Summary of State Regulations and 

Legislation Related to the Class VI 

Rule 

 
Office of Water (4606M) 

EPA 816-R-10-006 

November 2010 

http://water.epa.gov/drink/
1 

Summary of State Legislation and Regulations Related to the Class VI Rule

Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation.

State Citation Year and Status Description URL

Alabama 

Alaska 

Arizona HB 2542 2008 Sets greenhouse gas emissions limits, provides for 

study identifying opportunities for carbon capture 

and sequestration.

http://www.azleg.gov/legtext/48leg/2r/bills/hb2542p.htm 

Arkansas HB 1592 Introduced February 23, 

2009, withdrawn and 

referred to Joint Interim 

Committee on 

AGRICULTURE, 

FORESTRY & 

ECONOMIC 

DEVELOPMENT on 

March 30, 2009

Provides requirements for obtaining easements for 

carbon dioxide and other oil and gas-related 

pipelines (included as may eventually be related to 

GS).

http://www.arkleg.state.ar.us/assembly/2009/R/Bills/HB159

2.pdf 

California AB 1925 Introduced February 1, 

2006, signed September 

26, 2006, only effective 

until January 2009

Directs reports to state on how CA can provide 

incentives on using GS for CO2 emissions 

reductions. 

http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_1901-

1950/ab_1925_bill_20060201_introduced.html

Colorado HB 06-1281 Signed June 1, 2006 Directs Public Utilities Commission to consider 

proposals by Colorado electric utilities to build 

demonstration power plants using CCSequipped IGCC technology. 

http://www.interwest.org/documents/documents/2007_

co_hb1281.pdf

Colorado HB 07-1203 Signed 2007 Declares that the Governor's Office of Energy 

Management and Conservation to set funding 

for county-level appraisal of greenhouse gas 

mitigation/potential for carbon sequestration 

and creation of a Colorado energy profile.

http://www.leg.state.co.us/clics/clics2007a/csl.nsf/billc

ontainers/D392B1B095DC2B4A87257251007D546D/$FI

LE/1203_enr.pdf

Colorado HB 08-1164 Signed June 2, 2008 Directs the Public Utilities Commission to 

consider the benefits of CO2-EOR when utilities 

come forward with CCS plans.

http://rechargecolorado.com/images/uploads/pdfs/HB1

164.pdf
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 2 

State Citation Year and Status Description URL

Connecticut Substitute HB 

5600, became 

public act No. 08-

98

Effective October 1, 

2008

The original HB stated that the CT Department of 

Environmental Protection may "create 

monitoring and verification requirements to 

ensure the capture and sequestration of carbon 

dioxide." The final act, published in 1998, 

removed this line item. 

http://www.cga.ct.gov/2008/ACT/PA/2008PA-00098-

R00HB-05600-PA.htm

Delaware http://legis.delaware.gov/

Florida HB 549 Signed June 12, 2007 Provides incentives for clean energy 

technologies (but does not specifically mention 

GS).

http://www.myfloridahouse.gov/Sections/Bills/billsdeta

il.aspx?BillId=35055&SessionId=54

Florida Section 253.034 

F.S (law effective 

2008)

 Directs the Division of State Lands to "conduct 

an inventory of certain state lands to determine 

the value of carbon capture and carbon 

sequestration" (part of the Florida Coastal 

Management Program).

http://elobbyist.com/gaits/text/14257ing=&URL=Ch0253/Sec03

4.HTM

Florida Executive Order 

07-128

Signed July 13, 2007 Established the Governor’s Action Team on 

Energy and Climate Change and tasked it with 

creating a comprehensive Florida Energy and 

Climate Change Action Plan. Action team tasked 

to examine carbon capture and storage 

technologies.

http://www.flclimatechange.us/ewebeditpro/items/O12

F15075.pdf

Georgia http://www.legis.ga.gov/legis/2009_10/

Hawaii HB 678 Passed second reading 

on February 9, 2007, no 

further action reported.

Outlines greenhouse gas reduction goals, including 

carbon sequestration as an option to reduce 

emissions. 

http://www.capitol.hawaii.gov/session2007/bills/HB678_.ht

m 

Hawaii HB 226 (now Act 

234)

Signed on July 2, 2007 Similar to above bill, but also creates a task 

force to identify ways to decrease greenhouse 

gas emissions, including carbon sequestration 

(does not specifically mention injection).

http://www.capitol.hawaii.gov/session2007/bills/HB226

_CD1_.htm

Hawaii HB 1054 Carried over to 2010 

legislative session on May 

11, 2009

Transportation energy infrastructure bill encourages 

reduction of CO2 emissions, noting that carbon 

sequestration is permitted (does not note that this is 

for permanent GS).

http://www.capitol.hawaii.gov/session2010/Bills/HB1054_.

htm 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 3 

State Citation Year and Status Description URL

Hawaii HB 1811 Carried over to 2010 

legislative session on May 

11, 2009

Transportation energy infrastructure bill encourages 

reduction of CO2 emissions, noting that carbon 

sequestration is permitted (does not note that this is 

for permanent GS).

http://www.capitol.hawaii.gov/session2010/Bills/HB1811_.

