies a general duty to
obtain financial responsibility acceptable to the Director, and EPA will provide guidance to be developed at
a later date that describes the recommended types of financial mechanisms that owners or operators can use
to meet this requirement.  The following unit costs were used:
                                                                                               36

-------
Performance Bond or Demonstration of Financial Ability for Well Plugging

This unit cost item includes the labor costs to prepare a report demonstrating financial responsibility for well
plugging.

Performance Bond or Demonstration of Financial Ability for Post-Injection Site Care Period

This unit cost item includes the labor costs to prepare a report demonstrating financial responsibility for post
injection monitoring, including remediation.

Financial Responsibility Unit Costs
Table 9 specifies the estimated costs and data sources for financial responsibility unit costs.

                            Table 9: Financial Responsibility Unit Costs
Cost Reporting
Heading
Financial
Responsibility
Financial
Responsibility
Unit Cost Heading
Post- Inject! on
Monitoring and
Remediation By
Operator
Post- Inject! on
Monitoring and
Remediation By
Operator
Tracking
Number
H-1
H-2
Cost Item
Performance bond or demonstrate financial ability to close
site (including annual inflation factor)
Performance bond or demonstrate financial ability for post-
injection monitoring (including annual inflation factor)
Cost Algorithm
8 hours @$53.52/hr = $428 per
financial report
4 hours@$53.52/hr=$214 per
financial report
Data Sources
ICF estimate of time required. Hourly rate
may change based on labor survey data.
no added cost
                   3.9  General and Administrative Costs

General and administrative costs are included as unit costs for both the project development and operating
phases.  The costs are specified as a percentage either capital costs or annual operating costs.

Table 10 specifies the estimated costs and data sources for general and administrative unit costs.

                          Table 10: General and Administrative Unit Costs
Cost Reporting
Heading
G&A Costs
G&A Costs
Unit Cost Heading
General and
Administrative Costs
for Capex
General and
Administrative Costs
for Opex
Tracking
Number
J-!
J-2
Cost Item
Project development G&A
Operating G&A
Cost Algorithm
20% of initial capital expenditure
20% of annual operating costs
Data Sources
ICF estimate based on oil and gas industry
factors.
ICF estimate based on oil and gas industry
factors.
                                                                                               37

-------
38

-------
         Characteristics of Example Projects for Costing
                   4.1   Introduction

While costs could vary significantly on a site-by-site basis, for the current analysis a decision was made to
create three example geologic sequestration cases for costing:

       saline reservoir
       depleted gas field
       depleted oil field

The rationale for selecting these three cases is as follows:

Saline Reservoir
Saline reservoir storage capacity represents a large percentage of assessed U.S. capacity and it is widely
agreed that this reservoir type will eventually be chosen for most future U.S. CO2 storage.  Saline reservoirs
are present in most regions of the country, including areas that have not historically had a great deal of oil
and gas production. An additional factor is that in most cases these potential reservoirs have not been
penetrated by wells, which can provide leakage pathways. It has also been demonstrated at Sleipner field
that CO2 sequestration in saline reservoirs is effective and the CO2 plume can generally be monitored
effectively  with seismic and other forms of monitoring techniques.

In addition, most of the planned major DOE sequestration pilots are in saline reservoir settings.

Depleted Conventional Gas Field and Depleted and Abandoned Oil Field
While the assessed volume of potential U.S. CO2 storage  in depleted gas fields is only a small fraction of the
U.S. total, it is expected that industry will choose to sequester some CO2 in these settings. Among these are
the known presence of a trap, known reservoir properties  such as porosity, permeability, and flow
characteristics, and established field and transportation infrastructure.  It was also considered important to
develop a set of characterization, monitoring, and other costs in settings other than saline reservoirs, because
of presences of existing wells and other infrastructure.
                   4.2   Lawrence Berkeley Study
ICF has reviewed available literature from other organizations that have developed parameters for "typical"
storage scenarios by reservoir type. Review of this information was useful in helping us develop our
example projects.

A research team at Lawrence Berkeley National Laboratory investigated a large number of scenarios for
carbon sequestration and selected two for detailed evaluation65.  Table 11 lists their parameters to use for
estimating the costs of storage for enhanced oil field recovery and saline aquifer scenarios.
65 Monitoring Protocols and Life-Cycle Costs for Geologic Storage of Carbon Dioxide, by S. M. Benson, M.
Hoversten, and E. Gasperikova of Lawrence Berkeley National Laboratory, and M. Haines of EA Greenhouse Gas
                                                                                                 39

-------
            Table 11: Lawrence Berkeley Study Parameters for Their Economic Analysis
Scenario
Parameters
Storage Scenario
Number of Injection
Wells
Reservoir Properties
Operational Period
Post Inj . Period
Post-Closure
MassofCO2
Injected
Frequency of
Geophysical
Monitoring
Project Footprint
Oil-Field
CO2 storage combined with enhanced oil
recovery
20 injection, 12 production wells distributed
evenly over the foot print of the reservoir, based
on the Schader Bluff scenario
25 m thick, areal extent of 360 km2
30 years
20 years
0 years (assume no leakage from the storage
formation)
258 million metric tons CO2
5, 10,20, 30,40, and 50 years

360 km2 (area of the oil reservoir)
Saline Formation
CO2 storage in a saline formation
10 injection wells located within a 10 sq. km area, based
on the injectivity of vertical wells in a Frio-like formation
with a permeability of 0.5 Darcy
100 m thick, 20% porosity, capacity factor of 10%,
density of CO2 at reservoir conditions 800 kg/m3
30 years
50 years
0 years (assume no leakage from the storage formation)
258 million metric tons CO2
1, 2, 5, 10, 15, 20, 25, 30, 40, 50, 60, 70, and 80 years

