## Geologic CO 2 

## Sequestration Technology and Cost AnalysisOffice of Water (4606-M) EPA 816-R10-008 November 2010 http://water.epa.gov/drink/i 

## Table of Contents

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

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

C OSTING M ETHODOLOGY

.............................................................................................................................. ................. 3 P RIMARY D ATA S OURCES FOR C OSTS ............................................................................................................................ 3 C OST Y EAR B ASIS AND T RENDS IN M AJOR C OSTS ......................................................................................................... 5

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

3.1 S ITE C HARACTERIZATION

.............................................................................................................................. .......... 9 Maps and Cro ss Sections ....................................................................................................... ................................... 9 Seismic Su rveys ............................................................................................................... .......................................... 9 Seismic (Earthqu ake) History .................................................................................................. ............................... 10 Remote Land Survey ............................................................................................................ .................................... 10 Data on Extent, Thickness, Capacity, Porosity of Receivi ng Formations ......................................................... ...... 10 Geomechanical Informa tion

..................................................................................................... ............................... 11 Potentially Affected Underground So urces of Drinking Water (USDWs) ............................................................ ... 11 Geochemical and Other Info rmation on Formations ............................................................................... ............... 12 Information on Water- Rock Geochemistry ........................................................................................ ...................... 12 List of Penetrations of Injection Zone ........................................................................................ ............................. 12 List of Penetrations of Containment System .................................................................................... ........................ 13 List of Water Wells with in Area of Review ..................................................................................... ......................... 13 Geologic Characterization Report .............................................................................................. ............................ 13 Geologic Site Characte rization Un it Costs ..................................................................................... ........................ 13 3.2 M ONITORING

.............................................................................................................................. ........................... 15 Develop Geochemical Baselin e of Forma tion Water ............................................................................... ............... 15 Eddy Covariance Ai r Monitoring ................................................................................................ ............................ 17 Front-End Engineering and Design- Monitoring Wells ............................................................................ .............. 18 Rights of Way for Surface Use – Monitori ng Wells and Air Mo nitoring Sites ..................................................... ... 18 Downhole Safety Va lve or Check Valve .......................................................................................... ........................ 18 Standard Monitori ng Well Costs ................................................................................................ ............................. 18 Pressure and Temperature Gauges and Equipment for Mon itoring Wells ............................................................ . 19 Salinity, CO 2 ,

and Tracer Equipment for Monitori ng Wells ................................................................................... 19 Develop Plan and Implement Eddy Covariance Air Monitori ng ..................................................................... ....... 20 Develop Plan and Implement Digital Color Infrar ed Ortho-imagery and Hy per-spectral Imaging ....................... 20 Develop Plan and Implement LIDAR Airborne Survey .............................................................................. ............. 21 Develop Plan and Implemen t Soil Zone M onitori ng ............................................................................... ................ 21 Develop Plan and Implement Vadose Zone Monito ring ............................................................................. ............. 22 Develop Plan and Implemen t Water Table Monito ring ............................................................................. ............. 22 Periodic Monitoring of Groundwate r Quality and Ge ochemistry ................................................................... ........ 22 Surface Microseism ic Equi pment ................................................................................................ ............................ 22 Monitoring Well O&M Costs - Above Injection Zone .............................................................................. ............... 23 Monitoring Well O&M Costs - Into Injec tion Zone ............................................................................... ................. 23 U-Tube Sampling O&M – Enhanced Recovery ....................................................................................... ................ 23 Annual Costs of Air and Soil Surveys – Eddy Covariance ........................................................................ .............. 23 Annual Costs of Air and Soil Surveys – Digital Color Infrared Orthoimagery or Hyperspectral Imaging ............ 24 Annual Costs of Air an d Soil Surveys –LIDAR.................................................................................... .................... 24 Annual Costs of Air and Soil Su rveys –Soil Zone Monitoring .................................................................... ............. 24 Annual Costs of Air and Soil Sur veys –Vadose Zone Monito ring .................................................................. ......... 24 Annual Costs of Air and Soil Sur veys – Samples from Water Table ............................................................... ........ 24 Annual Cost of Passive Seismic Eq uipment ...................................................................................... ...................... 24 Periodic Seismic Surveys – 3D ................................................................................................. ............................... 24ii Complex Modeling of Flui d Flows and Migra tion ................................................................................. ................. 25 Reports to Re gulators ......................................................................................................... ..................................... 26 Monitoring Unit Co sts ......................................................................................................... .................................... 26 3.3 I NJECTION W ELL C ONSTRUCTION .......................................................................................................................... 29 Front End Engineer ing and Design .............................................................................................. .......................... 29 Rights of Way for Surface Uses ................................................................................................ ............................... 29 Lease Rights for Subs urface Pore Space ........................................................................................ ......................... 29 Land Use, Air Emission s, and Water Permits .................................................................................... ..................... 29 UIC Permit Filing ............................................................................................................. ...................................... 30 Standard Injection Well Drilling Cost ......................................................................................... ............................ 30 Well Stimul ation .............................................................................................................. ........................................ 31 Corrosion Resistant Tu bing and Casing ......................................................................................... ........................ 31 Cementing of the Inj ection Well Casing ........................................................................................ .......................... 32 Use of CO 2 -Resistant Cement ............................................................................................................. ..................... 32 Pumps ......................................................................................................................... ............................................. 33 Wellhead Control Equipment .................................................................................................... .............................. 33 Pipeline Costs ................................................................................................................ .......................................... 34 Injection Well Constr uction Unit Costs ........................................................................................ ........................... 35 3.4 A REA OF R EVIEW AND C ORRECTIVE A CTION ........................................................................................................ 37 Simple Fluid Flow Calculations to Predict CO 2 Flow ............................................................................................ 37 Complex Modeling of CO 2 Fluid Flow ................................................................................................................... . 37 Aerial Survey to Find Old Wells ............................................................................................... ............................... 37 Evaluate Mechanical Integrity of Existing Wells Penetrating C ontainment System ............................................... 37 Evaluate Integrity of Shallow Wells ........................................................................................... ............................. 38 Remediate Old Wells in Area of Review ......................................................................................... ......................... 39 Area of Review and Corr ective Action Unit Co sts ............................................................................... ................... 39 3.5 W ELL O PERATION

............................................................................................................................... ................... 41 Corrosion Monitoring and Prevention Program ................................................................................... .................. 41 Corrosion Mo nitori ng .......................................................................................................... ................................... 41 Measuring and Monito ring Equipment ............................................................................................ ....................... 41 Equipment to Add Tracers ...................................................................................................... ................................. 41 Electricity Costs for Pumps and Equipment ..................................................................................... ....................... 42 Injection Well Operating and Maintena nce Costs ................................................................................ .................. 42 Land Use Rents an d Right of Way ............................................................................................... ............................ 43 Pore Space Unit Co sts ......................................................................................................... .................................... 43 Property Taxes and Insurance .................................................................................................. .............................. 43 Tracers in Inj ected Fl uid ..................................................................................................... .................................... 43 Repair or Replace We lls and Equipment ......................................................................................... ........................ 43 General Failure of Containment Site – Remove and Relocate CO 2 ........................................................................ 43 Well Operation Unit Costs ..................................................................................................... ................................. 43 3.6 M ECHANICAL I NTEGRITY T ESTS ............................................................................................................................ 4 5 Internal Mechanical Integrity Tests ........................................................................................... ............................. 45 Casing Insp ection Log ......................................................................................................... .................................... 45 Radioactive Tracer Survey of Bottom Hole Cement ............................................................................... ................. 46 External Mechanical Integrity Test ............................................................................................ ............................. 46 Pressure Fa lloff Te sts ........................................................................................................ ...................................... 46 Mechanical Integrity Te st Unit Costs .......................................................................................... ............................ 46 3.7 W ELL P LUGGING , E QUIPMENT R EMOVAL , AND P OST -I NJECTION S ITE C ARE (PISC) ............................................. 47 Flush Wells with Buffer Fluid before Plugging ................................................................................. ...................... 47 Plug Injec tion We lls .......................................................................................................... ...................................... 47 Perform Mechanical Integrity Test Prior to Plug ging ........................................................................... ................. 48 Plug Monitori ng Wells ......................................................................................................... ................................... 48 Remove Surface Equipment, Stru ctures, Restore Vegetation ...................................................................... ............ 48 Document Plugging and Post-Injection Process .................................................................................. ................... 48 PISC Monitori ng Well O&M ...................................................................................................... ............................. 49 Post-Injection Air and Soil Surveys ........................................................................................... .............................. 49iii Post- Injection Se ismic Surveys ............................................................................................... ................................ 49 Post- Injection Repo rts to Regulators ......................................................................................... ............................ 49 Well Plugging, Equipment Remo val, and PISC Unit Costs ......................................................................... ............ 49 3.8 F INANCIAL R ESPONSIBILITY

.............................................................................................................................. .... 51 Performance Bond or Demonstration of Financial Ability to Close Site .......................................................... ...... 51 Performance Bond or Demonstratio n of Financial Ab ility for PISC ............................................................... ....... 51 Financial Responsib ility Unit Costs ........................................................................................... ............................. 51

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

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

## List of Tables

Table 1: Major Sources of GS Cost Information ................................................................................. ............. 4 Table 2: Geologic Site Ch aracterization Unit Costs ............................................................................ ........... 14 Table 3: Monitoring Unit Costs ................................................................................................ ...................... 27 Table 4: Injection Well Construction Unit Costs ............................................................................... ............. 36 Table 5: Area of Review and Corrective Action Unit Costs ...................................................................... ..... 40 Table 6: Well Operation Unit Costs ............................................................................................ .................... 44 Table 7: Mechanical Inte grity Tests Unit Costs ................................................................................ .............. 47 Table 8: Well Plugging, Equipment Removal, and PISC Costs ..................................................................... 50 Table 9: Financial R esponsibility Unit Costs .................................................................................. ................ 51



## List of Figures

Figure 1: U.S. Carbon Steel Plate Prices ...................................................................................... ..................... 6 Figure 2: Nickel Prices ....................................................................................................... ............................... 7 Figure 3: Gas Pipeline Costs by Component ..................................................................................... ............... 7 Figure 4: U.S. Drilli ng Rig Day Rates ......................................................................................... ..................... 8 Figure 5: Diagram of Typical CO 2 Injection Wellhead .................................................................................. 34Technology and Cost Document for the final GS Rule 1 November 2010 

## 1 Introduction

The Environmental Protection Agency (EPA) ha s developed new minimum Federal requirements under the Safe Drinking Water Act (SDWA) fo r underground injection of carbon dioxide (CO 2 ) for the purpose of geologic sequestration (GS). The elements of this rulemaking are based on the existing Underground Injection C ontrol (UIC) Program regulatory framework, creating a Class VI well classification that addre sses the unique nature of CO 2 injection for GS. This rule will help to ensure consistency in permitting underground injection of CO 2 at GS operations across the United States. The requirements are desi gned to prevent endangerment of underground sources of drinking water (USDWs) in anticipation of the eventual use of GS to reduce CO 2 emissions to the atmosphere.

This Geologic CO 2 Sequestration Technology and Cost Anal ysis document (Technology and Cost document) describes the unit costs of specific technologies and operati ng practices that are expected to apply to GS activitie s. It does not discuss in any deta il the development of overall costs for the final rule, which is presented in Chap ter 5 of the Cost Analysis for the final rule 1 . As described in that chapter, EPA be lieves that projects will deploy in primarily two types of geologic settings during the period of analysis: saline formations and oil and gas reservoirs (enhanced recovery (ER) sites). 2,3 The costs and risk assessments for th ese two project types were developed under the five different regulatory alternatives co nsidered in the Cost Analysis, including one baseline alternative that repres ents EPA’s understanding of the cost s and risks if it were to deploy under current UIC regulation (absent a Class VI regulation). Each of the unit costs presented in this Technology and Cost document applies to at l east one and usually more of the regulatory alternatives considered to varying degrees. A cost that is incurred under a given regulatory alternative and also under the ex isting Class I non-hazardous in jection well regulations (the regulatory baseline for this anal ysis) is not attributable to th e regulatory alternative but are presented in the analysis for completeness.

The SDWA provides EPA with the authority to develop regulations to protect USDWs from endangerment; however, it does not provi de authority to deve lop regulations for all areas related to GS. This document includes all unit costs associated with GS, not just thos e specific to preventing

1 Cost Analysis for the Federal Requirements Under the U nderground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule), EPA 816-R-10-013. The Cost Analysis presents development of the final rule costs, taking into account the unit costs presented in the Technology and Cost document, the schedule (periodicity) of cost incurrence, the baseline number of projects estimated to deploy, the types of projects (saline and ER) anticipated and the geological and engi neering parameters associated with them.
2 EPA understands that the primary purpose of most CO 2 injection operations located in depleting oil and gas reservoirs will be to enhance recovery of oil and gas until it is no longer economically feasible. Under this scenario, these operations would be covered under the existing Class II injection well regulations. An exception is the conversion of an operation whose primary purpose changes from enhanced recovery to the long term storage of CO 2 in an effort to reduce emissions to the atmosphere. In such a case, the new rule would apply.
3 There are other possible target formations for GS, including but not limited to coal seams, basalts, salt domes, and shales, as described further in the Preamble to the Final GS Rule. The GS rule does not categorically preclude or prohibit injection into any type of formation, but expects th at the majority of GS project s will involve saline reservoirs and converted ER projects.Technology and Cost Document for the final GS Rule 2 November 2010 endangerment to USDWs. GS costs are incurred in the pre-injection, or construction and permitting phase, throughout the injection phase, and during post-injection site care (PISC). However, GS components do not include carbon capture and CO 2 transportation to the GS site. The GS component is estimated to be approximately 2.7 per cent of the total cost of an integrated capture and sequestration project, as described in the Preamble to the Final GS Rule.

The major cost categories included in the Cost Analysis for the fina l rule are: site characterization, well construction and operation, mo nitoring during operations, area of review and corrective action, and financial responsibility. The sections of this document that follow describe the unit costs specific to each category.

EPA applied a unit cost multiplier to existing uni t costs (e.g. monitoring) to account for the few potential cases where a waiver of the required in jection depth would be permitted. These and other applicability factors are presen ted in Appendix B (Project Algorithms) of the Cost Analysis. 4

4 Cost Analysis for the Final GS Rule, EPA 816-R-10-008.Technology and Cost Document for the final GS Rule 3 November 2010 

## 2 General Costing Methodology, Data Sources, and Cost Trends

Costing Methodology This Technology and Cost document evaluates th e individual cost components for GS. These are termed unit costs and are categorized as follows:

 Site Characterization

 Area of Review and Corrective Action

 Injection Well Construction

 Mechanical Integrity Tests

 Monitoring

 Injection Well Operation

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

 Financial Responsibility

Unit costs are specified in terms of cost per site , per well, per square m ile, or other appropriate parameter depending on the characteristics of the cost item. Unit costs are applied to pro forma projects presented in the Cost Analysis for this rule. 5 The pro forma descriptions include specifications for total surface area, drilling depth, reservoir thickness, well injectivity, number of wells through time, and other parameters.

In the cost analysis, costs are estimated for a base line regulatory case, assumed to be equivalent to a Class I Non-Hazardous Industrial In jection Well, and four proposed regulatory alternatives. Each cost item has been evaluated as to whether it is required under each regulatory alternative, and whether the cost will apply to all future projects or to a fraction of projects. In many cases, specific cost components and technologies will be applied to the GS project regardless of which regulatory alternative is chosen. For these cost components, there is no cost difference among the regulations. Other cost components may be a pplicable only under particular re gulatory alternatives. Thus, not all of the unit costs included in this analysis are attributable to a particul ar regulatory alternative.

Primary Data Sources for Costs

Table 1 summarizes the major data sources for costs in the analysis. A wide range of cost data are available from industry survey publications for cost s typically incurred in oil and gas drilling and production operations. This incl udes drilling and completion cost s by region and depth interval, equipment and operating costs, a nd pipeline costs. Data are available for both the United States. and Canada. 6,7,8,9 The cost of drilling and equipping wells represents a larg e component of

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

6 Joint Association Survey of Drilling Costs , American Petroleum Institute, Washington, DC. http://www.api.org/statistic s/accessapi/api-reports.cfm

7 PSAC Well Cost Study – 2009, Petroleum Services Association of Canada, April 30, 2009 and later editions.Technology and Cost Document for the final GS Rule 4 November 2010 Table 1: Major Sources of GS Cost Information

API Joint Association Survey of Drilling Costs Drilli ng costs in the U.S. for oil, gas, and dry holes by depth interval EIA Oil and Gas Lease Equipment and Operating Cost Survey Surface equipment costs, annual operating costs, pump costs Pipeline Prime Mover and Compressor Costs (FERC) Pumps

2009 Petroleum Services of Canada Well Cost Study (PSAC) Canada drilling costs, plugging costs, logging costs

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

Land Rig Newsletter Onshore day rates/ well cost algorithms New Orleans Sequestration Technology Meeting, January, 2008 Monitor station costs in several categories; seismic
costs FutureGen Sequestration Site Materials Monito ring station layout/number of stations Preston Pipe Report Casing and tubing costs U.S. Bureau of Labor Statistics, American Association of Petroleum Geologists, Society of Petroleum Engineers Hourly labor rates

Selected presentations and papers (see below) Sens or costs, monitoring costs, number of stations, seismic costs Benson, "Monitoring Protocols and Life Cycle Costs for Geologic Storage of Carbon Dioxide", Sept., 2004 IEA Greenhouse Gas Programme Report PH4/29, "Overview of Monitoring Requirements for Geologic Storage Projects, Nov., 2004. Hoversten, "Investigation of Novel Geophysical Techniques for Monitoring CO2 Movement During Sequestration," Oct., 2003. Dahowski, et al, " The Costs of Applying Carbon Dioxide Capture and Geologic Storage Technologies to Two Hypothetical Coal to Liquids Production Configurations: A Preliminary Estimation," Pacific NW National Laboratory, September, 2007.

GS costs. The costs of additional equipment or material specifications for CO 2 injection wells are based in part upon various sources for corrosion re sistant materials and sp ecific well components.

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

Labor rates are obtained from the U.S. Bureau of Labor Statistics and from surveys of oil and gas professionals performed by the American Associa tion of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers ( SPE). Labor rates include a “loa d factor” from EPA guidance. The number of hours estimated for implementation of the various character ization or monitoring activities represent EPA’s best professional judgment, informed by and modified in response to public comment.

8 Oil and Gas Lease Equipment and Operating Costs , U.S. Energy Information Administration, 2007 and later editions, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publi cations/cost_indices_equipment_production/current/coststu dy.html
9 Oil and Gas Journal Pipeline Cost Survey , Oil and Gas Journal Magazine, September, 2009.Technology and Cost Document for the final GS Rule 5 November 2010 Because some GS technologies ar e still under development, no comp rehensive source is available that provides detailed summaries of the full range of GS project cost components. Estimates of the costs of monitoring equipment, the number of st ations required, and the co st of ongoing monitoring are based upon analysis of av ailable literature and recent pr esentations by government and academic research groups. Some specific monitori ng costs were obtained at an industry meeting sponsored by the Groundwater Protection Council. 10

Cost Year Basis and Trends in Major Costs

The costs reported here and used in the cost analysis represent price levels in late 2007, inflated to 2008 using the Consumer Price Index inflationary factor. Use of the 2007 price level avoids some of the extreme cost fluctuations seen in the 2008-2009 period. For the purpose of providing context for discussion, recent historical cost trends are presented in the figures below in nominal dollars. There have been very steep increases in the cost of materials and labor used in the construction of all types of energy infrastructure including power plants, pipelines and oil and gas wells. Figure 1 shows the recent history of cost per ton of carbon steel plate (used in line pipe, casing, pressure vessels, etc.) and Figure 2 shows similar data for nickel (used in corrosion resistant tubing and casing and cryogenic applications such as LNG liquefaction plants and LNG storage tanks). Steel prices have declined since peak ing in 2008, but are higher than in the early 2000s. Figure 3 shows the cost of natural gas pipeline construction a nd Figure 4 shows the average day rate for onshore drilling rigs in the US.

A discussion of uncertainty in cost estimation fo r this study is presented as Section 5 of this Technology and Cost document.

10 Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008.Technology and Cost Document for the final GS Rule 6 November 2010 Figure 1: U.S. Carbon Steel Plate Prices

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600

2001-01 2002-01 2003-01 2004-01 2005-01 2006-01 2007-01 2008-01 2009-01
DateUS Dollars per Short Ton

Domestic plate A36 (FOB US Midwest mill) from BloombergTechnology and Cost Document for the final GS Rule 7 November 2010 Figure 2: Nickel Prices

$0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010US Dollars per Short Ton

Figure 3: Gas Pipeline Costs by Component

$0 $10,000 $20,000 $30,000 $40,000 $50,000 $60,000 $70,000 $80,000 $90,000 $100,000

200

9 200

8 2007 2006 2005 200

4 200

3 2002 2001 2000 19

99 199

8 1997 1996 1995 19

94 199

3Dollars per Inch-Mile Misc. R.O.W. Labor Material

A verage of large-diameter gas pipelines 30 to 36 inches FERC data compiled by Oil & Gas JournalTechnology and Cost Document for the final GS Rule 8 November 2010 Figure 4: U.S. Drilling Rig Day Rates

$0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000Q1.99Q2.99Q3.99Q4.99Q1.00Q2.00Q3.00Q4.00Q1.01Q2.01Q3.01Q4.01Q1.02Q2.02Q3.02Q4.02Q1.03Q2.03Q3.03Q4.03Q1.04Q2.04Q3.04Q4.04Q1.05Q2.05Q3.05Q4.05Q1.06Q2.06Q3.06Q4.06Q1.07Q2.07Q3.07Q4.07Q1.08Q2.08Q3.08Q4.08Q1.09Q2.09Q3.09Q4.09Q1.10

QuarterDollars per DayTechnology and Cost Document for the final GS Rule 9 November 2010 

## 3 Technologies and Costs

3.1 Site Characterization

Site characterization is a fundame ntal component of the UIC progr am. Owners or operators must identify the presence of suitable geologic charact eristics at a site to ensure the protection of USDWs from endangerment associated with inj ection activities. To accomplish this, site characterization includes an assessment of th e geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS s ite. Characterization is designed to provide the geologic and hydrologic data and needed to desi gn the infrastructure, develop computational models, determine appropriate operation parameters , and design the monitoring program. In this phase of site development, a determination is ma de of whether the formation has adequate porosity, permeability, and continuity for long term injection. An assessment is also made about the ability of overlying units to restrict upw ard movement of the injected CO 2 and prevent the endangerment of USDWs. This includes evalua tion for the presence of non-seali ng faults or other potential pathways for migration. Other types of evaluatio n include geomechanical data on the mechanical properties of the reservoir, information on the occurrence and characteristics of USDWs, and information on past drilling into the proposed injection zone and overlying formation.

Maps and Cross Sections

The basic element of geologic analysis and character ization is the developmen t of regional and sitespecific geologic maps and cross sections to prov ide an understanding of stratigraphy and structure. The primary source of information for this analysis is well log data, which allows the geologist to map the depth to various formation tops, thickn ess variations (i.e., wi th isopach maps), and lithologies (e.g., sandstone, shale, or carbonates). Where available, seismic or other geophysical and engineering data are also used to aid th e development of the subsurface interpretation.

Seismic Surveys

Seismic data acquisition and interp retation is an important aspect of site characterization. Seismic data will be acquired either on th e surface, or in a well. Borehole techniques require one or more wells for sources and receivers. Su rface seismic data can be either two-dimensional (2-D) or threedimensional (3-D), with the latter providing a high er degree of resolution but being much more data intensive and costly to obtain and interpret. Se ismic data may also be used for monitoring during operations and PISC. 11

3-D seismic techniques use man-made source signal s and a receiver array to image the subsurface. In the site characterization phase , 3-D seismic surveys may be used to evaluate the detailed

11 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregena lliance.org, December 1, 2006.Technology and Cost Document for the final GS Rule 10 November 2010 structural geology and stratigraphy of the site. 3-D seismic data may also be used in the site characterization phase to inform computat ional models to estimate the volume of CO 2 that can be stored at a potential site. 12 The technology is mature and has been used in the oil and gas exploration and development for decades.

The cost of 3-D seismic acquisition varies widely, ranging from $40,000 to $160,000 per square mile. 13 14 15 Factors other than area affecting cost in clude acquisition para meters, terrain, geology, reservoir depth, and remoteness of location. A recen t large seismic survey by a major operator in Louisiana averaged $85,000 per square mile. 16 A Canadian study indicate d a range in cost of $21,000 to $104,000 per square mile. 17 A cost of $100,000 per square mile has been cited in industry articles as an averag e for the United States onshore.

Seismic (Earthquake) History

The natural long-term seismic history of a potential GS site must be evaluate d to gain a picture of potential failure risks, including the inherent potential for a seismic event and for induced seismicity. Historic data on seismic activity ca n be obtained from the U.S. Geological Survey. Evaluation will include the frequency and intensity of historic activity and its relationship to known geology. The presence of regional fa ults and the activity on those fa ults is of significance in assessing site suitability.

Remote Land Survey

An airborne survey of the poten tial site may be carried out to locate and identify dwellings and other manmade structures affected within the area of review. The AoR is defined in the final rule as “the region surrounding the geologi c sequestration project where USDWs may be endangered by the injection activity. The AoR is delineated us ing computational modeling that accounts for the physical and chemical properties of all phases of the injected CO 2 stream and is based on available site characterization, monitoring, and operational data as set forth in §146.84” of the rule.

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

Perhaps the most fundamental aspect of site char acterization is the determ ination of the receiving and storage properties of the proposed injection zone interval. In orde r to develop the analysis, it is necessary to obtain regional well log, well hist ory, pressure test, and other subsurface data.

12 Doughty, Christine, Barry Freifeld, and Robe rt Trautz, 2007, “Site Characterization for CO 2 Geologic Storage,” Environmental Geology , vol. 54, no. 8, June 2008.
13 McFarland, John, 2009, “How Do Seismic Surveys Work?” http://www.oilandgaslawyerblog.com/2009/04/how-doseismic-survey s-work.html
14 Dix, Manfred and Greg Albrecht, 2008, “An Economic Impact Analysis of the Haynesville Shale Natural Gas Exploration, Drilling, and Production,” Louisiana Depa rtment of Natural Resources report, August, 2008 http://dnr.louisiana.gov/haynesvilleshale/manfred-dix-impact-analysis.pdf
15 Percival, Pamela, 2008, “Chesapeake Exec Discusses 3D Seismic in Major Shale Plays,” Basin Oil and Gas Magazine , May 2010.
16 Hill, Kevin. B., 2010?, “A Seismic Oil and Gas Pr imer,” Hill Geophysical Consulting, Shreveport, LA. http://www.loga.la/flash/HS/kevinhillLSUS.pdf
17 Cooper, N.M, 2010, “The Value of 3D Seismic in Today’s Exploration Environment – In Canada and Around the World,” Mustagh Resources , Calgary, Alberta. www.mustagh.com/ab stract/opi_3D.docTechnology and Cost Document for the final GS Rule 11 November 2010 Included is the acquisition of core data, drill stem test data, producti on test data, and other engineering data on wells in the AoR. The geolog ist uses this information to map the thickness, structure, and injection zone char acteristics in the subsurface. The goal is to fully evaluate storage capacity and injectivity, and the e xpected variability in these parameters. Some sites, such as depleting oil or gas fields, will have a large amount of existing subsurface data in a specific area. In saline formations, the amount of subsurface data may be limited or more regional in distribution.

Geomechanical Information

The mechanical properties of a potential storage rese rvoir play an important role in its ability to withstand injection pressures. If not designed properly, CO 2 injection could lead to deformation of the injection zone or confining ro ck, resulting in fracturing and poten tial leakage that may endanger USDWs. 18 19 The maximum injection pressure for CO 2 must be less than the formation fracture pressure at the depth of injection. If the injecti on pressure exceeds the fract ure 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 an d literature as well as from ne w cores and tests. Sources of geomechanical data include well logs, seismic, pressure fall-off tests, and direct physical measurements of rock strength in the laborat ory. Data parameters include pore pressure, overburden stress, horizontal st ress and orientation, elastic st rength, and expected failure mechanisms.

Potentially Affected Underground So urces of Drinking Water (USDWs)

A major consideration in site sele ction and design is the protection of USDWs. As part of the site permitting process, the operator must determine the distribution and depth of all potentially affected USDWs.

EPA defines USDWs as follows:

An aquifer or portion of an aquifer that supplie s any public water system or that contains a sufficient quantity of ground water to supply a public water system, and currently supplies drinking water for human consumption, or th at contains fewer than 10,000 mg/l total dissolved solids and is not an exempted aquifer. 20

This cost element is based upon the cost of rese arching information on th e distribution of USDWs in the vicinity of the GS site. Such information ca n be found in the literature or in public well logs.

18 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage , by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.
19 Measuring and Modeling for Site Characterization: A Global Approach , D. Vu-Hoang, L. Jammes, O. Faivre, and T.S. Ramakrishnan, Schlumberger Carbon Services, March, 2006.

20 US EPA website, Office of Water, Underground Injection Control: http://www.epa.gov/safewate r/uic/glossary.html#t

.Technology and Cost Document for the final GS Rule 12 November 2010 Geochemical and Other Information on Formations

In addition to determining the distribution of US DWs at the proposed site, owners and operators must obtain data on the geochemical water properties of regional formations, as well as an overall understanding of their regional th ickness and structure. Informa tion on formation water in the potential injection zone may be obtained from nearby well logs or from water samples from nearby wells. This cost element is based upon the time re quired to research and ev aluate this information from public data sources in unit cost A-6 and from new cores and tests in unit cost A-7 in Table 2 below.

Information on Water-Rock Geochemistry

The geochemistry of subsurface fluids can affect wh ether a site is suitable for GS. Injection of CO 2 can result in the presence of carbonic acid, which can react with injection zone rock to liberate heavy metals. Another consideration is whether ce rtain minerals may be precipitated that would plug the pore space, reducing permeability and reducing the ability to inject CO 2 . Therefore, another requirement during site char acterization is the analysis of the chemical characteristics of the formation water and the potential reactiv ity of the injection zone rock with CO 2 . Information on formation water characteristics may be obtained fr om nearby well logs or from water samples from nearby wells. Information on injection zone mine ralogy may be obtained fr om whole or sidewall cores, well cuttings or well logs in nearby wells. Analysis will lik ely include petrographic studies of thin sections of injection zone rock to dete rmine mineralogy. EPA expect s that laboratory tests will be conducted to evaluate chemical reactivit y to carbonic acid under injection zone conditions.