HRG Plume: 1 9 km2 after the first year, growing to 2 1 6
km2 after 80 years;
LRG Plume: 18 km2 after the first year, growing to 348
km2 after 80 years
                  4.3  Regional DOE Partnership Pilot Projects and FutureGen

ICF has evaluated the characteristics of the DOE pilot sequestration projects and the previously selected
FutureGen sequestration site in Illinois.  The characteristics of these projects were used in the development
of our type examples.  Project characteristics that have been compiled are shown in Tables 12 and 13. None
of the major projects currently planned for injection pilots is a depleted gas field, but there is information on
oil reservoir pilots. As shown in the table, the currently planned projects are only scheduled for about three
to four years of injection. The typical injection rate (from one well) is up to one million tons of CO2 per
year. This can be compared to an expected full scale future rate for a power plant of up to  several million
tons per year, likely involving multiple injection wells over a much longer period of time.

For the FutureGen project, a 2007 report by the FutureGen Alliance lays out the characteristics of all of the
proposed sequestration sites (FutureGen Initial Conceptual Design Report, 2007). Included is information
on several areas including such as depth, thickness, porosity, expected injectivity and ultimate plume size.
R&D Programme, Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies (GHGT-
7), September 5-9, 2004, Vancouver, Canada, v. II, 1259-1266, 2005.
                                                                                                40

-------
                           Table 12: DOE CO2 Sequestration Pilot Projects (DOE Phase III) and FutureGen Project
Regional
Organization
Project
Name
Main Projects -Announced DOE Phase III
Big Sky Green River Basin Nugget Saline Reservoir
Moxa Arch, Western Wyoming
MGSC
PCOR
SWCARB
SECARB
MRCSP
WESTCARB
Other Proposed
SWCARB
SECARB
Illinois Basin Mt. Simon Saline Reservoir
Williston Basin EOR Sequestration; ND
Raton Basin Entrada Saline Reservoir;
SW Colorado
Mississippi Tuscaloosa Massive Saline
Reservoir; SW Mississippi
Cincinnati Arch Mt. Simon Saline
Reservoir; Greenville, OH
San Joaquin Basin, CA Saline Formation;
Olcese and Vedder Sands
DOE Pilot Projects
Green River Basin Entrada
"Athropogenic " Test in Tuscaloosa
DOE Planned Total Injection
Funding Tons per Duration Sequestered Cost CO2 Depth
Status Year Years Tons $MM Source ft Comments
Proposed 1 ,000,000
Approved 365,000
Approved 750,000
Approved 700,000
Approved 1 ,000,000
Proposed 280,000
Proposed 250,000

Proposed 100,000
Proposed 250,000
3 3,000,000 $110 Gas plant 12,000
3 1,095,000 $84 ADM ethanol plant 5,500
6 4,500,000 $300 Existing coal plant 10,000
4 2,800,000 $81 La Veta gas plant ? Strat. below gas field
containing CO2
1.5 1,500,000 $94 Jackson Dome 10,000 Downdip of oil reservoir
4 1,120,000 $93 Planned ethanol pit. 3,500
4 1 ,000,000 $91 New 49 MW plant 9,000 Timeline shows 8 years
of injection

1 100,000 Pacificorp power pit. 7,000
4 1 ,000,000 CO2 from as yet undecided
                  Massive Saline Reservoir
FutureGen Project    Matoon, IL Location of FutureGen
                                                                                                                             source/ power plant
                                                    Selected
2,000,000
20+   50,000,000   $1,500 IGCC plant
                                                                                                                                                      41

-------
Table 13: Details of Sequestration Pilot Projects
Regional Project
Organization Name
Main Projects - Announced DOE Phase III
Big Sky Green River Basin Nugget Saline Reservoir
Moxa Arch, Western Wyoming
MGSC Illinois Basin Mt. Simon Saline Reservoir
POOR Williston Basin EOR Sequestration; ND
SWCARB Raton Basin Entrada Saline Reservoir;
SE Colorado
SECARB Mississippi Tuscaloosa Massive Saline
Reservoir; SW Mississippi
MRCSP Cincinnati Arch Mt. Simon Saline
Reservoir; Greenville, OH
WESTCARB San Joaquin Basin, CA Saline Formation;
Olcese and Vedder Sands
Other Proposed DOE Pilot Projects
SWCARB Green River Basin Entrada
SECARB "Athropogenic " Test in Tuscaloosa
Massive Saline Reservoir
Proposed FutureGen Projects
Matoon, IL Location of FutureGen
Tuscola, IL Mt. Simon
Odessa, TX Delaware Sand
Brazos, TX Woodbine Sand
Formation
Name
Nugget
Mt. Simon
Undet.
Entrada

Tuscaloosa
Mt. Simon

Vedder

Entrada
Tuscaloosa
Mt. Simon
Mt. Simon
Delaware
Woodbine
Lithology
Sandstone
Sandstone
Carbonate
Sandstone

Sandstone
Sandstone

Sandstone

Sandstone
Sandstone
Sandstone
Sandstone
Sandstone
Sandstone
Top
Injection Gross Net Press.
Depth Interval Sand Porosity Perm. Grad. Pressure Temp
ft ft ft % md psi/ft psi F
12,000 700 200 15% 0.35 4200 209
5,500 1500
10,000
?