List of Penetrations of Injection Zone

The location and evaluation of exis ting penetrations into the inj ection zone within the area of review is a key component of site characteri zation. 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, a ll well penetrations must be loca ted and the condition of the wells and casing cement evaluated. It may be possible to correct issues with problematic existing wells. In some cases, the presence of such wells can make the use of a particular site for GS economically infeasible or pose undue risk of endangerment to USDWs.

Existing commercial oil and gas we ll history databases contain in formation on the location, depth, and other characteristics of most historic wells. Because some wells may not be in the database, an operator could also carry out a physical survey using airborne or ground-based magnetic methods to locate abandoned wells. Such co sts are included in item D-4 (AoR review). The co st of locating and evaluating existing penetrations into the injecti on zone is expected to vary widely based on the quality and coverage of availabl e well data, the assumption in the current analysis is that well database coverage is good and that magnetic tests are not needed in the site charac terization phase. Costs are based on EPA’s best professional judg ment regarding the number of hours needed to conduct the research and evaluate the findings.Technology and Cost Document for the final GS Rule 13 November 2010 List of Penetrations of Containment System

It is also important to determine the locati on, depth, and characteristics of wells that have penetrated the containment syst em within the area of review, but reached total depth before penetrating the storage injection zone because th ese wells could also represent potential leakage pathways. As with the previous item, the source of information is primarily commercially available well history databases. EPA expect s that the coverage in well hist ory databases is good and that magnetic tests will generally not be needed.

List of Water Wells within Area of Review

Determination of the location and depth of existing wa ter wells is an aspect of site characterization. Information may be obtained from databases of well locations or by site inspection. Site inspections would include activities such as la nd surveys and seismic surveys.

Geologic Characterization Report

Approval of a specific site for GS involves a thorough understanding of all of the geological characteristics, including the suitability of the re ceiving zone, storage capacity and injectivity, and that there is a competent confining system. Th e report must incorporate aspects of the site characterization studies, including geologic, geochemical, geomechanical, hydrological, and geophysical studies. It summarizes th e results of any pre-injection m odeling studies to evaluate the size and location of the expected CO 2 plume through time.

Geologic Site Characterization Unit Costs

Table 2 specifies the estimated costs and data sources for site characterization.Technology and Cost Document for the final GS Rule 14 November 2010 Table 2: Geologic Site Characterization Unit Costs

Tracking Number Cost Item Cost Algorithm Data Sources

A-1 Develop maps and cross sections of local geologic structure 60 hours of geologists @$107.23/hr = $6,434 p er site AAPG 2009 salary survey of petroleum geologists

A-2 Conduct 3D seismic survey to identify faults and fractures in primary and secondary containment units $104,000/square mile for good resolution Several published reports are in range of this cost. Cost depends on resolution

(number of lines shot) of survey.

A-3 Obtain and analyze seismic (earthquake) history. 60 hours of geologists @$107.23/hr = $6,434 per site AAPG 2009 salary survey of petroleum geologists

A-4 Remote (aerial) survey of land, land uses, structures etc.. Should assume survey is twice the project's actual CO2 footprint due to uncertainty during site characterization phase of exact location of facilities and p lume. $3,100/site + $415/square mile surveyed. (Should assume survey is

twice project's actual footprint.) Advertised cost of an aerial survey company for high-resolution (1/2 meter).

A-5 Obtain data on areal extent, thickness, capacity, porosity and permeability of receiving formations and confining systems 24 hours of geologists @$107.23/hr = $2,574 per site AAPG 2009 salary survey of petroleum geologists

A-6 Obtain geomechanical information on fractures, stress, rock strength, in situ fluid pressures (from existing data and literature ) 120 hours of geologists @$107.23/hr = $12,868 per site AAPG 2009 salary survey of petroleum geologists

A-7 Obtain geomechanical information on fractures, stress, rock strength, in situ fluid pressures (new cores and tests) $78/foot for stratigraphic test well + $3,100/core Drilling cost is estimated from drilling cost equations developed from JAS and PSAC data. Core analysis cost is best professional judgement.

A-8 List names and depth of all potentially affected USDWs 24 hours of geologists @$107.23/hr = $2,574 per site AAPG 2009 salary survey of petroleum geologists

A-9 Provide geochemical information and maps/cross section on subsurface a q uifers. 60 hours of geologists @$107.23/hr = $6,434 p er site AAPG 2009 salary survey of petroleum geologists

A-10 Provide information on water-rock-CO2 geochemistry and mineral reactions. 240 hours of geologists @$107.23/hr +$10,300 lab fees = $36,035 per site Best professional judgement of time required and lab fee.

A-11 Develop list of penetrations into injection zone within AoR (from well history data bases) 12 hours @$107.23/hr = $1,287 per square mile Best professional judgement of time required. Hourly rate derived from AAPG 2009 salary survey of petroleum geologists. Cost expected to vary widely based on well ages and quality of record keeping.

A-12 Develop list of penetrations into containment systems within AoR (from well history data bases) 12 hours @$107.23/hr = $1,287 per square mile Best professional judgement of time required. Hourly rate derived from AAPG 2009 salary survey of petroleum geologists. Cost expected to vary widely based on well ages and quality of record keeping.

A-13 Develop list of water wells within AoR (from public data) 36 hours @$107.23/hr = $3,860 per square mile Best professional judgement of time required. Hourly rate derived from AAPG 2009 salary survey of petroleum geologists. Cost expected to vary widely based on well ages and quality of record keeping.

A-14 Prepare geologic characterization report demonstrating: suitability of receiving zone, storage capacity and injectivity, trapping mechanism free of nonsealing faults, competent confinin g s y stem, etc. 240 hours of geologists @$107.23/hr = $25,735 per site Best professional judgement of time required. Hourly rate derived from AAPG 2009 salary survey of petroleum geologists.

A-15 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 15 November 2010 3.2 Monitoring

Once injection begins, a program for monitoring of conditions in the injection zone and CO 2 distribution is required. 21 This is needed in order to:

 Manage the injection process

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

 Verify and provide input in to computational models

 Provide early warnings of failure

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

 Analysis of the carbon dioxide stream

 Installation and use of con tinuous recording devices to monitor injection pressure, rate, and volume; the pressu re on the annulus between th e tubing and the long string casing; and the annulus fluid volume added

 Corrosion monitoring

 Monitoring of ground water quality and ge ochemical changes above the confining zone(s)

 A demonstration of mechanical integrity

 A pressure fall-off test

 Testing and monitoring to track the exte nt of the carbon dioxide plume and the presence or absence of elevated pressure

 Any additional monitoring required by the UIC Director

The GS rule provides more detailed and specific monitoring requirements. M onitoring of the wells, deep subsurface, shallow subsurface and ground surf ace is expected to continue for long periods after the injection is terminated for safety a nd to confirm predictions of storage behavior.

As mentioned in the Introduction to this Technology and Cost document, to cost the potential few cases where a waiver of the required injection depth would be permitted, EPA applied a unit cost multiplier to existing unit costs to account for the additional requirements, in particular for monitoring. These and other appli cability factors are pr esented in Appendix B (Project Algorithms) of the Cost Analysis. 22

Develop Geochemical Baseline of Formation Water

Prior to injection of CO 2 , owners and operators must develop a baseline of geochemical properties and characteristics of water in the injection zone s, confining zones, and USDWs. During injection or in the post-injection monito ring phase, regular sampling continues. In this way, changes in geochemistry through time can be interpreted, allo wing analysis of plume movement or leakage. Geochemical analysis of water samples includes the quantification of gases (methane, ethane, CO 2 ,

21 The Future of Coal, Options for a Carbon-constrained World , An Interdisciplinary MIT Study, Massachusetts Institute of Technology, 2007.

22 Cost Analysis for the Final GS Rule, EPA 816-R-10-013.Technology and Cost Document for the final GS Rule 16 November 2010 N 2 ), carbonate, and total alkalinity, metals (Na, K, Ca ), salinity (total dissol ved solids, or TDS), and stable isotopes (C, O). 23 24

Downhole fluid samples can be collected for surface analysis using wireline formation testers and U-Tube sampling devices. The Schlumberger Mo dular Formation Dynamics Tester (MDT) is a wireline tool that is used to collect multiple subsurface samples at formation pressure and temperature (PVT samples) for surface analysis. 25 U-Tube technology was developed for the DOE Frio Brine project and allows sample extracti on at injection zone pr essure and temperature. 26 As its name implies, it is a U-shaped tube device inserted in the well. A valve is opened to collect samples from the interval of interest at pressure a nd transport them to the surface for analysis.

It is necessary to establish a baseline of existing groundwater pr operties. After injection begins, periodic testing of groundwater can detect leak age. In many areas, local and regional groundwater wells will be present and are a source of data on chemical prope rties. New wells may also be needed for sampling. Geochemical analysis of water samples for parameters such as resistivity and pH are routine. For groundwater samples, Sc hlumberger has develope d the Westbay sampling system. This is a sampling assembly that is lowere d into a groundwater well of generally less than 3,300 feet in depth. Discrete samples can be taken fr om multiple intervals. The hardware can be left in place for subsequent testing. In sampling for CO 2 concentrations, care mu st be taken to account for rapid degassing of CO 2 from the water. Misleadingly lo w values can be obtained unless precautions are taken. 27

In depleted/depleting oil and gas formations, there may is a need to monitor for petroleum escaping from an oil field structure that is being filled with CO 2 . This could occur as injected CO 2 forces oily fluids down below the lowermost “spill-point” of an ER site or a CO 2 flood project that is converted to GS. Petroleum leaks could be detect ed by bringing up water samp les using a U-tube or other sampling system. A third option is a fi ber optic device which can monitor downhole concentrations of hydrocarbons in aquifers. The n ear-infra-red light sour ce (1.0-1.7 micrometers) and matching optical sensor are ke pt at the surface, linked by a fi ber optic cable bund le to the IR absorption path deep in the well. APS Technolog y, Inc. has developed such a system under the name PetroMax system. 28 The PetroMax system has complete d all laboratory tests and a field prototype has been designed. The PetroMax sy stem provides real-time monitoring of downhole fluid composition and provides continuous oil, wa ter and gas concentrations from multiple downhole locations. The PetroMax system dis tinguishes among chemicals passing the downhole

23 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregena lliance.org, December 1, 2006.
24 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide , S. Benson and L. Myer, Lawrence Berkeley Laboratory, Berkeley, California, 2002.
25 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregena lliance.org, December 1, 2006.
26 The U-Tube – Novel System for Sampling and Analyzing Mulit-Phase Borehole Fluid Samples , by Barry M. Freifeld, et al, Lawrence Berkeley National Laboratory , Berkeley, CA. (publication date unknown).
27 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2 , Report No. COAL R285 DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Be ntham, S. Holloway, and G. Kirby, British Geological Survey, Coordinator of the European Network of Excellence on Underground CO2 Storage (CO2GeoNet), Keyworth, Nottingham, UK, March 2005.
28 Bill Turner, APS Technology, “Downhole Fluid Analyzer Development, Phase I Final Report,” DOE Award DEAC26-98FT40481, U.S. Department of Energy, National Ener gy Technology Laboratory, Pittsburgh, PA, March, 2004. See also: http://www.aps-tech.com/other/ petromax.htm; and PetroMax brochure: http://www.aps-tech.com/tds/APSPetroMax.pdf

.Technology and Cost Document for the final GS Rule 17 November 2010 sensor by directly measuring the composition of th e downhole fluid. The light that is not absorbed in the sample volume returns to the surface a nd is analyzed and presented in real time.

Standard sampling and analysis is done by personnel at th e well site supplemented as needed with analyses at commercial labs. There is the possibility of con tinuous automated monitoring of geochemical data using downhole sensors. Alt hough downhole pH and optical sensors for wells exist, additional R&D and commercia l operations are needed in this area. Thus, geochemical data acquisition may rely partially upon su rface testing of water samples.

Eddy Covariance Air Monitoring

Direct measurement and testing of CO 2 concentrations above a GS site can be made in the air or vadose zone (the vadose zone is the unsaturated zone between the ground surface and the water table). This type of monitoring may be required at the discretion of the UIC Di rector. If this type of monitoring is to be part of the monitoring progra m, it will be necessary to develop a baseline of ambient conditions as part of the site characterization. Es tablishment of a repres entative baseline of the concentration of CO 2 in the air or soil may be somewhat problematic in many instances, due to the potential for a relativ ely large amount of natu ral variability. The back ground variability may be high relative to what is of interest for site monitoring.

Basic technologies include e ddy covariance, light detection and ranging (LIDAR), soil gas sampling with ground-surface accumulation chambers, and direct vadose zone sampling using subsurface probes.

The eddy covariance technique is used to measure CO 2 concentration in the ai r above a GS site. It combines an open path infra-red gas analyzer on a tower alongside a sensitive anemometer that measures wind speed and direction. The size and shape of the sampling footprint is derived mathematically from the anemometer data. 29,30 A typical station consists of sensors mounted on a tower from 10 to 30 feet high. The stations can be operated with solar power and can be set up for data telemetry for transmission to a central facili ty. Deployment of a grid of such detectors over a GS site provides information regardless of wind direction.

Capital costs for eddy covariance monitoring are based upon cost pe r station and specifications of number of monitoring stations. Annua l costs are estimated separately.

29 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2 , Report No. COAL R285 DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Be ntham, S. Holloway, and G. Kirby, British Geological Survey, Coordinator of the European Network of Excellence on Underground CO2 Storage (CO2GeoNet), Keyworth, Nottingham, UK, March 2005.
30 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide , S. Benson and L. Myer, Lawrence Berkeley Laboratory, Berkeley, California, 2002.Technology and Cost Document for the final GS Rule 18 November 2010 Front-End Engineering and Design- Monitoring Wells

This encompasses front-end engineering and desi gn of the monitoring wells only. The monitoring wells may be completed above the injection zone or into the injection zone. These items have separate costs in the model.

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

Owners or operators must obtain rights-of-way for surface use to set up and operate monitoring facilities. In the cost model for th is analysis, the costs for right-of -way are estimated separately for monitoring wells above the injection zone, monito ring wells into the injection zone, and for air monitoring sites

. Downhole Safety Valve or Check Valve

Injection wells must be equipped with alarms a nd automatic downhole shutoff systems (or, at the discretion of the UIC Director, other mechanical devices that provide equivalent protection). Downhole safety valves will be inst alled to automatically shut in th e well if surface equipment fails so that no surface release occurs and backfl ow into surface facili ties is prevented.

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

Standard Monitoring Well Costs

To ensure the protection of USDWs, multiple m onitoring wells will be required to monitor the movement of CO 2 in the subsurface. Various types of sensor technologies and fluid sampling methods can be used to provide such informa tion. A 2006 FutureGen report listed the various categories of monitoring wells: 31

 Injection Zone Monitori ng Wells – monitoring wells that ar e perforated across the injection

zone.

 Above the Confining Zone Mon itoring 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 CO 2 or salinity.

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

With injection zone monitoring wells there is a tradeoff between improved ability to monitor the injection zone and a potential increase in leakag e risk. Monitoring wells completed in intervals above the injection zone do not carry this risk. In the curren t cost study, it is assumed that monitoring wells are completed just above the primary seal.

31 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregena lliance.org, December 1, 2006.Technology and Cost Document for the final GS Rule 19 November 2010 The drilling and completion of CO 2 monitoring wells represents a large component of overall monitoring costs. For example, a 5,000 foot well with an average co st per foot of $180 will cost $900,000. The overall cost is a function of de pth and well design and characteristics.