10,000 1300
3,500 300 12% 50-400 0.41 1450 88

9,000 800 10-40%

7,000

6,750 1,300-1,600 500
6,150 1600 600
3,600 1600 130
4,800 500 20-30% high
Well
Gas Injec-
TDS Stream tivity
mg/L % CO2 MM t/yr
109000 92%


97%








2.50
2.50
0.25-0.33
1.13
                                                                                       42

-------
                  4.4  Project Characteristics - Saline Reservoir (Commercial Scale)

Basic properties from the saline reservoir case are based upon typical parameters as evaluated in the DOE
pilots. It should be noted that there is a wide range of variation in the properties among the various DOE
pilot projects. Generally speaking however, the saline reservoirs are characterized by thick, porous
intervals, generally at depths below 5,000 feet. Gross sand intervals are typically hundreds of feet thick and
net (porous) sand intervals are also thick.

Table 14 presents the project characteristics for a commercial scale saline reservoir site. The example is
based upon sequestration of the CO2 from a 275 MW power plant. As shown in the first part of the table
titled "Power Plant, Injection Rate, and Monitoring," with 90 percent capture and 85 percent utilization,
this equates 1.8 million tons per year. The injection period is 20 years, representing about 37 million tons of
sequestration. The 20 year period represents one half of the full lifetime of a power plant. The injection
was split into two 20 year periods under the assumption that the operator will  develop half of the
sequestration capacity initially and the other half in approximately 20 years.  Such a staggered development
would reduce the present value of investment and operating cost.

The second portion titled "Injection Zone Depth, Pressure, and Temperature" lists the values for those
parameters and the calculated CO2 density.

The next section titled "Volumetrics and Capacity" lists the assumptions required to estimate the total
potential storage volume within a specified area. In terms of theoretical storage capacity, an initial volume
is estimated based upon the pore space and the density of CO2 in kg/cu. meter. A practical storage volume is
calculated using an estimated storage efficiency factor often percent.  The ten percent assumption has been
cited in various literature sources as a good first approximation and is based upon a volumetric analysis
carried out by ICF on published storage capacity estimates from the DOE NATCARB project.   The
practical storage capacity is  much lower than the pore space volume because of factors such as the geometry
of the plume and other factors relating to geologic complexity.

The section titled "Old Wells in Area" shows the assumptions for the number and characteristics of
existing wells.  Old wells are estimated at one per square mile for deeper wells and two per square mile for
shallow wells. The old well assumptions impact well remediation costs.

The section titled "Injection Wells and Stratigraphic  Wells" shows the assumptions for the number of
injection wells and potential Stratigraphic test wells. For the commercial scale projects, the number of
injection wells is based upon an assumption of 2,000 tons per day per well, plus one additional well. For the
pilot scale projects, there is an assumption of one injector.  The number of Stratigraphic wells is a maximum
of one for commercial scale  projects, and depends upon the regulatory scenario. There are no Stratigraphic
wells for the pilot projects.

Under the section titled "Monitoring Wells," assumptions are presented on the maximum number of
monitoring wells in each case. The actual number of monitoring wells is dependent upon the regulatory
scenario. Also shown here are the assumptions for air and soil sampling and microseismic arrays.

The section "USDWs and Containment Systems" shows the assumptions for the depths to the top of the
deepest USDW and the depths to the top and bottom of containment systems.

The "CO2 Pipelines and Pumps" section shows the estimated number of miles of CO2 distribution
pipelines, pipeline diameters, and pump horsepower.
                                                                                               43

-------
           Table 14: Saline Reservoir Type Case Characteristics (Commercial Scale Project)
Power Plant, Injection Rate, and Monitoring
MW Power Plant
90% Capture (CO2 tonnes/day)
Capacity Utilization
Tons per Year
Storage facility injection life in years
Tons for facility
Post-injection monitoring period in years	
          275
         5,940
          0.85
    1,842,885
           20
   36,857,700
           10
Injection Zone Depth, Pressure, and Temperature
Depth to Top of Injection Interval (ft)
Depth to Bottom of Injection Interval (ft)
Hydrostatic pressure (psi)
Temp(F) @1dF/100ft
Hydrostatic pressure (Mpa)
Temp. (C)
CO2 density (kg/cu.m)	
        7,900
        8,500
        3,681
          147
         25.4
         63.9
        782.0
Volumetrics and Capacity
Gross thickness (ft)
Net thickness (ft)
Porosity (%)
Area (sq. mi.)
Area (sq. ft.)
Pore space volume (cu. ft)
Pore space volume (cu. m)

Million tonnes capacity at 100% storage efficiency
Storage efficiency
Effective Million tonnes capacity	
          600
          300
          20%
           10
   278,784,000
16,727,040,000
   473,656,579

          370
        10.0%
           37
 Set square miles so as to make facilities
capacity large enough for power plant
Old Wells in Area

Deep Artificial Penetrations (exclude any to be used as
injectors)
Shallow Artificial Penetrations
Water Wells Artificial Penetrations
                                                         In AoR
                             Additional
                Known to     Wells w/o
                 Require    Good Cement
               Remediation      Logs
           10
           20
           20
         1.0
         2.0
         2.0
1.5
3.0
3.0
 One per square mile
 Two per square mile
 Two per square mile
                                                                                                                 44

-------
    Table 14. (continued) Saline Reservoir Type Case Characteristics (Commercial Scale Project)
Injection Wells and Stratigraphic Wells
Injection Wells Required (total)
Injection Wells New Drills
Injection Wells Conversions of Old Wells
Cost of Converted Wells as % of New
Tubing Size (inches)
Number of Stratigraphic Tests (if required)
Depth of Stratigraphic Tests (feet)
Cores per Stratigraphic Test