In the Cost Analysis 32 for this rule, monitoring well costs are determined for wells completed either above the injection zone or into the injection zone.

Pressure and Temperature Gauges and Equipment for Monitoring Wells

Monitoring wells may have permanently insta lled downhole equipment to continuously measure pressure and temperature in the injection and containment zone. Measurements of subsurface pressure are routine in oil and gas field operations. 33 A wide variety of pressure sensors are available, including piezo-electric transducers, strain gauges, diaphragm gauges, capacitance gauges, and the newer fiber optic pressure and temperature sensors are available. Fiber optic cables from the surface to the formation can provide real-time formation pressure measurements.

These items in the cost model are for the capita l costs of such equipment. The annual operating costs for monitoring wells are input separately.

Salinity, CO 2 , and Tracer Equipment for Monitoring Wells

Salinity and fluid characteristics may be measured downhole in a monitoring well to help determine composition of fluids and to monitor CO 2 movement. Samples can also be analyzed for injected chemical tracers. At the discretion of the UIC Di rector, owners and operators may be required to add tracers to the injected CO 2 and conduct subsequent monitoring with monitoring wells to detect the tracers, indicating CO 2 leakage.

Samples can be collected directly from the form ation using a U-tube downhole sampler, which was developed by the Lawrence Berkeley National La boratory (LBNL). Once collected and brought to the surface, the samples can be analyzed for majo r ions, pH, alkalinity, stable isotopes of carbon, oxygen, and hydrogen, and gases such as hydrocarbon vapors, CO 2 , and its associated isotopes. 34

At the Texas Frio Brine Pilot Te sts, a U-tube downhole sampler wa s used to collect high-frequency samples at the monitoring well. 35 A U-shaped tube was equipped w ith a series of one-way check valves at the cusp of the U bend in the tube and was inserted to the sampli ng depth. The pressure in the U-tube was decreased below formation pressure to allow sample fluids to enter the tube through the check valves. The U-tube pressure was then increased using compressed nitrogen gas, and the sample was rapidly transported to the surface for analysis.

32 Cost Analysis for the Final GS Rule, EPA 816-R-10-013.
33 Overview of Monitoring Techniques and Protocols for Geological Storage Projects , S. M. Benson, E. Gasperikova, and G. M. Hoversten, IEA Greenhouse Gas R&D Program report, Report Number PH4/29, November 2004.
34 Overview of Monitoring Techniques and Protocols for Geological Storage Projects , S. M. Benson, E. Gasperikova, and G. M. Hoversten, IEA Greenhouse Gas R&D Program report, Report Number PH4/29, November 2004.
35 Monitoring Geologically Sequestered CO2 during the Frio Brine Pilot Test using Perfluorocarbon Tracers , by S. D. McCallum, D. E. Reistenberg, D. R. Cole, B. M. Freifeld, R. C. Trautz, S. D. Hovorka, and T. J. Phelps, Conference Proceedings, Fourth Annual Conferen ce on Carbon Capture and Sequestr ation, DOE/NETL, May 2-5, 2005.Technology and Cost Document for the final GS Rule 20 November 2010 There are three components in this category for equipment costs only:

 Monitoring equipment for wells above the injection zone

 Monitoring equipment for wells into the injection zone

 U-tube monitoring equipment for sensing oil movement away from the bottom of the formation (Enhanced Recovery only)

Develop Plan and Implement Eddy Covariance Air Monitoring

Eddy covariance is an established tec hnology for potentially monitoring the CO 2 concentration in the air above a GS site. It combines an open path infra-red gas analyzer (IRGA) on a tower alongside a sensitive, high-spee d, three-dimensional anemometer, a device used for measuring instantaneous wind speed and dire ction. Time series data are recorded and evaluated using computer methods. Eddy covariance systems are rese arch tools that are assembled from a variety of commercially available components. The size and sh ape of the sampling footprint (the surface area that is sampled by the instrument) is derived mathematically from the anemometer data. A typical station consists of sensors mounted on a tower from several meters to 30 meters or more high.

The stations can be operated with solar power and can be set up fo r data telemetry for transmission to a central facility. Deployment of a grid of such detectors over an area provides information regardless of wind direction. CO 2 concentration data are integr ated with meteorological data including wind speed and directi on, relative humidity, and temperature. Such methods have the ability to measure CO 2 concentration in the atmosphere over relatively large areas.

This cost component incorporat es the expenditures for planni ng and equipment costs for air monitoring using Eddy Covariance technology. Annual operating costs are included as a separate data item.

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

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

Digital color ortho-imagery and hyper-spectral imaging are airbor ne remote sensing technologies used to detect changes in vegetation resulting from CO 2 leakage. Hyper-spectral sensors are used to image changes in the electromagnetic spectrum from vegetation. The object is to detect a specific spectral signature that is known to result from CO 2 uptake. The advantage of these methods is that they can efficiently cover a large surface area.

This cost component incorporat es the expenditures for planning and quality assurance. Annual operating costs are included as a subsequent data item.Technology and Cost Document for the final GS Rule 21 November 2010 Develop Plan and Implement LIDAR Airborne Survey

LIDAR is an optical remote sensing tec hnology that can be used to detect CO 2 concentration in the air above a GS site. 36 Another technology for measurement of CO 2 in air is Raman LIDAR. LIDAR is the optical analog of radar, and it is based upon the use of la ser radiation to measure various compounds in the air, including CO 2 . The Raman LIDAR method involves transmitting laser light into the atmosphere and then detecting the sca ttered laser radiation that has been shifted in wavelength due to interaction with th e target scattering molecules (e.g., CO 2 ) along the resolved path length. By comparing the Raman signal of the CO 2 to the Raman signal of N 2 or O 2 , a direct measurement of CO 2 concentration can be obtained.

A similar method, Differential Absorption LIDAR (DIA L), uses two wavelengths of laser light to measure the CO 2 concentration in the atmosphere. The wavelengths used are specific to CO 2 . One wavelength is selected to correspond to a CO 2 spectral absorption line, while the other is a nonabsorbing wavelength. The average CO 2 concentration over the path le ngth can be determined from the ratio of the backscatter signals for the two laser wavelengths. The instrumentation for both methods (Raman LIDAR and DIAL) can be truck or airplane mounted and can provide similar precision at similar cost. Truck me thods can cover up to tens of square kilometers per day. Plane mounted platforms can cover a much larger area.

Airborne DIAL methods are currently in use fo r methane leakage detection along gas pipelines. Instrumentation includes the LIDAR, a digital mapping camera, a color video system, and an optical guidance system. The airpla ne flies a survey over the pipeline at an altitude of about 1,000 feet, approximately perpendicular to the wind di rection. The LIDAR instru mentation measures the concentration of methane by measur ing how much of the reflected laser pulse has been absorbed. These data are integrated with re al time wind direction and velocity to define the le akage footprint and estimate a leakage rate.

This cost component incorporat es the expenditures for planning and quality assurance. Annual operating costs are included as a subsequent data item.

Develop Plan and Implement Soil Zone Monitoring

The soil zone is generally present within the first few inches to possibly te ns of feet beneath the Earth’s surface. A monitoring progr am to detect the vertical CO 2 flux in the soil zone can be established. Background levels (which vary with ti me of day and season) must be determined to provide a baseline against which statistically si gnificant anomalies can be detected. This may consist of a grid of accumulation chambers in which the CO 2 flux is periodically measured. 37

Commercially available accumulation chamber instru ment packages are used to evaluate seasonal variations in CO 2 flux. The accumulation chamber is a method of measuring soil CO 2 flux that

36 U.S. Department of Energy NETL http://www.netl.doe.gov/publications /factsheets/project/Project642.pdf.
37 Oldenberg, C.M., Jenni fer L. Lewicki, and Robert P. Hepple, 2003, “Near-Surface Mon itoring Strategies for Carbon Dioxide Storage Verification,” Earth Sc iences Division, Lawrence Berkeley National Laboratory, publication LBNL54089.Technology and Cost Document for the final GS Rule 22 November 2010 involves the placement of a collectio n chamber directly on or into the soil surface, with the rate of CO 2 accumulation measured periodically with an IRGA.

This cost component incorporat es the expenditures for planning and equipment installation. Annual operating costs are included as a subsequent data item.

Develop Plan and Implement Vadose Zone Monitoring

The vadose zone is the relatively shallow zone beneath the surface that is not saturated with groundwater. Due to absence of water, monitoring in this zone therefore is limited to testing the chemistry of the air contained within the pore space. The CO 2 concentration of air samples taken in this zone can be measured using commercially available infrared gas analyzers (IRGAs), which measure the absorption of specific portions of the infrared spectrum to determine the concentration of CO 2 (or other gases) in the air sample.

This cost component incorporates the expe nditures for planning and equipment installation. Annual operating costs are included as a subsequent data item.

Develop Plan and Implement Water Table Monitoring

The water table is the subsurface zone that lies beneath the vados e zone. The water table can be monitored in shallow water wells to detect CO 2 leakage at a GS site. This cost component incorporates the expenditures for planning and equipment installation. Annual operating costs are included as a subsequent data item.

Periodic Monitoring of Groundwa ter Quality and Geochemistry

As discussed above, the ground water must be monito red periodically to detect leakage. This cost component details the costs of peri odic testing of water wells. Wate r samples are obtained from the well and tested at the laboratory.

Surface Microseismic Equipment

Microseisms are very small earthquakes that are a ssumed to be caused natura lly or by the pressure front of the injected CO 2
. 38 Technologies that allow the determination of the location of microseisms in three dimensions through tim e are used to monitor plume movement.

Passive seismic methods detect seis mic signals other than those crea ted by “active” sources. In this technology, sensors (geophones) ar e deployed downhole. Downhole receivers are cemented in a monitoring well and continuously re cord a signal from microseism ic activity in the injection

zone. 39,40,41

38 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregena lliance.org, December 1, 2006.
39 Monitoring of Sequestered CO2: Meeting the Challenge with Emerging Geophysical Technologies, S.N. Dasgupta, Saudi Aramco, 2005.
40 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2 , Report No. COAL R285 DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Be ntham, S. Holloway, and G. Kirby, British GeologicalTechnology and Cost Document for the final GS Rule 23 November 2010 Passive seismic is used to detect microfractures created during injection. Th e microfractures result from the change in pressure brought about by in jection. Passive seismic is used to monitor CO 2 plume movement, and to help determine the risk of developing through-go ing fractures that may impact migration or seal integrit y. A series of surveys through time results in a time-lapse picture of CO 2 movement. An advantage of microseismic mon itoring is that, once the sensors are in place, there is little maintenanc e needed, and the data can be collected remotely. 42

Not all storage injection zones are amenable to pa ssive seismic methods. F actors that play a role include rock mechanics, lithology, and natural seismic activity.

This cost item includes the installation of micr oseismic detection equipment. Annual costs are itemized separately.

Monitoring Well O&M Costs - Above Injection Zone

This includes the annual costs of operating and ma intaining monitoring wells completed above the injection zone including operating labor and system maintenance.

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

Monitoring Well O&M Costs - Into Injection Zone

This includes the annual costs of operating and maintaining monitoring wells completed in the injection zone including operating labor and system maintenance.

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

U-Tube Sampling O&M – Enhanced Recovery

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

Annual Costs of Air and Soil Surveys – Eddy Covariance

This component is the annual cost of continuous air sampling using eddy covariance equipment. This technology was described previously.

Survey, Coordinator of the European Network of Excellence on Underground CO2 Storage (CO2GeoNet), Keyworth, Nottingham, UK, March 2005.
41 SACS – 2, Work Package 4, Monitoring Well Scenarios , by I. M. Carlsen, S. Mjaaland, and F. Nyhavn, SINTEF Petroleum Research, Trondheim, Norway, for SACS group, April 6, 2001.
42 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregena lliance.org, December 1, 2006.Technology and Cost Document for the final GS Rule 24 November 2010 Annual Costs of Air and Soil Surveys – Digital Color Infrared Orthoimagery or Hyperspectral Imaging

This component is the annual cost of digital im agery for monitoring of the site. The technologies were described previously.

Annual Costs of Air and Soil Surveys –LIDAR

This component is the annual cost of a LI DAR airborne survey to detect surface CO 2 leaks. This technology was described previously.

Annual Costs of Air and Soil Surveys –Soil Zone Monitoring

This component is the annual cost of soil z one monitoring. The technol ogies were described previously. The costs are based upon labor and a fee for lab testing.

Annual Costs of Air and Soil Surveys –Vadose Zone Monitoring

This component is the annual cost of vadose z one monitoring. The technologies were described previously. The costs are based upon labor and a fee for lab testing.

Annual Costs of Air and Soil Surve ys – Samples from Water Table

This component is the annual cost of water tabl e monitoring. The costs are based upon labor and a fee for lab testing.

Annual Cost of Passive Seismic Equipment

This component is the annual cost of passive se ismic detection. The technologies were described previously. The cost is based upon an annual cost for each detection station.

Periodic Seismic Surveys – 3D

Seismic methods and costs were described above in the section on site characterization. Seismic data may also be used as a monitoring technology to evaluate CO 2 plume movement during and after injection. Seismic data can detect plume mo vement by evaluating changes in fluid properties due to displacement of brine with CO 2 . Surveys may be repeated dur ing injection and through the PISC monitoring phase. 43 Three dimensional (3D) data are much more useful but are more costly to obtain and interpret than 2D data. Both veloc ity and amplitude anomalies may result from CO 2 movement.

Seismic data sources (the energy sources) may be e ither vibroseis or dynamite . A vibroseis truck is a mobile source that shakes to put energy into the ground. Small dynamite shots in shallow holes may also be used. Both of these methods have be en used for decades in petroleum exploration.

43 Matoon Site Environmental Information Volume, FutureGen Alliance, www.futuregenalliance.org, December 1, 2006.Technology and Cost Document for the final GS Rule 25 November 2010 The ability to monitor CO 2 in the subsurface using seismic depends upon numerous factors, and not all sites or injection zone formations will be amenable to seismic monitoring. For example, a storage formation that has low porosity or is very deep (certainly below 10,000 feet, and in some cases less) will be less amenable to seismic mon itoring. Some geological settings may preclude the use of seismic because of near surface factor s as well. Such factors may include irregular topography, unusual lithologies, surface water, manmad e structures or impediments or other access factors. Where conditions are right, however, it is possible to detect plume movement and it can be possible to detect injected CO 2 volumes of as little as 1,000 tons. 44

In addition to surface seismic, vertical seismic profiling (VSP) and cross-well seismic may be used for subsurface monitoring to obtain very high reso lution data over a small area. VSP is a technique in which surface sources are arrayed around a well that is in close proximity to a CO 2 plume. 45 The sensors are deployed downhole. The a dvantage 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 CO 2
.
In cross-well seismic methods, seismic sources su spended on a cable are lowered into one well, and the receivers are lowered into an adjacent well. 46 Both wells must penetrate to the base of the storage injection zone under inve stigation. This method results in a two-dimensional vertical slice of the subsurface with high resolutio n at the injection zone level. The method has been successfully tested at the Frio site in Texas.

The VSP and cross-well approaches ar e not included in the cost model. The cost of 3D seismic is specified in terms of square mile area. A disc ussion of costs was presented in section 3.1 (site characterization) of this Technology and Cost document.