4.0
4.0
0
15%
6.0
1
9,350
6










Monitoring Wells, etc.
Max. Number of Monitoring Wells (depends on scenario)
Depth of Monitoring Wells (feet)
Long-string Casing of Monitoring Wells (diam. inches)
Air/soil Sampling Stations (if required)
Passive seismic arrays (inside monitoring wells if required)
Above Inj Zone
16
4,700
3.5
3
2
Into Inj Zone
16
8,350
3.5


                                                                               Based on injection rate
                                                                              per well of 2,000 mtpd plus
                                                                              one extra well.
                                                                               Maximum number based
                                                                              on number of injectors
USDW's and Containment Systems
Deepest USDW
Second Containment System Depth to Top (ft)
Second Containment System Depth to Bottom (ft)
First Containment System Depth to Top (ft)
First Containment System Depth to Bottom (ft)
2,000
5,800
6,100
7,000
7,400

CO2 Pipelines and Pumps
Distribution Pipeline 1
Distribution Pipeline 2
Total inch-miles
Pump HP
Miles (inches)
3.2 6
3.2 4
32
713
 Depths are estimates
based upon relationship
to reservoir depth.
 Calculated from
reservoir area
 Based on inj. rate
                  4.5  Project Characteristics - Depleted gas reservoir (Commercial
                        Scale)

For the depleted gas and depleted oil reservoirs, ICF relied upon a statistical analysis of the DOE "GASIS"
reservoir database. 66  This is a reservoir level database compiled for DOE in the 1990s and includes
properties for most of the significant oil and gas fields in the U.S.  Statistics were derived from GASIS
through the evaluation of only those reservoirs occurring within a depth range of 3,000 to 10,000 feet. The
results of the analysis are shown in Table 15 and the example case for commercial scale depleted gas
reservoirs is shown in Table 16.  The categories are the same as described above for the commercial scale
saline case.
66 Gas Information System (GASIS) Project, U.S. Department of Energy, National Energy Technology Center,
Morgantown, WV.
                                                                                               45

-------
Table 15: Summary of GASIS Reservoir Database Parameters for Depleted Gas Reservoir and
                         Depleted Oil Reservoir Example Cases
         Parameter
Units
Saline
Gas
Oil
Depth
Porosity
Permeability
Gross Pay
Net Pay
Area
Area
Hist. Completions
Completions/Sq.mi.
feet
%
md
feet
feet
acres
sq. mi.
number
number
8,500
20.0%
200
600
300
*
*
*

7,500
15.0%
50
400
200
9,600
15.0
30.0
2
5,000
15.0%
50
400
200
12,800
20.0
160.0
8
          = Dependent upon injection scenario
                                                                                     46

-------
Table 16: Depleted Gas Reservoir Type Case Characteristics (Commercial Scale Project)
Power Plant, Injection Rate, and Monitoring
MW Power Plant
90% Capture (CO2 tonnes/day)
Capacity Utilization
Tons per Year
Storage facility injection life in years
Tons for facility
Post-injection monitoring period in years
210
4,536
0.85
1 ,407,294
20
28,145,880
10

Injection Zone Depth, Pressure, and Temperature
Depth to Top of Injection Interval (ft)
Depth to Bottom of Injection Interval (ft)
Hydrostatic pressure (psi)
Temp(F) @1dF/100ft
Hydrostatic pressure (Mpa)
Temp. (C)
CO2 density (kg/cu.m)
7,200
7,500
3,248
137
22.4
58.3
789.0

Volumetrics and Capacity
Gross thickness (ft)
Net thickness (ft)
Porosity (%)
Area (sq. mi.)
Area (sq. ft.)
Pore space volume (cu. ft)
Pore space volume (cu. m)
Million tonnes capacity at 100% storage efficiency
Storage efficiency
Effective Million tonnes capacity
300
200
15%
15.0
418,176,000
12,545,280,000
355,242,434
280
10.0%
28.0
                                                     Sized to match reservoir storage volume
                                                     Sized to match reservoir storage volume
                                                     Actual area from database analysis




Old Wells in Area
Deep Artificial Penetrations (exclude any to be used as
injectors)
Shallow Artificial Penetrations
Water Wells Artificial Penetrations




In AoR

30
30
30


Known to
Require
Remediation

3.0
3.0
3.0
Additional
Wells w/o
Good
Cement
Logs

4.5
4.5
4.5
                                                                           One per square mile
                                                                           Two per square mile
                                                                           Two per square mile
                                                                                                  47

-------
Table 16 (continued)  Depleted Gas Reservoir Type Case Characteristics (Commercial Scale Project)
Injection Wells and Stratigraphic Wells
Injection Wells Required (total)
Injection Wells New Drills
Injection Wells Conversions of Old Wells
Cost of Converted Wells as % of New
Tubing Size (inches)
Number of Stratigraphic Tests (if required)
Depth of Stratigraphic Tests (feet)
Cores per Stratigraphic Test
4.0
4.0
0
15%
6.0
1
8,250
6

Monitoring Wells, etc.
Max. Number of Monitoring Wells (depends on scenario)
Depth of Monitoring Wells (feet)
Long-string Casing of Monitoring Wells (diam. inches)
Air/soil Sampling Stations (if required)
Passive seismic arrays (inside monitoring wells if
required)
Above Inj Zone Into Inj Zone
16 16
4,150 7,425
3.5 3.5
4
3

USDWs and Containment Systems
Deepest USDW
Second Containment System Depth to Top (ft)
Second Containment System Depth to Bottom (ft)
First Containment System Depth to Top (ft)
First Containment System Depth to Bottom (ft)
2,000
5,100
5,400
6,300
6,700

CO2 Pipelines and Pumps
Distribution Pipeline 1
Distribution Pipeline 2
Total inch-miles
Pump HP
Miles (inches)
3.9 6
3.9 4
39
544
 Based on injection rate
per well of 2, 000 mtpd plus
one extra well.
 Maximum number based
on number of injectors
 Depths are estimates
based upon relationship
to reservoir depth.
 Calculated from
reservoir area
 Based on inj. rate
                                                                                         48

-------
                  4.6   Current Project Characteristics - Depleted Oil Reservoir
                        (Commercial Scale)
The example case for depleted oil reservoirs is presented in Table 17.
       Table 17: Depleted Oil Reservoir Type Case Characteristics (Commercial Scale Project)
                                                          Sized to match reservoir storage volume
Power Plant, Injection Rate, and Monitoring
MW Power Plant
90% Capture (CO2 tonnes/day)
Capacity Utilization
Tons per Year
Storage facility injection life in years
Tons for facility
Post-injection monitoring period in years
275
5,940
0.85
1,842,885
20
36,857,700
10

Injection Zone Depth, Pressure, and Temperature
Depth to Top of Injection Interval (ft)
Depth to Bottom of Injection Interval (ft)
Hydrostatic pressure (psi)
Temp(F) @1dF/100ft
Hydrostatic pressure (Mpa)
Temp. (C)
CO2 density (kg/cu.m)
4,600
5,000
2,165
112
14.9
44.4
758.0

Volumetrics and Capacity
Gross thickness (ft)
Net thickness (ft)
Porosity (%)
Area (sq. mi.)
Area (sq. ft.)
Pore space volume (cu. ft)
Pore space volume (cu. m)
Million tonnes capacity at 100% storage efficiency
Storage efficiency
Effective Million tonnes capacity
400
200
15%
20
557,568,000
16,727,040,000
473,656,579
359
10.0%
36
                                                          Actual area from database analysis
Old Wells in Area
Deep Artificial Penetrations (exclude any to be used as injectors)
Shallow Artificial Penetrations
Water Wells Artificial Penetrations
InAoR
160
40
40
Known to
Require
Remediation
16.0
4.0
4.0
Additional Wells
w/o Good Cement
Logs
24.0
6.0
6.0
                                                                                 One per square mile
                                                                                 Two per square mile
                                                                                 Two per square mile
                                                                                              49

-------
  Table 17 (continued) Depleted Oil Reservoir Type Case Characteristics (Commercial Scale Project)
Injection Wells and Stratlgraphlc Wells
Injection Wells Required (total)
Injection Wells New Drills
Injection Wells Conversions of Old Wells
Cost of Converted Wells as % of New
Tubing Size (inches)
Number of Stratigraphic Tests (if required)
Depth of Stratigraphic Tests (feet)
Cores per Stratigraphic Test
4.0
4.0
0
15%
6.0
1
5,500
6


Monitoring Wells, etc.
Max. Number of Monitoring Wells (depends on scenario)
Depth of Monitoring Wells (feet)
Long-string Casing of Monitoring Wells (diam. inches)
Air/soil Sampling Stations (if required)
Passive seismic arrays (inside monitoring wells if required)
Above Inj Zone
16
2,700
3.5
5
4
Into Inj Zone
16
4,900
3.5
                                                                              Based on injection rate
                                                                             per well of 2,000 mtpd plus
                                                                             one extra well.
                                                                              Maximum number based
                                                                             on number of injectors
USDW's and Containment Systems
Deepest USDW
Second Containment System Depth to Top (ft)
Second Containment System Depth to Bottom (ft)
First Containment System Depth to Top (ft)
First Containment System Depth to Bottom (ft)
1,700
2,500
2,800
3,700
4,100

CO2 Pipelines and Pumps
Distribution Pipeline 1
Distribution Pipeline 2
Total inch-miles
Pump HP
Miles Diam (inches)
4.5 6
4.5 4
45
713
 Depths are estimates
based upon relationship
to reservoir depth.
 Calculated from
reservoir area
 Based on inj. rate
                   4.7   Pilot Scale Example Projects

A set of example projects has also been developed to allow the application of unit costs to pilot scale
projects.  The pilot projects are characterized to represent the smaller annual and total injection volumes and
other aspects of pilot scale projects such as those planned by DOE.  These projects are detailed in Appendix
A.
                                                                                                  50

-------
  5      Uncertainties in Analysis

As with any technology and cost analysis, there are many sources of uncertainty, both in terms of current
costs and likely costs in the future. In the current study, these are 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)

        How many times the costs are applied through the life of the project, (e.g. number of surveys)

        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.

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 is known to industry, although there is
uncertainty in terms of which situations this would be applied and how much impact it will have.

Unit cost 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 technologies are in an early stage of
                                                                                                51

-------
development and are not commercially deployed, and the fact that 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. ICF has obtained useful information from the literature and
from a UIC meeting in New Orleans. 6?  For example, we obtained information on eddy covariance,
geochemical testing, and tracer injection. In addition, unit cost input has been received from the Department
of Energy 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,
this uncertainty is only part of the equation.

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.

Uncertainty  in Characteristics and Cost Repetition Through Time
Much of the overall uncertainty relates not to the specific unit costs but the assumptions related to the
characteristics of the example cases which determine the overall cost of applying the technology.

There is uncertainty in the example sequestration projects. For example, the saline reservoir case is based
upon the general characteristics of the DOE pilots, but there is a great range of characteristics such as depth,
pay thickness, and porosity in those projects. For the depleted gas and depleted oil field example cases, a
statistical analysis of existing fields was performed, but because of the general lack of pilot projects in these
settings, there is uncertainty in terms of what may become typical in these settings over the coming decades.