Complex Modeling of Fluid Flows and Migration

Reservoir modeling methods are numerical methods that employ a representa tion of a reservoir to evaluate and predict fluid pressures and flows. They can be used in an injection project to forecast the movement of CO 2 in the reservoir. Modeling of subsurface CO 2 flow must be used to define the area of review. Modeling is also used to help de termine the location, number, and specifications for the injection and monitoring wells.

CO 2 flow from injection wells can be modeled a nd the injection zone capacity can be estimated with basic engineering methods. However, comp lex numerical models providing multi-phase and multi-component reservoir simulation may be used to understand the injection project and its

44 Technology Status Review – Monitoring Technologies for the Geological Storage of CO2 , Report No. COAL R285 DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Bentham, S. Holloway, and G. Kirby, British Geological Survey, Coordinator of the Eur opean Network of Excellence on Underground CO2 Storage (CO2GeoNet), Keyworth, Nottingham, UK, March 2005.

45 Measurement, Monitori ng, and Verification , L. H. Spangler, Zero Emission Research and Technology Center, Carbon Sequestration Leadership Forum, date unknown.

46 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregenalliance.org, December 1, 2006.Technology and Cost Document for the final GS Rule 26 November 2010 impacts in much greater detail. 47 Different models are needed to analyze the well-bore flow and to simulate the large-scale flow processes in the rese rvoir. Models may be de signed to evaluate flow over periods of tens of years to t housands of years into the future.

Reservoir modeling costs are specified in the cost model in terms of labor hours for the site plus additional labor hours per injection well.

Reports to Regulators

This cost item includes the labor costs to complete periodic reports to regula tory bodies. The cost is based upon an estimate of the number of hours of labor required.

Monitoring Unit Costs

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

47 GEO-SEQ Best Practices Manual, Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation , by the GEO-SEQ Project Team, Earth Sciences Division, Lawren ce Berkeley National Laboratory, Berkeley, California, September 30, 2004.Technology and Cost Document for the final GS Rule 27 November 2010 Table 3: Monitoring Unit Costs

Tracking Number Cost Item Cost Algorithm Data Sources

B-1 Develop geochemical baseline for injection zones and confining zone. $207 per sample. Assume 4 samples per injection well = $828 per injection well Lab analysis fee of $100 to $200 discussed in N.O. meeting.

B-2 Develop baseline of surface air CO2 flux for Eddy Covariance leakage monitoring. $36,200 per station Range of costs discussed at N.O. meeting Jan 2008 was $20,000 to $50,000 per station.

B-3a Conduct front-end engineering and design (monitoring wells ABOVE in j ection zone ) $20,700 + $5,200/shallow monitoring well Best professional judgement.

B-3b Conduct front-end engineering and design (monitoring wells INTO in j ection zone ) $5,200/deep monitoring well Best professional judgement.

B-4a Obtain rights-of-way for surface uses. (monitoring wells ABOVE in j ection zone ) $10,400 per monitoring well site Best judgement. Cost of land rights are highly variable.

B-4b Obtain rights-of-way for surface uses. (monitoring wells INTO in j ection zone ) $10,400 per monitoring well site Best judgement. Cost of land rights are highly variable.

B-5 Obtain rights-of-way for surface uses. (monitoring sites) $5,200 per air monitoring station site (microseismic is done inside montoring

well and has no extra land costs) Best judgement. Cost of land rights are highly variable.

B-6a Downhole safety shut-off valve $15,500 + $2.10/ft depth. Would be placed 100 or more feet above packer Best professional judgement.

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

B-7 Standard monitoring well stopping above the injection zone (used lookup table). Standard monitoring wells for ER p ro j ects sto p below the in j ection zone. Use look-up table. $/foot = $155 to $207 per foot typical down to 9,000 ft. Drilling cost is estimated from drilling cost equations developed from JAS and PSAC data.

B-8 Standard monitoring well drilled into the injection zone (used lookup table); applies to RA 3-4 only). Use look-up table. $/foot = $155 to $207 per foot typical down to 9,000 ft. Drilling cost is estimated from drilling cost equations developed from JAS and PSAC data.

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

e q ui p ment for monitorin g wells ABOVE in j ection zone $10,400/well Best professional judgement.

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

e q ui p ment for monitorin g wells INTO in j ection zone $10,400/well Best professional judgement.

B-10a Salinity, CO2, tracer, etc. monitoring equipment for wells ABOVE injection zone (portion of equipment may be at surface such as for in situ sam p lin g usin g U-tubes ) $10,400/well Best professional judgement.

B-10b Salinity, CO2, tracer, etc. monitoring equipment for wells INTO injection zone (portion of equipment may be at surface such as for in situ sam p lin g usin g U-tubes ) $10,400/well Best professional judgement.

B-10c ER Only. U-tube for sensing oil movement away from bottom of formation. Applies to 2 of 8 EOR wells. $16/ft + $30,000 per well Best professional judgement.

B-11a Develop plan and implement Eddy Covariance air monitoring. 40 hours @$107.23/hr = $4,289 for plan plus $75,000/monitoring site Best professional judgment of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

Monitoring station cost estimate from Benson 2004.

B-11b Develop plan and implement Digital Color Infrared Orthoimagery (CIR) or Hyperspectral Imaging to detect changes to vegetation. No construction costs, but planning and quality assurance costs would add $10,000 per square mile. Best professional judgement.

B-11c Develop plan and implement LIDAR airborne survey to detect surface leaks. Works best where vegetation is sparse. No construction costs, but planning and quality assurance costs would add $10,000 per square mile. Best professional judgement.

B-11d Develop plan and implement soil zone monitoring 40 hours @$107.23/hr = $4,289 for plan plus $6,000/monitoring site Best professional judgement.

B-11e Develop plan and implement vadose zone monitoring wells to sample gas above water table. 40 hours @$107.23/hr = $4,289 for plan plus $8,000/monitoring site Best professional judgement.

B-11f Develop plan and implement monitoring wells for samples from water table. 40 hours @$107.23/hr = $4,289 for plan plus $80,000/monitoring site Best professional judgement.

B-12 Conduct periodic monitoring of groundwater quality and geochemistry. (146.90(d) of GS Rule). $200/sample and 4 samples per well = $800 per well plus 0.5 hours of engineer labor for sampling per well p er month. Lab analysis fee of $100 to $200 discussed in New Orleans mtg.Technology and Cost Document for the final GS Rule 28 November 2010 Table 3 (continued): Monitoring Unit Costs

Tracking Number Cost Item Cost Algorithm Data Sources

B-13 Surface microseismic detection equipment $52,000/ site (geophone arrays go into monitorin g wells ) Best professional judgement.

B-14a Monitoring well O&M (ABOVE injection zone) Annual O&M costs are $25,900 + $3.10/ft per well per year Operating and maintenance costs adapted from EIA Oil and Gas Lease Equipment and Operating Cost estimates.

B-14b Monitoring well O&M (INTO injection zone) Annual O&M costs are $25,900 + $3.10/ft per well per year Operating and maintenance costs adapted from EIA Oil and Gas Lease Equipment and Operating Cost estimates.

B-14c ER Only; U-tube O&M; for 2 of 8 wells drilled 200 feet below injection zone $10,000 per year base O&M costs plus monthly sampling (=12*8 hrs/sample * $110.62/hr + 12* $200 (chromatograph cost) per sample = $10,000 plus $13,019 for 12 samples annually per well. Best professional judgement with reference to Benson, 2004

B-15a Annual cost of air and soil surveys: Eddy Covariance $10,000 per station per year Best professional judgement with reference to Benson, 2004

B-15b Annual cost of air and soil surveys: Digital Color Infrared Orthoimagery (CIR) or Hyperspectral Imaging to detect changes to vegetation. Airborne survey costs of $6,250 per square mile plus mobilization costs of $5,000 per site. Best professional judgement with reference to Benson, 2004

B-15c Annual cost of air and soil surveys: LIDAR airborne survey to detect surface leaks. Works best where vegetation is sparse. Airborne survey costs of $6,250 per square mile plus mobilization costs of $5,000 per site. Best professional judgement with reference to Benson, 2004

B-15d Annual cost of air and soil surveys: Soil zone monitoring $200 lab fee per sample plus $100 to collect. Best professional judgement with reference to Benson, 2004

B-15e Annual cost of air and soil surveys: Vadose zone monitoring wells to sample gas above water table. $200 lab fee per sample plus $100 to collect. Best professional judgement with reference to Benson, 2004

B-15f Annual cost of air and soil surveys: Monitoring wells for samples from water table. $200 lab fee per sample plus $1,000 to collect. Best professional judgement with reference to Benson, 2004

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

B-17 Periodic seismic surveys: 3D $104,000/square mile for good resolution Several published reports are in range of this cost. Cost depends on resolution

( number of lines shot ) of surve y

.

B-18 Complex modeling of fluid flows and migration (reservoir simulations) over 100 years (RA0-3) or 10,000 years (RA4). 180 hours of engineers @$110.62/hr = $19,912 per site + 64 hours of engineers @$110.62/hr = $7,080 per in j ection well Best judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

B-19 Annual reports to regulators and recordkeeping for all data gathering activities. 20 hours of engineers @$110.62/hr = $2,212 per report plus 24 hours annually of engineer labor @110.62 p er hour = $2,655 for recordkee p in g Best judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

B-20 Semi-Annual (RA3) or quartery (RA4) reports to regulators and recordkeeping for all data gathering activities and recordkeeping. 15 hours of engineers @$110.62/hr = $1,659 per report plus 36 hours of

engineer labor @$110.62/hr for recordkee p in g = $3,982 Best judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

B-21 Monthly reports to regulators and recordkeeping for all data gathering activities and recordkeeping. 8 hours of engineers @$110.62/hr = $885 per report Best judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum g eolo g ists.

B-22 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 29 November 2010 3.3 Injection Well Construction

Front End Engineering and Design

Front-end engineering and design ar e carried out for the overall site and for the injection wells. Design of the monitoring wells is included under the monitoring sec tion. Injection well construction costs include development of standard plans associated with current UIC regulations (e.g., the drilling and casing plan, wellhead equipm ent plan, and downhole equipment selection), as well as pre-operational loggi ng, sampling, and testing.

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

Rights of Way for Surface Uses

This element includes costs of the right-of-w ay for surface use for injection wells and for subsurface or pore space use. The issue of s ubsurface property rights varies by state and is discussed in detail in the IPCC report. 48 Rights to use subsurface pore space could be granted separately from surface ownership. Obtaining the ri ght to use subsurface pore space may represent a significant cost component of GS. Pore space co sts are outside the scope of SDWA and are not attributable to the GS rule. In the Cost Analysis, pore space costs for the final rule, in incremental terms, are zero because they occur under both the baseline alternative and the final rule (pore space costs in incremental terms are zero for each of th e regulatory alternatives in comparison to the regulatory baseline). These costs are presen ted in the analysis for completeness only.

Costs are specified as a fixed cost per injection well. It is assumed that half of the cost is legal fees for the developer and the other half is a bonus paym ent to the landowner. Pipeline right-of-ways are specified as pipeline costs.

Lease Rights for Subsurface Pore Space

This includes the upfront costs only for use of pore space. The ongoing pore space costs during the project are specified separately unde r the discussion of well operation.

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

Land Use, Air Emissions, and Water Permits

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

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

48 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage , by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.Technology and Cost Document for the final GS Rule 30 November 2010 UIC Permit Filing

This unit cost item covers the estimated labor cost to prepare a UIC injection permit. Each well will require its own UIC permit (EPA will not issue area permits), but there will be economies of scale in compiling the group of permits submitted for each project site.

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

Standard Injection Well Drilling Cost

The technologies for drilling and equipping CO 2 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 CO 2 enhanced oil recovery projects ar e active in the U.S., especially in the Permian Basin of West Texas, and technologie s have been developed to complete, produce, and maintain CO 2 injection and CO 2 EOR production wells for long periods of time.

The design of a CO 2 injection well is similar to that of a conventional gas (or other) injection well or a gas storage well, with the exception that much of the downhole equipment (e.g. casing and tubing, safety valves, cements, blowout prevente rs) must be upgraded for high pressure and corrosion resistance. 49 A well program is designed prior to dr illing to determine the drilling plan and casing points. This design incorporates wh at is known about the geology and engineering aspects of the location.

Injection wells typically consist of several strings of casing extending to di fferent depths. Multiple casing strings are required to isolate the well from shallow drinking water and to prevent problems with weak sections of the well bore. 50 The innermost, deepest casing string is cemented in place across the storage injection z one and then perforated to allow movement of the CO 2 into the well. Then a small diameter tube is run into the well in side the innermost casing. This injection tubing is sealed off from the casing with a double grip packer.

The well is completed at the surface by installing a wellhead and “Christmas Tree” that sits on top of the wellhead and is an assembly of valves, pre ssure 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 pr event well blowouts due to unexpected pressu re (downhole devices are now required). A Supervisory Control and Da ta Acquisition (SCADA) is used to monitor the data. The system is set up to automatically shut down the injection if needed.

Basic injection well drilling costs are specified on a per-foot of total depth basis. Cost per foot is typically in the range of $220 to $290 per foot. A dditional costs such as the use of specialized tubing and casing, cementing, and wellhead equipm ent are evaluated separately (see below). Operating and maintenance cost s are also not included here.

49 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage , by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.
50 Matoon Site Environmental Information Volume, FutureGen Alliance,www.futuregena lliance.org, December 1, 2006.Technology and Cost Document for the final GS Rule 31 November 2010 Well Stimulation

In some cases, it may be necessary to artificially fracture the injection well to allow for efficient CO 2 injection. This is accomplished by injecting a mixtur e of water and sand or other proppant material. This type of well stimulation is now carried out on a large percentage of gas wells drilled in the U.S. Cost information was modified from the PSAC well cost study. For the current study, any such costs included in the model would be based upon the pounds of proppant injected. The expected range is 25,000 to 200,000 pounds of proppant for the stimulation.

Corrosion Resistant Tubing and Casing

Operators of CO 2 EOR projects have developed guidelines for the use of special materials to prevent or minimize corrosion caused by carbonic aci d. As discussed in the Preamble of the final GS Rule, supercritical CO 2 in the absence of water will not be corrosive. Corrosiveness of CO 2 in the presence of water is well documented. An AP I report on injection tec hnology lays out a set of guidelines that were developed to address this corrosivity: 51

Because of the corrosive effects of carbonic acid, H 2 CO 3 , on metal components, induced by the alternating water and gas (WAG) injection cycles during CO 2 EOR operation, a significant fraction of scientific and technical work has been devoted to developing robu st solutions to corrosion problems. Supplemental work has also been do ne on identifying and developing elastomeric materials for packers and seal s that can withstand the solvent effects of supercritical CO 2 that induce swelling and degradation. Throughout this process, the underlying strategy of the i ndustry has been to select materials based on their durability and corrosion resi stance. As a result of these efforts, tubular components can be expected to have a service life of 20 to 25 years before replacement.

The following guidelines were published on page 23 of the report:

Component Materials

Upstream metering and piping runs 316 Stainless Steel (SS)/ Fiberglass

Christmas Tree (Trim) 316 SS Nickel, Monel

Valve Packing and Seals Teflon, Nylon

Wellhead (Trim) 316 SS Nickel, Monel

Tubing Hangar 316 SS Incoloy

51 Summary of Carbon Dioxide Enhanced Oil Recovery (CO 2 EOR) Injection Well Technology , J.P. Meyer, Contek Solutions, for the American Petroleum Institute, 2007.Technology and Cost Document for the final GS Rule 32 November 2010 Component Materials

Tubing Glass Reinforced Epoxy (GRE) - lined carbon steel; IPC carbon steel, Corrosion Resistant Alloys (CRA)

Tubing Joint Seals Seal ring (GRE), Coated threads and collars

ON/OFF Tool, Profile Nipple Nickel plated wetted parts

Packers Internally coated harden ed rubber, etc. Nickel plated wetted parts

Cements and Cement Additives API ceme nts and/or acid resistant cements

The nickel content of steel can be varied, with higher nickel content resulting in more corrosion resistance but higher costs.

Corrosion Resistant Tubing The tubing is the injection well t ubular component through which the CO 2 is injected into the formation. Cost assumptions for corrosion resistan t tubing include glass re inforced epoxy (GRE). Costs are specified on the basis of tubing footage and diameter.

Corrosion Resistant Casing The casing is the injection well steel tubular component that is inse rted in each section of drillhole after drilling and is subsequently cemented in pl ace to prevent fluid movement. Cost assumptions are specified for corrosion resistant materials on the basis of casing diameter and footage.

Cementing of the Injection Well Casing

This cost item includes the cost of cementing the well from the surface through the base of the lowermost USDW and throughout the injection zone . Costs are specified on the basis of casing diameter and footage. Costs specified are for sta ndard Portland cement. (Wells having waivers of the injection depth requirement will be cemented through the base of the USDW immediately above the injection zone.)

Use of CO 2 -Resistant Cement

The type of cement that is used in well cementi ng operations may be subject to chemical reactions in a CO 2 injection zone. Casing and cement or other mate rials used in the cons truction of a GS well must have sufficient structural strength and be designed for the life of the geologic sequestration project. In addition, the GS rule sp ecifies that all well materials must be compatible with fluids with which the materials may be expected to come in to contact and must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the UIC Director . Thus, it may in some cases be necessary toTechnology and Cost Document for the final GS Rule 33 November 2010 use specialty cements in remediation or new well construction. The following text is taken from the API report on injection well technology used in CO 2 EOR operations: 52

Because CO 2 corrosion of cement is thermodynamically favored and cannot be entirely prevented, various soluti ons have been developed to limit CO 2 attack on the cement sheath. Most of these appr oaches 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 (styre ne butadiene) to the design.

Recently, investigators took samples fr om a 52 year old SACROC well with conventional, Portland-based well cement exposed to CO 2 for 30 years and found limited evidence of cement degradation. Preliminary evaluation suggests that the mixture of gelled and solid-particulate, (CO 2 and cement), reaction products sealed the cement permeability pore throats to significantly delay or prevent further CO 2 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 sp ecialty cements, have not been widely used in CO 2 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 (CO 2 and H 2 S) and highly corrosive geothermal brine exposure conditions, in place of conventional systems.

Costs are specified on the basis of an increm ental cost over standard cementing operations.

Pumps

Pumps, wellhead and control equipment, and m easuring and monitoring equipment are required elements of the injection system. The pumps are those needed to move the CO 2 to the injectors. Pump costs are a function of hor sepower. Installation of electri cal service also adds a cost component.

Wellhead Control Equipment

A diagram of typical injection we ll wellhead and control equipment is shown in Figure 5. The cost of injection equipment is a functi on of injectivity and the intended ra te of injection. Injection well monitoring equipment is described in the 2007 AP I report and includes a lubricator valve for

52 Summary of Carbon Dioxide Enhanced Oil Recovery (CO 2 EOR) Injection Well Technology, J.P. Meyer, Contek Solutions, for the American Petroleum Institute, 2007.Technology and Cost Document for the final GS Rule 34 November 2010 running wireline tools, master valves to isolatethe tubing from the CO 2 source, casing head valves to permit monitoring of pressure in the annulus between the production casi ng and the tubing string to ensure mechanical integrity, and a Bradenh ead valve to monitor the pressure between the production casing and surface casing. 53

Figure 5: Diagram of Typical CO 2 Injection Wellhead
Source: 2007 API report (cited on previous page).

Costs are specified on the basis of the maximum nu mber tons injected per day per well. Operating costs are not included here.

Pipeline Costs

Included in the cost analysis is the cost for a CO 2 pipeline for the immediat e GS site. As described previously in this Technology and Cost document, costs to transport the CO 2 to the GS site are

53 Summary of Carbon Dioxide Enhanced Oil Recovery (CO 2 EOR) Injection Well Technology , supporting information provided by J. P. Meyer, Contek Solutions, for the American Petroleum Institute, 2007.Technology and Cost Document for the final GS Rule 35 November 2010 outside the scope of the rule and are excluded. Pi peline 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 injecti on well construction.Technology and Cost Document for the final GS Rule 36 November 2010 Table 4: Injection Well Construction Unit Costs

Tracking Number Cost Item Cost Algorithm Data Sources

C-1 Conduct front-end engineering and design (general and injection wells), pre-op logging, sampling, and testing. $207,000/site + $41,400/injection well Best professional judgement.

C-2 Obtain rights-of-way for surface uses. (equipment, injection wells) $20,700 per injection (pipeline right of ways included in pipeline costs) Half of cost is legal fees for developer, other half is bonus to landowner. Best professional judgement. Cost of land rights are highly variable.

C-3 Lease rights for subsurface (pore space) use. Upfront payment of $52/acre (additional injection fees under O&M costs ) Best professional judgement. Cost of land rights are highly variable.

C-4 Land use, air emissions, water discharge permits $103,400/site + $20,700/square mile Best professional judgement.

C-5 UIC permit filing, including preparation of attachments $10,400/site + $6,000/injection well for first 5 wells at a site, then $2,000 thereafter Best professional judgement.

C-6a Standard injection well cost Use look-up table. $/foot = $220 to $290 per foot typically down to 9,000 ft. Drilling cost is estimated from drilling cost equations developed from JAS and PSAC data.

C-6b Well stimulation Total cost of stimulation based on cost per pound of proppant injected (coated

sand); $1.25 /lb. of sand; 25,000 to 200,000 lbs per frac Modified from PSAC cost study

C-7 Corrosion resistant tubing Additional $1.15/foot length - inch diameter for glass reinforced epoxy ( GRE ) linin g Based on SPE article on economics of GRE tubing.

C-8 Corrosion resistant casing Additional $1.81/foot length inch diameter (low alloy) or $2.70/ft (higher alloy) - for corrosion resistant casing PSAC and Preston Pipe Report

C-9 Cement well from surface through base of lowermost USDW and througout injection zone. $1.20/foot length - inch diameter Cementing cost based on 2008 PSAC Well Cost Study.

C-10 Use CO2-resistant cement Adds 25% to total cementing costs Best professional judgement.

C-13 Injection pressure limited to 90% of fracture pressure of injection formation Affects maximum flow of well, number of wells needed Due to uncertainty of injectability, this pressure impact is ignored.

C-14 Pumps $1550/HP. Installation of electrical service adds $20,700 per well site. Electrification cost based on EIA Oil and Gas Lease Equipment and Operating Cost estimates. Pump costs based on pipeline prime mover and compressor cost reported to FERC.

C-15 Wellhead and Control Equipment Cost per well is $520*(maximum tons p er da y in j ected p er well ) ^0.6 Based on 2008 PSAC Well Cost Study.

C-16 All elements of pipeline costs $83,000/inch-mile From pipeline cost data reported to FERC. Published annually in Oil and Gas Journal.

C-17 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 37 November 2010 3.4 Area of Review and Corrective Action

This aspect of the cost analysis includes fluid flow and reservoir modeling to predict the movement of the injected CO 2 and pressure changes during and after injection. It also includes those cost elements pertaining to the identification, evaluati on, and remediation of ex isting wells within the area of review.

Simple Fluid Flow Calculations to Predict CO 2 Flow

Modeling of fluid flow in the subsurface can be based on relatively simple, straightforward approaches that are not particularly data inte nsive, or it can be extremely involved and use sophisticated numerical reservoir simulation models. Two basic type s of analysis are included in the cost analysis, one simple approach using ba sic reservoir parameters, and the other based upon advanced reservoir simulation.

This cost element is for a simple flow calcula tion that provides basic information on subsurface CO 2 movement.

Complex Modeling of CO 2 Fluid Flow

This cost element is an estimation of the numbe r of hours of labor requ ired to set up, run, and interpret a sophisticated subsurface reservoir simulation mode l. Cost items are included for a 100 year simulation model and a 10,000 year simulation model.

Aerial Survey to Find Old Wells

This cost item involves an airbor ne magnetic survey using a helicop ter that flies over the area of review to detect well casings from all cased well s. This may identify old wells that are not in existing databases. Magnetic surveys can also be carried out from ground vehicles, but airborne surveys can cover the large expect ed survey areas much more effi ciently. If such well casings are identified, additional follow-up, research of well records and physical inspection can be used to obtain additional data on the condition of these wells.

Evaluate Mechanical Integrity of Existin g Wells Penetrating Containment System

Existing wells at a planned GS site ar e potential conduits fo r the leakage of CO 2 . The goal in evaluating these wells is to assess risk and to de velop a plan of corrective action prior to GS. The wells that are most critical in this analysis are th ose that penetrate the proposed injection zone and confining zone units. Factors that must be evalua ted include the condition of the cement and overall well maintenance. 54,55

54 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage , by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.Technology and Cost Document for the final GS Rule 38 November 2010 A description of the process of evaluating and remediating old wells is provided by Meyer in a recent report published by API: 56

More recently, the 100 year old Salt Creek Field in Wyoming has been converted to a CO 2 EOR development in which ove r 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 wi th 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 l ogs, 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 monitori ng it, to see if any pressure falloff occurred. If not, the wellbore was competent.

5. When pressure fall off was observe d, it was indicative of casing leaks. The leaking section of casing was firs t identified and then re-sealed by squeeze cementing. In extreme cases, it was necessary to install a liner over the leaking section.

This cost item includes the labor costs to evaluate the integrity of wells penetrating the containment system at the site. Costs are spec ified on the basis of hours of labor costs at specified labor rates.

Evaluate Integrity of Shallow Wells

Existing shallow wells may pose a threat to USDWs. This cost item includes labor costs to evaluate the record of completion and plugging of shallow wells.

55 Measuring and Modeling for Site C haracterization: A Global Approach , D. Vu-Hoang, L. Jammes, O. Faivre, and T.S. Ramakrishnan, Schlum berger Carbon Services, March, 2006.
56 Summary of Carbon Dioxide Enhanced Oil Recovery Injection Well Technology , by James P. Meyer, API, http://www.gwpc.org/e-library/e-library_documents /e-library_documents_co2/ API%20CO2%20Report.pdf (no publication date provided)Technology and Cost Document for the final GS Rule 39 November 2010 Remediate Old Wells in Area of Review

It may be necessary to remediate existing wells at a potential GS site. Exis ting wells that penetrate the injection zone or overlying seal units may provide conduits for the vertical movement of injected CO 2 . 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 CO 2 resistant cements in portions of the well.

In the case of saline formations, there may be fe w, if any, existing wellbores. However, with older oil and gas fields, remediation costs may be si gnificant, especially with old wells. The major difficulty in estimating the scope and nature of reme diation is that there is little definitive research on the subject of the need for application of CO 2 -resistant cement in acid gas wells. 57

Remediate Old Wells that Pose a Risk to USDWs

Owners and operators must remediate wells that are in a condition that poses a risk to a USDW to ensure well integrity. This cost item in cludes well cleanout, logging, and re-plugging.

Remediate Old Wells in AOR that Lack High Quality Cementing Information

Wells that lack adequate information on cementi ng must undergo remediation to ensure integrity. This cost item includes well cl eanout, logging, and re-plugging.

Area of Review and Corrective Action Unit Costs

Table 5 specifies the estimated costs and data so urces for area of review and corrective action.

57 EPA workgroup, January, 2008.Technology and Cost Document for the final GS Rule 40 November 2010 Table 5: Area of Review and Corrective Action Unit Costs

Tracking Number Cost Item Cost Algorithm Data Sources

D-1 Simple fluid flow calculations to predict CO2 fluid flow. 36 hours of engineers @$110.62/hr = $3982 per site + 12 hours of engineers @$110.62/hr = $1327 per injection well Best professional judgement of time required. Hourly rate may change based on labor survey data.

D-2 Complex modeling of CO2 fluid flows and migration (reservoir simulations) over 100 years 180 hours of engineers @$110.62/hr = $19,912 per site + 24 hours of engineers @$110.62/hr = $2,655 per in j ection well Best professinoal judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

D-3 Complex modeling of CO2 fluid flows and migration (reservoir simulations) over 10,000 years 180 hours of engineers @$110.62/hr = $19,912 per site + 36 hours of engineers @$110.62/hr = $3,982 per in j ection well Best professinoal judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

D-4 Areal search for old wells (artificial penetrations) helicopter magnetic survey requires about 9 hours/square mile @$1,240 per hour. Cost = $5,200 mobilization + $11,160 per square mile. Follow-up

ground surveys will add another $2,070 per square mile. (helicopter survey interline spacing is about 80 feet with s p eed of 10 ft/sec ) Based on DOE sponsored research at Salt Creek WY . Helicopter hourly rate is in range of several published estimates, adjusted for fuel costs.

D-5 Evaluate integrity of construction and record of completion and/or plugging of existing wells that penetrate containment

s y stem. 24 hours @$107.23/hr = $2,574 per site + 6 hours @$110.62/hr = $664 per well Best judgement of time required. Hourly rate derived from AAPG 2009 salary survey of petroleum geologists.

D-6 Evaluate integrity of construction and record of completion and/or plugging of existing shallow wells that pose a treat to USDWs. 6 hours @$110.62/hr = $664 per well Best professinoal judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

D-7 Remediate old wells in AoR that pose a risk to USDWs $31,200 for clean out, $13,500 to replug and $11,400 to log (two cement plugs - one in producing formation and one for surface to bottom of USDWs, remainder of borehole filled with mud).

Water well remediation is $20,700. Plugging and logging cost based on 2008 and 2009 PSAC Well Cost Studies. Clean out cost will vary widely. Cost here is 3 days

of rig use @ $10,400 per day. Rig cost from Land Rig Newsletter US Land Rig Rates.

D-8 Remediate old wells in AoR that lack high quality cementing information $31,200 for clean out, $13,500 to replug and $11,400 to log (two cement plugs - one in producing formation and one for surface to bottom of USDWs, remainder of borehole filled with mud).

Water well remediation is $20,700. Plugging and logging cost based on 2008 and 2009 PSAC Well Cost Studies. Clean out cost will vary widely. Cost here is 3 days

of rig use @ $10,400 per day. Rig cost from Land Rig Newsletter US Land Rig Rates.

D-9 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 41 November 2010 3.5 Well Operation

This cost category includes those cost elements related to the operation of the injection wells, including measuring and monitoring equipment, el ectricity costs, O&M costs, pore space costs, repair and replacement of wells and equipment, and estimated costs for the possibility of failure at the site and the need to relocate a GS operati on. As discussed previously in this Technology and Cost document, pore space costs are included fo r completeness in the analysis, but are not attributable to this rulemaking.

Corrosion Monitoring and Prevention Program

Because of the potential for CO 2 to be corrosive in the presence of water, owners and operators must develop a corrosion monitoring and prev ention program for the operation. The cost is specified as labor hours to develop the program.

Corrosion Monitoring

This cost item includes the labor costs and samp le analysis costs for the corrosion monitoring program. Corrosion monitoring includes quarterly analysis of the injectate stream and the measurement of corrosion well material coupons.