Various sources in the literature helped in our determination of the example site characteristics and the
number of monitoring stations and frequency of monitoring. However, it can be said that there is no
industry consensus on the levels of appropriate monitoring, how many monitor wells  are needed, etc.

Number of Hours and Hourly Rates
Several of the cost categories here 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 would be done in-house by
employees or contracted out.

Cost Changes Through 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 is needed, and general labor cost changes.

For example, sequestration projects initiated over the next decade or so may incur higher labor costs than
those farther in the future, due to a shortage of experienced technical staff that specialize in injection
operations. As more projects become operational, costs may decline due to better knowledge and more
efficient site characterization, operation, and monitoring approaches.
  Joint GWPC/EPA CO2 MMV meeting, New Orleans, LA January 16, 2008.
                                                                                                 52

-------
         Bibliography
Carbon Capture and Storage: A Regulatory Framework for States - Summary of Recommendations,, by
Kevin Bliss, Interstate Oil and Gas Compact Commission, January, 2005.
Carbon Dioxide Storage: Geological Security and Environmental Issues - Case Study on the Sleipner
Field, Norway, S. Soloman, Bellona Foundation, May, 2007.
Carbon Sequestration Technology Roadmap and Program Plan 2007, Ensuring the Future of Fossil Energy
Systems through the Successful Deployment of Carbon Capture and Storage Technologies, U.S. Department
of Energy, Office of Fossil Energy, National Energy Technology Laboratory, 2007.

CO2 Storage in Saline Aquifers, by M. Bentham and G. Kirby, Oil and Gas Science and Technology, vol. 60,
no.  3, 2005.
Determination of the Mechanical Integrity of Injection Wells, EPA Region 5 website,
www.epa.gov/region5/water/uic/r5guid/r5 05.htm
Discussion Paper:  Identifying Gaps in CO2 Monitoring and Verification of Storage, by B. Reynen, M.
Wilson, N. Riley, T. Manai, O. M. Mathiassen, and S. Holloway, A Task Force under the Technical Group
of the Carbon Sequestration Leadership Foru, (CSLF), Paper No. CSLF-T-2005-3, Presented at the
Technical Group Meeting, April 30, 2005.
Economic Evaluation ofCO2 Storage  and Sink Options, by B. R. Bock, R. Rhudy, H. Herzog, M. Klett, J.
Davison,  D. De la Torre Ugarte, and D. Simbeck, DOE Research Report DE-FC26-OONT40937, February,
2003.
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.
Investigation of Novel Geophysical Techniques for Monitoring CO 2 Movement during Sequestration, Final
Report No. 822176, by G. M. Hoversten and E. Gasperikova, Lawrence Berkeley National Laboratory,
Berkeley California, October 2003.
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.
Joint Association Survey of Drilling Costs, American Petroleum Institute, Washington, DC.
http://www.api.org/statistics/accessapi/api-reports.cfm
Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org,
December 1, 2006.
Measurement, Monitoring, and Verification, L. H. Spangler, Zero Emission Research and Technology
Center, Carbon Sequestration Leadership Forum, date unknown.
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.
                                                                                             53

-------
Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and
Carbon Credits, Paper SPE102833, by S. M. Benson, Earth Sciences Division, Lawrence Berkeley National
Laboratory, for SPE ATCE, San Antonio, Texas, September 26, 2006.
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.
Monitoring of Aquifer Disposal ofCO2: Experience from Underground Gas Storage and Enhanced Oil
Recovery, by W. D. Gunter, Alberta Research Council, R. J. Chalaturnyk, University of Alberta, and J. D.
Scott, University of Alberta, for Alberta Research Council, Edmonton, Alberta, Canada.
Monitoring of Sequestered CO2:  Meeting the Challenge with Emerging Geophysical Technologies, S.N.
Dasgupta, Saudi Aramco, 2005.
Monitoring Protocols and Life-Cycle Costs for Geologic Storage of Carbon Dioxide, by S. M. Benson,
Lawrence Berkeley National Laboratory, for Carbon Sequestration Leadership Forum, Melbourne,
Australia, September  13-15, 2004.
Monitoring Protocols and Life-Cycle Costs for Geologic Storage of Carbon Dioxide, by S. M. Benson, M.
Hoversten, and E.  Gasperikova of Lawrence Berkeley National Laboratory, and M. Haines of EA
Greenhouse Gas R&D Programme, Proceedings of the 7th International Conference on Greenhouse Gas
Control Technologies (GHGT-7), September 5-9, 2004, Vancouver, Canada, v. II, 1259-1266, 2005.
Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide, S. Benson and L.
Myer, Lawrence Berkeley Laboratory, Berkeley, California, 2002.
Oil and Gas Lease Equipment and Operating Costs, U.S. Energy Information Administration, 2006,
http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/curr
ent/coststudy .html
Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September 3, 2007.
Overview of Monitoring Requirements for Geologic Storage Projects, IEA Greenhouse Gas Programme,
Report No.  PH4/29, November, 2004.
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, 2004.
PSAC Well Cost Study - 2008, Petroleum Services Association of Canada, October 30, 2007.
Report on Monitoring Workshop, organized by IEA Greenhouse Gas R&D Programme and BP with the
support of EPRI and the U.S.  DOE/NETL, at University of California at Santa Cruz, November 8-9, 2004.
Reservoir Monitoring Methods and Installation Practices, by G. V. Chalifoux and R. M. Taylor, Petrospec
Engineering Ltd., CADE eNews, February 2007.
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.
Sensitivity and Cost of Monitoring Geologic Sequestration Using Geophysics, by L. R. Myer, G. M.
Hoversten, and E.  Gasperikova, Lawrence Berkeley National Laboratory, Berkeley California, Proceedings
of the 6th International Conference  on Greenhouse Gas Control Technologies (GHGT-6), J. Gale and Y.
Kaya (eds.), 1-4 October 2002, Kyoto, Japan, Pergamon, Vol. 1, pp. 377-382, 2003.
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.
                                                                                             54