Measuring and Monitoring Equipment

Measuring and monitoring equipment include a lubri cator valve for running wireline tools, master valves to permit isolation of the tubing from the CO 2 source, casing head valves to permit monitoring of pressure in the annulus between th e production casing and the tubing string to ensure mechanical integrity, and a Bradenhead valve to permit monitoring of the pressure between the production casing and surface casing. 58

This cost item includes the equipment costs for e quipment to monitor injection volumes, pressure, flow rates, and annulus pre ssure. It is specified as a cost per injection well.

Equipment to Add Tracers

Tracer testing is implemented at the Director’s discretion, and involves the incorporation of trace amounts of chemical compounds into the injected CO 2 . The objective is to confirm the migration and location of CO 2 within the injection zone and poten tially in overlying groundwater or soil zones. A number of tracers with very low de tection limits are availa ble and more are under development.

58 Summary of Carbon Dioxide Enhanced Oil Recovery (CO 2 EOR) Injection Well Technology , supporting information provided by J. P. Meyer, Contek Solutions, for the American Petroleum Institute, 2007.Technology and Cost Document for the final GS Rule 42 November 2010 The use of tracers for monitoring was investigated under GEO-SEQ 59 . Natural and artificial tracers have the potential to assist in characterizing injection zones, and calibrating models as well as indicating leakage and seepage.

Tracers may consist of natural tracers (isotopes of C, O, H, and noble gases) that are associated with the injected CO 2 , and introduced tracers including noble gases, SF6, and perfluorocarbons (PFC’s). 60 Perfluorocarbon Tracers (PFTs) have many advant ages in that they are soluble in water, non-toxic, non-radioactive, and have an extremely small detection limit. 61 Thus, much smaller amounts are required to be injected compared to other compounds such as sulfur hexafluoride.

Tracers may be detected in monitoring wells either within the storage injecti on zone or in shallower zones, groundwater, or soil gases. At the Frio Br ine pilot in Texas, ther e were three types of monitoring installations to test for CO 2 in shallow zones. 62 These included capillary absorbent tubes (CATs) and soil gas wells for the soil zone and water wells for groundwater testing. Soil gas wells may be only a few feet deep and are sampled with a syringe. CAT samples are removed and shipped to a laboratory for analys is. Fresh CATs are then installe d and the sample tubes sealed. Groundwater wells are sampled for the headspace atmosphere.

If chemical tracers are to be injected into the CO 2 stream for monitoring purposes, it will be necessary to incur costs related to the injection e quipment. This cost is specified as a cost per injection well.

Electricity Costs for Pumps and Equipment

Electricity costs represent a significant componen t of overall operating costs. This cost item specifies the electricity costs for pumps and equipment. The cost is specified as dolla rs per kilowatt hour.

Injection Well Operating and Maintenance Costs

The annual costs of operating and maintaining the injection wells include operating labor, system maintenance, and CO 2 compression costs (if needed). Not included in this unit cost are the costs for mechanical integrity pressure te sts, mechanical integrity logging, and the repercussions from those tests, such as the cost to repair , rework, or plug th e injection well.

Costs are specified as a base rate per year plus a cost per foot per well.

59 GEO-SEQ Best Practices Manual, Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation , by the GEO-SEQ Project Team, Earth Sciences Division, Lawren ce Berkeley National Laboratory, Berkeley, California, September 30, 2004.
60 Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon Dioxide , S. Benson and L. Myer, Lawrence Berkeley Laboratory, Berkeley, California, 2002.
61 Surface Environmental Monitoring at the Frio CO2 Sequestration Test Site, Texas , H.S. Nance, Texas Bureau of Economic Geology, Austin, Texas, DOE/NETL Conference on Carbon Capture and Storage, May, 2005.
62 Surface Environmental Monitoring at the Frio CO 2 Sequestration Test Site, Texas , H.S. Nance, Texas Bureau of Economic Geology, Austin, Texas, DOE/NETL Conference on Carbon Capture and Storage, May, 2005.Technology and Cost Document for the final GS Rule 43 November 2010 Land Use Rents and Right of Way

This unit cost includes the ongoing annual costs for land use and righ t of way during site operation. This is distinct from the upfront land use costs associated with site characterization.

Costs are specified in terms of dollars per acre per year.

Pore Space Unit Costs

This unit cost includes an estimate of pore space cost per barrel of CO 2 injected. This is distinct from the upfront payment unit cost included under site characteriza tion. While pore space costs are included in the analysis, they are not attributable to the final rule.

Property Taxes and Insurance

This unit cost includes the ongoing expe nse of property tax and liability insurance. It is specified as a cost per dollar of capital expenditures.

Tracers in Injected Fluid

The use of injected tracers to detect leakage is discussed above. This cost item specifies the cost of the tracer material, estimated as a cost per unit volume of CO 2 injected.

Repair or Replace Wells and Equipment

This cost component includes remediation of wells and equipment that occurs during the injection phase. This is in addition to the remediation that is completed during the initial site remediation work. The cost is based upon an assumption of 1 pe rcent per year of init ial well and equipment
cost.

General Failure of Containment Site – Remove and Relocate CO 2 There is a small probability that a given GS site will not perform adequately, due to unforeseen subsurface conditions that are not detected during the site characte rization and construction phases. This may require in a small percentage of cases the closure of the site and re-location sometime during the operating life or in the post-injection period. The best method of incorporating such a cost is through a risk-based acc ounting approach, taking the entire co st times the small probability of occurrence. An assumption is made of a 1 percen t chance of site failure after it is constructed and begins operations.

Well Operation Unit Costs

Table 6 specifies the estimated costs and data sources for well operation unit costs.Technology and Cost Document for the final GS Rule 44 November 2010 Table 6: Well Operation Unit Costs

Tracking Number Cost Item Cost Algorithm Data Sources

E-1 Develop a corrosion monitoring and prevention program 24 hours of engineers @$110.62/hr = $2655 per site Best professional judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

E-2 Corrosion monitoring; quarterly analysis of injectate stream and measurement of corrosion of well material coupons. 6 hours a@ $110.62/hr= $663.72/well plus $25/well (quarterly) plus $300 per sample (4 samples per injection well) Best professional judgement.

E-3 Continuous measurement / monitoring equipment: injected volumes, pressure, flow rates and annulus pressure $15,500/well Best professional judgement.

E-4 Equipment to add tracers $10,400/well Best professional judgement.

E-5 Electricity cost for pump, equipment $0.066/kWh 2007 average industrial sector electricity price reported by EIA.

E-6 Injection well O&M Annual O&M costs are $77,500 + $3.10/ft per well per year Operating and maintenance cost based on EIA Oil and Gas Lease Equipment and Operating Cost estimates.

E-7 Land use rent, rights-of-way $5.20/acre/year Best professional judgement based on oil & gas industry costs. Cost of land rights are highly variable.

E-8 Pore space use costs $0.052/barrel or about $0.36 per metric ton Best professional judgement based on oil & gas industry costs. Cost of land rights are highly variable.
E-9 Property Taxes & Insurance $0.03/$1CAPEX Best professional judgement.

E-10 Tracers in injected fluid $0.05/ton of CO2 injected Best professional judgement. Cost will depend of type of tracer.

E-12 Repair, replace wells and equipment Assume 1%/year of initial well and

e q ui p ment cost Best professional judgement

E-13 General failure of containment at site: cost to remove and relocate CO2 Assuming a 1% chance of failure over injection life, then approximately 0.083% of total capital costs each year would cover such a contin g enc y Best professional judgement

E-14 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 45 November 2010 3.6 Mechanical Integrity Tests

Owners or operators of CO 2 injection wells must periodically evaluate well integrity to ensure mechanical soundness, lack of corrosion, and ability to sustain pressure. There are several such tests that are typically used, a nd they include both pressure tests and wireline logs. These technologies are well establis hed and have been used for decades for underground injection operations.

Internal Mechanical Integrity Tests

An injection well has internal mechanical integrity if it can be demonstrated that there is no leakage in the tubing, casing, or packers. This is differentiated from an ex ternal mechanical integrity that evaluates the bond between casing and rock. Annular pressure under normal operating conditions will be continuously m onitored and recorded as one means of assuring internal mechanical integrity. In addition, periodic internal MITs can be performed. The most common internal periodic MIT is the standard annular pressure test (SAPT). The annulus between the casing and injection tubing is pressured far above normal operating conditions and monitored to see if the pressure holds. 63

EPA and state regulatory agencies have specific requirements for pressure testing injection wells and for performing other mechanical integrity tests. 64,65 Testing occurs prio r to injection and periodically thereafter. Wells that fail the mechanical integrity test must be shut in until repaired, reworked, or plugged. 66 In addition if after a mechanical integrity test is performed, a well operation causes the injection packer to be unseated or if the tubi ng or packer was pulled, repaired, or replaced, the well must be re-t ested for mechanical integrity.

Casing Inspection Log

Following is a definition of the casing inspection log:

An in situ record of casing thickness and inte grity, to determine whether and to what extent the casing has undergone corrosion. The term refe rs to an individual measurement, or a combination of measurements using acoustic, electrical and mechanical techniques, to evaluate the casing thickness and other parame ters. The log is usually presented with the basic measurements and an estimate of metal lo ss. It was first introdu ced in the early 1960s.

63 Carbon Dioxide Storage: Geological Security and Environm ental Issues – Case Study on the Sleipner Field, Norway, S. Soloman, Bellona Foundation, May, 2007.
64 UIC Program Mechanical Integrity Testing: Lessons for Carbon Capture and Storage , Jonathan Koplos, Bruce Kobelski, Anhar Karimjee, and Chi Ho Sham, Fifth Annual Conference on Carbon Capture and Sequestration, DOE/NETL, May, 2006.
65 Determination of the Mechanical Integrity of Injection Wells , EPA Region 5 website, www.epa.gov/region5/water/uic/r5guid/r5_05.htm
66 Underground Injection Control Rules, Montana Board of Oil and Gas Conservation, www.bogc.dnrc. state.mt.us/uicrules.htm

.Technology and Cost Document for the final GS Rule 46 November 2010 Today the terms “casing-evaluation log” and “pipe-inspection log” are used synonymously. 67

Radioactive Tracer Survey of Bottom Hole Cement

A radioactive tracer survey is a mechanical integrity test in which a slug of radioactive material is injected into the well, and gamma ray detection equi pment is used to detect specific movement of the tracer material between the well and the su rrounding rock that indicates problems with the cement, in which the injected material move s in vertical channels outside the casing.

External Mechanical Integrity Test

A number of wireline logg ing tools are used to evaluate external integrity, which is the integrity of the bond between the cement and surrounding rock or between the casing and the cement. These include cement bond, temperature, no ise, and oxygen activation logs. 68 Cement bond logs are used to assess the presence, bond and continuity of cement. Periodic cement bond logs can detect deterioration of the cement through time or any indication of reaction with CO 2
. 69 Descriptions of these technologies are availabl e at the EPA Region 5 website 70

Costs are specified for annual te sts or tests every six months.

Pressure Falloff Tests

A falloff test is a pressure transient test that consis ts of shutting in an in jection well and measuring the pressure falloff. 71 Falloff tests provide injection zone pres sure data and are used to characterize both the injection zone and the completion c ondition of the injecti on well. For Class I nonhazardous injection wells, operators are required to perform the test annually.

Mechanical Integrity Test Unit Costs

Table 7 specifies the estimated costs and data so urces for mechanical integrity test unit costs.

67 http://www.glossary.oilfield .slb.com/Display.cfm?Term=casing-inspection%20log
68 UIC Program Mechanical Integrity Testing: Lessons for Carbon Capture and Storage , Jonathan Koplos, Bruce Kobelski, Anhar Karimjee, and Chi Ho Sham, Fifth Annual Conference on Carbon Capture and Sequestration, DOE/NETL, May, 2006.
69 Carbon Dioxide Storage: Geological Security and Environmental Issues – Case Study on the Sleipner Field

, Norway, S. Soloman, Bellona Foundation, May, 2007.
70 Determination of the Mechanical Integrity of Injection Wells , EPA Region 5 website, www.epa.gov/region5/water/uic/r5guid/r5_05.htm

71 UIC Pressure Falloff Requirements , USEPA Region 9, August, 2002

.Technology and Cost Document for the final GS Rule 47 November 2010 Table 7: Mechanical Integrity Tests Unit Costs

Note: Schedule/periodicity for each unit cost is describ ed in Appendix B (Project Algorithms) of the Cost Analysis of the Final GS Rule. 72

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

After the injection phase has ended, the owner or operator must close the site in a safe and secure manner that protects USDWs from endangerment a nd monitor the site during the PISC period. This involves the plugging of injection we lls, removal of surface equipment, and land restoration. It also includes long term requirements for monitoring the si te to ensure safety and to confirm that the CO 2 moved as expected in the subsurface.

Flush Wells with Buffer Fluid before Plugging

Prior to plugging, the well is flushed with a buffer fluid. This cost includes a fixed component and a cost per inch-foot of casing diameter.

Plug Injection Wells

Upon completion of injection operations and PISC, prio r to site closure, an owner or operator will plug those injection wells not intend ed for further use as monitoring wells. Monitoring wells will be plugged following a phase of l ong-term monitoring. Closure of injection and monitoring wells involves the placement of cement plugs over all or pa rt of the well, with special care taken to seal off USDWs. While most aspects of plugging CO 2 injection wells are similar to procedures used in conventional wells, it may be required to plug more of the well and may be necessary to use

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

Tracking Number Cost Item Cost Algorithm Data Sources

F-1 Internal mechanical integrity pressure tests $2,070/test Best professional judgement.

F-2 Casing inspection log $2,070 plus $4.15/foot Based on 2008 and 2009 PSAC Well Cost Studies for wireline log suite. Cost of MIT lo g could be lower.

F-3 Conduct a tracer survey of the bottom-hole cement using a CO2-soluble isotope $5,200/test Best professional judgement.

F-5 External mechanical integrity test s to detect flow adjacent to well using temperature or noise log $2,070 plus $4.15/foot Based on 2008 PSAC Well Cost Study for wireline log suite. Cost of external MIT log could be lower.

F-6 External mechanical integrity test s to detect flow adjacent to well using temperature or noise log $2,070 plus $4.15/foot Based on 2008 PSAC Well Cost Study for wireline log suite. Cost of external MIT log could be lower.

F-7 Conduct pressure fall-off test $2,070/test Best professional judgement.

F-9 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 48 November 2010 corrosion resistant cement. (Reference: IPCC re port). A guide to the plugging and closure requirements for injection wells is available on the EPA website. 73

Costs are specified as a cost per well for logging and pluggin g. Cement plugging involves two plugs – one in the injection zone and one fr om the surface to the base of the USDWs.

Perform Mechanical Integrity Test Prior to Plugging

An important aspect of proper well closure is mech anical integrity testing. This testing confirms that the casing and cement have integrity and will not provide a pathway for fluid movement. Various types of mechanical integr ity tests are described in the prev ious section. Costs are specified as a base cost per well and cost per foot.

Plug Monitoring Wells

Monitoring wells at the site may be conduits for leakage and also will require eventual plugging after the long-term monitoring period. Costs are specified for three cases:

 Plug monitoring wells above injection zone

 Plug monitoring wells into injection zone

 Plug monitoring wells below injection zone (for waivered wells)

Remove Surface Equipment, Structures, Restore Vegetation

For both injection and monitoring wells, surface e quipment will be removed and the site restored. Injection well site restoration occurs after th e injection period and m onitoring well restoration occurs before closing the site.