-------
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 Status Review -Monitoring Technologies for the Geological Storage ofCO2, 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.
The Economics ofCO2 Storage, Gemma Heddle, Howard Herzog, and Michael Klett, Laboratory for Energy
and the Environment, Massachusetts Institute of Technology, August, 2003.
The Future of Coal, Options for a Carbon-constrained World, An Interdisciplinary MIT Study,
Massachusetts Institute of Technology, 2007.
The U-Tube - Novel System for Sampling and Analyzing Mult-Phase Borehole Fluid Samples, by Barry M.
Freifeld, et al, Lawrence Berkely National Laboratory, Berkely, CA. (publication date unknown).
UIC Pressure Falloff Requirements, USEPA Region 9, August, 2002.
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.
Underground Injection Control Rules, Montana Board of Oil and Gas Conservation,
www.bogc.dnrc.state.mt.us/uicrules.htm.
                                                                                             55

-------
APPENDIX A - CHARACTERISTICS  OF PILOT SCALE
EXAMPLE PROJECTS
Table Al - Saline Pilot Scale Project
 Power Plant, Injection Rate, and Monitoring
 MW Power Plant
 90% Capture (CO2 tonnes/day)
 Capacity Utilization
 Tons per Year
 Storage facility injection life in years
 Tons for facility
 Post-injection monitoring period in years
     112
    2,419
     0.85
 750,557
       7
5,253,898
      10
Injection Zone Depth, Pressure, and Temperature
Depth to Top of Injection Interval (ft)
Depth to Bottom of Injection Interval (ft)
Hydrostatic pressure (psi)
Temp(F)  @1dF/100ft
Hydrostatic pressure (Mpa)
Temp. (C)
CO2 density (kg/cu.m)	
   7,900
   8,500
   3,681
     147
    25.4
    63.9
   782.0
Volumetrics and Capacity
Gross thickness (ft)                                       600
Net thickness (ft)                                         300
Porosity (%)                                            20%
Area (sq. mi.)                                            1.4
Area (sq. ft.)                                       39,029,760
Pore space volume (cu. ft)                           2,341,785,600
Pore space volume (cu. m)                            66,311,921

Million tonnes capacity at 100% storage efficiency                  52
Storage efficiency                                       10.0%
Effective Million tonnes capacity                              5.2
: Equivalent to 750,000 tons/yr
          Set square miles so as to make facilities
         capacity large enough for power plant
Old Wells in Area

Deep Artificial Penetrations (exclude any to be used as
injectors)
Shallow Artificial Penetrations
Water Wells Artificial Penetrations
                                                 In AoR
                     Additional
           Known to    Wells w/o
           Require      Good
         Remediation Cement Logs
                 0.1
                 0.3
                 0.3
                 0.2
                 0.4
                 0.4
 One per square mile
 Two per square mile
 Two per square mile
                                                                                                   56

-------
Table Al (Continued) - Saline Pilot Scale Project
Injection Wells and Stratigraphic Wells
Injection Wells Required (total)
Injection Wells New Drills
Injection Wells Conversions of Old Wells
Cost of Converted Wells as % of New
Tubing Size (inches)
Number of Stratigraphic Tests (if required)
Depth of Stratigraphic Tests (feet)
Cores per Stratigraphic Test

1.0
1.0
0
15%
6.0
0
9,350
6

Monitoring Wells, etc.
Max. Number of Monitoring Wells (depends on scenario)
Depth of Monitoring Wells (feet)
Long-string Casing of Monitoring Wells (diam. inches)
Air/soil Sampling Stations (if required)
Passive seismic arrays (inside monitoring wells if
required)
Above Inj Zone Into Inj Zone
4 4
4,500 8,350
3.5 3.5
0

0

USDW's and Containment Systems
Deepest USDW
Second Containment System Depth to Top (ft)
Second Containment System Depth to Bottom (ft)
First Containment System Depth to Top (ft)
First Containment System Depth to Bottom (ft)

2,000
5,800
6,100
7,000
7,400

CO2 Pipelines and Pumps

Distribution Pipeline 1
Distribution Pipeline 2
Total inch-miles
Pump HP

Miles (inches)
1.2 6
0.0 4
7
290

 One injector well
for pilots



 None for pilots



 Maximum number based
on number of injectors





 Depths are estimates
based upon relationship
to reservoir depth.




 Calculated from
reservoir area

 Based on inj. rate
                                                                                           57

-------
Table A2 - Depleted Gas Pilot Scale Project
Power Plant, Injection Rate, and Monitoring
MW Power Plant
90% Capture (CO2 tonnes/day)
Capacity Utilization
Tons per Year
Storage facility injection life in years
Tons for facility
Post-injection monitoring period in years

112
2,419
0.85
750,557
7
5,253,898
10

Injection Zone Depth, Pressure, and Temperature
Depth to Top of Injection Interval (ft)
Depth to Bottom of Injection Interval (ft)
Hydrostatic pressure (psi)
Temp(F) @1dF/100ft
Hydrostatic pressure (Mpa)
Temp. (C)
CO2 density (kg/cu.m)

7,200
7,500
3,248
137
22.4
58.3
789.0

Volumetrics and Capacity
Gross thickness (ft)
Net thickness (ft)
Porosity (%)
Area (sq. mi.)
Area (sq. ft.)
Pore space volume (cu. ft)
Pore space volume (cu. m)
Million tonnes capacity at 100% storage efficiency
Storage efficiency
Effective Million tonnes capacity