Costs are specified for four cases:

 Injection wells

 Monitoring wells above injection zone

 Monitoring wells into injection zone

 Monitoring wells below injec tion zone (waivered wells)

Costs are specified as a fixed cost pe r well and cost per monitoring station.

Document Plugging and Post-Injection Process

This cost item includes the labor costs for notifica tion to regulators of inte nt to cease injection, including well plugging, PISC, and site closure plans.

73 U.S. EPA, http://www.epa.gov/r5water/uic/r5guid/r5_04.htm#iv.Technology and Cost Document for the final GS Rule 49 November 2010 PISC Monitoring Well O&M

The annual costs of operating and maintaining the monitoring wells will extend through the end of the PISC monitoring period. Costs are specified for three cases:

 Monitoring wells above injection zone

 Monitoring wells into injection zone

 Monitoring wells below injec tion zone (waivered wells)

Post-Injection Air and Soil Surveys

The annual costs of air and soil su rveys will extend through the end of the PISC monitoring period. Costs are specified per station per year.

Post- Injection Seismic Surveys

The annual costs of seismic surveys will extend through the end of the PISC monitoring period. Costs are specified on a square mile basis.

Post- Injection Reports to Regulators

Periodic reports to regulators wi ll continue during PISC monitori ng. The frequency and duration of reports is dependent upon the regulatory alternat ive and is specified in Chapter 5 of the Cost Analysis. 74 Costs are specified as labor costs.

Well Plugging, Equipment Removal, and PISC Unit Costs

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

74 Cost Analysis for the Final GS Rule, EPA 816-R-10-013.Technology and Cost Document for the final GS Rule 50 November 2010 Table 8: Well Plugging, Equipment Removal, and PISC Costs

Note: Schedule/periodicity for each unit cost is describ ed in Appendix B (Project Algorithms) of the Cost Analysis of the Final GS Rule. 75

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

Tracking Number Cost Item Cost Algorithm Data Sources

G-1 Flush wells with a buffer fluid before closing $1000 + $0.085/inch-foot casing diameter Best professional judgement.

G-2 Plug injection wells (done to all wells) $13,500 to plug and $11,400 to log (two cement plugs - one in injection

formation and one for surface to bottom of USDWs, remainder of borehole filled with mud ) Plugging and logging cost based on 2008 PSAC Well Cost Study.

G-3 Perform a mechanical integrity test prior to plugging to evaluate integrity of casing and cement to remain in ground $2,070 plus $4.15/foot Based on 2008 PSAC Well Cost Study for wireline log suite.

G-4a Plug monitoring wells ABOVE injection zone $6,700 to plug and $5,700 to log (one cement plugs - surface to bottom of USDWs, remainder of borehole filled with mud ) Plugging and logging cost based on 2008 PSAC Well Cost Study.

G-4b Plug monitoring wells INTO injection zone $6,700 to plug and $5,700 to log (one cement plugs - surface to bottom of USDWs, remainder of borehole filled with mud ) Plugging and logging cost based on 2008 PSAC Well Cost Study.

G-5 Remove surface equipment, structures, restore vegetation (injection wells) $25,900/injection well Best professional judgement.

G-6a Remove surface equipment, structures, restore vegetation (monitoring wells ABOVE injection zone) $10,400/monitoring well, $5,200 for monitoring stations Best professional judgement.

G-6b Remove surface equipment, structures, restore vegetation (monitoring wells INTO injection zone) $10,400/monitoring well, $5,200 for monitoring stations Best professional judgement.

G-7 Document plugging and closure process (well plugging, postinjection plans, notification of intent to close, post-closure report) 120 hours of engineers @$110.62/hr = $13,274 per site Best professional judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

G-8a Post-closure monitoring we ll O&M (ABOVE injection zone) Annual O&M costs are $25,900 + $3.10/ft per well per year Operating and maintenance costs adapted from EIA Oil and Gas Lease Equipment and Operating Cost estimates.

G-8b Post-closure monitoring well O&M (INTO injection zone) Annual O&M costs are $25,900 + $3.10/ft per well per year Operating and maintenance costs adapted from EIA Oil and Gas Lease Equipment and Operating Cost estimates.

G-9 Post-injection air and soil surveys $10,400 per station per year Best professional judgement.

G-10 Post-closure seismic survey $104,000/square mile for good resolution Several published reports are in range of this cost. Cost depends on resolution

(number of lines shot) of survey.

G-11 Periodic post-injection monitoring reports to regulators 40 hours @$110.62/hr = $4,425 per report Best professional judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

G-12 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 51 November 2010 3.8 Financial Responsibility

To ensure that resources are available to protect USDWs from endangerment, today's rule identifies qualifying financial instruments, the time frames over which financial responsibility must be maintained, procedures for estimating the costs of activities covered by the financial instruments, procedures for notifying the Di rector of adverse financial conditions, and requirements for adjusting cost estimates to reflect changes to the project plans. Today’s rule requires the owner or operator to have a detailed written estimate, in current dollars, of the cost of: 1) performing corrective action on wells in the AoR, 2) plugging the injection well(s), 3) PI SC and site closure, and 4) emergency and remedial response. The cost estimate must be prepared separately for each injection activity and be based on the costs to the owner or operator of hiring a third party (who is neither a parent nor a subsidiary of the owner or operator) to perform the activities. The following unit costs were used:

Performance Bond or Demonstration of Financial Ability to Close Site

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

Performance Bond or Demonstration of Financial Ability for PISC

This cost item includes the labor costs to prepare a report demonstrating fina ncial responsibility for post injection monitoring period, including remedi ation. The duration of th e period is dependent upon the regulatory alternative, and is speci fied in Chapter 2 of the Cost Analysis. 76

Financial Responsibility Unit Costs

Table 9 specifies the estimated costs and data so urces for financial res ponsibility unit costs.

Table 9: Financial Responsibility Unit Costs

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

Tracking Number Cost Item Cost Algorithm Data Sources

H-1 Performance bond or demonstrat e financial ability to close site (including an inflation factor) 8 hours @$110.62/hr = $885 per financial report Best professional judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

H-2 Performance bond or demonstrate financial ability for postinjection monitoring, remediation (including an inflation factor) 4 hours @$110.62/hr = $442 per financial report Best professional judgement of time required. Hourly rate derived from SPE 2009 salary survey of petroleum geologists.

H-3 Operating G&A 20% of annual operating costs Best professional judgement based on oil and gas industry factors.Technology and Cost Document for the final GS Rule 52 November 2010 

## 4 Uncertainties in Analysis

As with any technology and cost analysis, there ar e many sources of uncertainty, including current costs and likely future costs. In this analys is, uncertainty is char acterized as follows:

Uncertainties are related to:

 Unit costs of technology (e.g. dollars per foot to drill and complete an injection well)

 Characteristics of the example case which determines how the unit costs are multiplied. (e.g. number of feet to injection zone ) (presented in the Cost Analysis)

 How many times the costs are applied through th e life of the project. (e.g. number of surveys) (presented in the Cost Analysis)

 Number of hours and hourly ra tes 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 workforc e and their experience.

o Labor costs

Uncertainty in Unit Costs Generally speaking, the unit costs for which there is gr eater certainty are those directly or indirectly related to conventional drilling and completion practices and ge ophysical techniques used in exploration and development. This includes drilling costs and day ra tes, 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 pipelin es of different diameters and capacity are known to industry but vary based on market forces a ffecting supply and demand for materials and labor.

In addition to equipment costs, the operating co st component is also well known by region and well characteristics.Technology and Cost Document for the final GS Rule 53 November 2010 Well remediation unit costs are known through conventional oil and gas field development as well as through underground injec tion and EOR projects.

The costs of specialty cements and corrosion resistant tubulars are known to industry, although there is uncertainty as where this will apply and how much impact it will have.

Uncertainty on a unit cost basis for specific technol ogies is larger with s ite characterization and monitoring technologies that are not generally used in the oil and gas industry or rarely used. Factors include a general paucity of data in the literature, the fact that GS technologies are in an early stage of development and are not commercially deployed and because companies do not publicize such individual unit costs due to competit ive factors. In addition, the service companies package these technologies and tailor them to specific projects. EPA has obtained useful information from the literature and from a UIC Technology Conference in New Orleans 77 for the basis of unit costs such as eddy covariance, geochemical testing, a nd tracer injec tion. In addition, unit cost input has been received from the Depa rtment of Energy, public comment on the rule, and other sources. The specific unit co sts of monitoring equipment, for example, do affect the cost analysis, but since the overall uncertainty incl udes how often and how much the technology is applied, the impact of this uncertain ty is expected to be minimal.

It is important to note that th e cost of drilling and completi ng injection and monitoring wells represents a large component of sequestration costs, and thes e costs are relatively well known.

Number of Hours and Hourly Rates Several of the cost categories described in this document are labor inte nsive projects requiring many hours of time at relatively high labor rates. Due to the expected large vari ability in projects, it is difficult to estimate the number of hours requ ired for activities such as geological site characterization. The hours requir ed for such analysis are estimates, while the labor rates are generally known. Uncertainty in la bor rates involves the level of technical expertise required and other factors such as whether the work will be done in-house by employees or contracted out.

Fluctuation in Unit Costs over Time A significant element of uncertainty is associated with potential changes in technology or labor costs through time. As listed above, these may relate to improved technology, changes in the experience of the technical workforce, better understa nding of what informati on is needed and what activities should be implemented, a nd general labor cost changes.

For example, sequestration projects initiated over the next decade or so may incur higher labor costs than those deployed further in to the future, due to a shortage of experienced technical staff that specializes in injection ope rations. As more projects b ecome operational and the technology more developed, costs may decline due to better knowledge and mo re efficient site characterization, operation, a nd monitoring approaches.

77 Joint GWPC/EPA CO2 MMV meeting, New Orleans, LA January 16, 2008.Technology and Cost Document for the final GS Rule 54 November 2010 Overall Cost Analysis Uncertainty Chapter 5 of the Cost Analysis 78 discusses uncertainty related to the overall cost analysis. Briefly, EPA used best professional judgment in determin ing the characteristics of the pro forma projects developed to represent baseline projects for saline and ER sites, the schedule of cost incurrence throughout the period of analysis, and the applicability of each unit cost under each regulatory alternative considered.

Various sources in the literature informed developm ent of the pro forma site characteristics and the number of monitoring stations a nd frequency of monitoring. Howeve r, industry has not yet reached consensus on issues such as the appropriate number of monitoring wells for a GS project.

78 Cost Analysis for the Final GS Rule, EPA 816-R-10-013.Technology and Cost Document for the final GS Rule 55 November 2010 

## 5 Bibliography

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CO 2 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/wate r/uic/r5guid/r5_05.htm Discussion Paper: Identifying Gaps in CO 2 Monitoring and Verification of Storage , by B. Reynen, M. Wilson, N. Riley, T. Manai, O. M. Mathia ssen, and S. Holloway, A Task Force under the Technical Group of the Carbon Sequestration Lead ership Foru, (CSLF), Paper No. CSLF-T-2005- 3, Presented at the Technical Group Meeting, April 30, 2005. Economic Evaluation of CO 2 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- 00NT40937, February, 2003. GEO-SEQ Best Practices Manual, Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation , by the GEO-SEQ Project Team, Earth Sc iences Division, Lawrence Berkeley National Laboratory, Berkeley, California, September 30, 2004. Investigation of Novel Geophysica l Techniques for Monitoring CO 2 Movement during Sequestration, Final Report No. 822176 , by G. M. Hoversten and E. Gasperikova, Lawrence Berkeley National Laboratory, Berk eley 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 Univ ersity 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/statistic s/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.Technology and Cost Document for the final GS Rule 56 November 2010 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. Monitoring Carbon Dioxide Sequestration in De ep Geological Formations for Inventory Verification and Carbon Credits , Paper SPE102833, by S. M. Bens on, Earth Sciences Division, Lawrence Berkeley National Laboratory, for SPE ATCE, San Antonio, Texas, September 26, 2006. Monitoring Geologically Sequestered CO 2 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 Proceedin gs, Fourth Annual Conference on Carbon Capture and Sequestration, DOE/NETL, May 2-5, 2005. Monitoring of Aquifer Disposal of CO 2 : Experience from Underground Gas Storage and Enhanced Oil Recovery , by W. D. Gunter, Alberta Research C ouncil, R. J. Chalaturnyk, University of Alberta, and J. D. Scott, Univer sity of Alberta, for Alberta Res earch Council, Edmonton, Alberta, Canada. Monitoring of Sequestered CO 2 : Meeting the Challenge with Emerging Geophysical Technologies

, S.N. Dasgupta, Saudi Aramco, 2005. Monitoring Protocols and Life-Cycle Cost s 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 Cost s for Geologic Storage of Carbon Dioxide , by S. M. Benson, M. Hoversten, and E. Gasperikova of La wrence Berkeley National Laboratory, and M. Haines of EA Greenhouse Gas R&D Programme, Pro ceedings of the 7th In ternational 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 Ge ological Sequestration of Carbon Dioxide , S. Benson and L. Myer, Lawrence Berkeley La boratory, 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_produc tion/current/coststudy.html Oil and Gas Journal Pipeline Cost Survey , Oil and Gas Journal Magazine, September 3, 2007. Overview of Monitoring Requirement s for Geologic Storage Projects , IEA Greenhouse Gas Programme, Report No. PH4/29, November, 2004. Overview of Monitoring Techniques and Prot ocols for Geological Storage Projects , S. M. Benson, E. Gasperikova, and G. M. Hoversten, IE A 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., C ADE eNews, February 2007.Technology and Cost Document for the final GS Rule 57 November 2010 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 Geophysic s, by L. R. Myer, G. M. Hoversten, and E. Gasperikova, Lawrence Berkel ey National Laboratory, Berkeley California, Proceedings of the 6th Intern ational Conference on Greenhouse Ga s Control Technologies (GHGT6), J. Gale and Y. Kaya (eds.), 1-4 Oct ober 2002, Kyoto, Japan, Pergamon, Vol. 1, pp. 377-382, 2003. Summary of Carbon Dioxide Enhanced Oil Recovery (CO 2 EOR) Injection Well Technology

, supporting information provided by J. P. Meyer, Contek Solutions, for the American Petroleum Institute, 2007. Surface Environmental Monitoring at the Frio CO 2 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 th e Geological Storage of CO 2 , Report No. COAL R285 DTI/Pub URN 05/1033, by J. Pearce, A. Chadwick, M. Bentham, S. Holloway, and G. Kirby, British Geological Survey, Coordinato r of the European Network of Excellence on Underground CO 2 Storage (CO 2 GeoNet), Keyworth, Nott ingham, UK, March 2005. The Economics of CO 2 Storage , Gemma Heddle, Howard Herzog, and Michael Klett, Laboratory for Energy and the Environment, Massachus etts 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, Lawr ence Berkely National Laboratory, Berkely, CA. (publication date unknown). UIC Pressure Falloff Requirements , USEPA Region 9, August, 2002. UIC Program Mechanical Integrity Testi ng: Lessons for Carbon Capture and Storage , Jonathan Koplos, Bruce Kobelski, Anhar Karimjee, and Ch i Ho Sham, Fifth Annual Conference on Carbon Capture and Sequestration, DOE/NETL, May, 2006. Underground Injection Control Rules, www.bogc.dnrc.state.mt.us/uicrules.htm

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