300
200
15%
15.0
418,176,000
12,545,280,000
355,242,434
280
10.0%
28.0
                                                                Equivalent to 750,000 tons/yr
                                                                 ' Actual typical area from database analysis




Old Wells in Area
Deep Artificial Penetrations (exclude any to be used as
injectors)
Shallow Artificial Penetrations
Water Wells Artificial Penetrations




InAoR

30
30
30
Additional
Known to Wells w/o
Require Good
Remediati Cement
on Logs

3.0 4.5
3.0 4.5
3.0 4.5
                                                                                   One per square mile
                                                                                   Two per square mile
                                                                                   Two per square mile
                                                                                                           58

-------
Table A2 (Continued) Depleted Gas Pilot Scale Project
Injection Wells and Stratigraphic Wells
Injection Wells Required (total)
Injection Wells New Drills
Injection Wells Conversions of Old Wells
Cost of Converted Wells as % of New
Tubing Size (inches)
Number of Stratigraphic Tests (if required)
Depth of Stratigraphic Tests (feet)
Cores per Stratigraphic Test

1.0
1.0
0
15%
6.0
0
8,250
6


Monitoring Wells, etc.
Max. Number of Monitoring Wells (depends on scenario)
Depth of Monitoring Wells (feet)
Long-string Casing of Monitoring Wells (diam. inches)
Air/soil Sampling Stations (if required)
Passive seismic arrays (inside monitoring wells if
required)
Into Inj
Above I nj Zone Zone
4 4
4,150 7,425
3.5 3.5
4

3

USDW's and Containment Systems
Deepest USDW
Second Containment System Depth to Top (ft)
Second Containment System Depth to Bottom (ft)
First Containment System Depth to Top (ft)
First Containment System Depth to Bottom (ft)

2,000
5,100
5,400
6,300
6,700

CO2 Pipelines and Pumps

Distribution Pipeline 1
Distribution Pipeline 2
Total inch-miles
Pump HP

Miles (inches)
3.9 6
0.0 4
23
290

 One injector well
for pilots



 None for pilots




 Maximum number based
on number of injectors





 Depths are estimates
based upon relationship
to reservoir depth.




 Calculated from
reservoir area

 Based on inj. rate
                                                                                          59

-------
Table A3 - Depleted Oil Pilot Scale Project
Power Plant, Injection Rate, and Monitoring
MW Power Plant
90% Capture (CO2 tonnes/day)
Capacity Utilization
Tons per Year
Storage facility injection life in years
Tons for facility
Post-injection monitoring period in years

112
2,419
0.85
750,557
7
5,253,898
10

Injection Zone Depth, Pressure, and Temperature
Depth to Top of Injection Interval (ft)
Depth to Bottom of Injection Interval (ft)
Hydrostatic pressure (psi)
Temp(F) @1dF/100ft
Hydrostatic pressure (Mpa)
Temp. (C)
CO2 density (kg/cu.m)

4,600
5,000
2,165
112
14.9
44.4
758.0

Volumetrics and Capacity
Gross thickness (ft)
Net thickness (ft)
Porosity (%)
Area (sq. mi.)
Area (sq. ft.)
Pore space volume (cu. ft)
Pore space volume (cu. m)
Million tonnes capacity at 100% storage efficiency
Storage efficiency
Effective Million tonnes capacity

400
200
15%
20
557,568,000
16,727,040,000
473,656,579
359
10.0%
36
                                                            : Equivalent to 750,000 tons, year
                                                            Actual area from database analysis



Old Wells in Area
Deep Artificial Penetrations (exclude any to be used
as injectors)
Shallow Artificial Penetrations
Water Wells Artificial Penetrations

Known to
Require
In AoR Remediation

160 16.0
40 4.0
40 4.0
Additional
Wells w/o
Good Cement
Logs

24.0
6.0
6.0
                                                                                      One per square mile
                                                                                      Two per square mile
                                                                                      Two per square mile
                                                                                                              60

-------
Table A3 (Continued) Depleted Oil Pilot Scale Project
Injection Wells and Stratigraphic Wells
Injection Wells Required (total)
Injection Wells New Drills
Injection Wells Conversions of Old Wells
Cost of Converted Wells as % of New
Tubing Size (inches)
Number of Stratigraphic Tests (if required)
Depth of Stratigraphic Tests (feet)
Cores per Stratigraphic Test

1.0
1.0
0
15%
6.0
0
5,500
6

Monitoring Wells, etc.
Max. Number of Monitoring Wells (depends on scenari
Depth of Monitoring Wells (feet)
Long-string Casing of Monitoring Wells (diam. inches)
Air/soil Sampling Stations (if required)
Passive seismic arrays (inside monitoring wells if
required)
Above Inj Zone Into Inj Zone
4 4
2,700 4,900
3.5 3.5
5

4

USDW's and Containment Systems
Deepest USDW
Second Containment System Depth to Top (ft)
Second Containment System Depth to Bottom (ft)
First Containment System Depth to Top (ft)
First Containment System Depth to Bottom (ft)

1,700
2,500
2,800
3,700
4,100

CO2 Pipelines and Pumps

Distribution Pipeline 1
Distribution Pipeline 2
Total inch-miles
Pump HP

Miles Diam (inches)
4.5 6
0.0 4
27
290

 One injector well
for pilots



 None for pilots



 Maximum number based
on number of injectors





 Depths are estimates
based upon relationship
to reservoir depth.




 Calculated from
reservoir area

 Based on inj. rate
                                                                                           61

-------