HTM 

Hawaii HB 1466 Carried over to 2010 

legislative session on May 

11, 2009

Transportation energy infrastructure bill encourages 

reduction of CO2 emissions, noting that carbon 

sequestration is permitted (does not note that this is 

for permanent GS).

http://www.capitol.hawaii.gov/session2010/Bills/HB1466_.

HTM 

Idaho 

Illinois HB 1599 (now 

P.A. 92-0012)

Enacted in 2002 Energy and greenhouse gas reduction law, 

allows use of carbon sequestration to reduce 

emissions (does not specifically mention 

injection of CO2).

http://www.commerce.state.il.us/NR/rdonlyres/3A4541

37-ABFF-4689-AD81-

FBE50031BD7A/0/PA920012FullText.pdf

Illinois SB 1187 Session Sine Die, 

January 13, 2009

Creates the Global Warming Response Act, which 

listed carbon sequestration as an option to help 

reduce greenhouse gas emissions (does not 

specifically mention injection of CO2).

http://www.ilga.gov/legislation/billstatus.asp?DocNum=118

7&GAID=9&GA=95&DocTypeID=SB&LegID=29272&Sessi

onID=51 

Illinois HB 1135 Session Sine Die, 

January 13, 2009

Creates the Clean-Coal Project Indemnification Act 

as part of the Future Gen project.

http://www.ilga.gov/legislation/billstatus.asp?DocNum=113

5&GAID=9&GA=95&DocTypeID=HB&LegID=29829&Sessi

onID=51 

Illinois HB 1777 Session Sine Die, 

January 13, 2009

Creates "the Clean Coal FutureGen for Illinois Act 

for the purpose of providing the FutureGen Alliance 

with adequate liability protection, land use rights, 

and permitting certainty to facilitate the siting of the 

FutureGen Project in Illinois." 

http://www.ilga.gov/legislation/BillStatus.asp?DocNum=17

77&GAID=9&DocTypeID=HB&LegId=30606&SessionID=5

1&GA=95 

Illinois SB 1704 (now 

Public Act 95-

0018)

Signed July 30, 2007 Provides the FutureGen Alliance with adequate 

liability protection and permitting certainty to 

facilitate the siting of the FutureGen Project in 

the State of Illinois.

http://www.ilga.gov/legislation/BillStatus.asp?DocType

ID=SB&DocNum=1704&GAID=9&SessionID=51&LegID

=29844
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 4 

State Citation Year and Status Description URL

Illinois SB 1987 (now 

P.A. 95-1027)

Signed January 2009 aka "Clean Coal Portfolio Standard Act" (PL 095-

1027); amends the Illinois Power Agency Act, 

requiring utilities to purchase 5 percent of their 

electricity from “initial” clean coal facilities. It 

also requires these clean coal facilities to offset 

any exceedance of their emission standards.

http://ilga.gov/legislation/BillStatus.asp?DocTypeID=S

B&DocNum=1987&GAID=9&SessionID=51&LegID=352

38

Illinois HB 3854 (now 20 

ILCS 5005/15)

Signed August 25, 2009 Creates a commission to study the legal issues 

surrounding sequestration. The commission has 

until December 31, 2010 to recommend 

legislation.

http://www.ilga.gov/legislation/ilcs/documents/0020500

50K15.htm

Illinois HB 1823 Referred to Assignments 

on April 3, 2009

Creates a commission to study the legal issues 

surrounding sequestration. The commission has 

until December 31, 2010 to recommend legislation.

http://www.ilga.gov/legislation/fulltext.asp?DocName=&Se

ssionId=76&GA=96&DocTypeId=HB&DocNum=1823&GAI

D=10&LegID=43610&SpecSess=&Session= 

Illinois SB 2660 Effective 7/28/2010 Requires alternative retail electric suppliers to 

report total amount of CO2 captured and stored, 

and if 90% of emissions not captured and 

stored, must seek carbon credits from some 

other source. 

http://www.ilga.gov/legislation/fulltext.asp?DocName=

&SessionId=76&GA=96&DocTypeId=SB&DocNum=266

0&GAID=10&LegID=49641&SpecSess=0&Session=0

Illinois SB 2550 Referred to assignments, 

7/27/10

Extends provisions requiring alternative retail 

electric suppliers to report total amount of CO2 

captured and stored, and if 90% of emissions not 

captured and stored, must seek carbon credits from 

some other source. 

http://www.ilga.gov/legislation/fulltext.asp?DocName=&Se

ssionId=76&GA=96&DocTypeId=SB&DocNum=2550&GAI

D=10&LegID=49276&SpecSess=&Session= 

Illinois SR 0491 Referred to Assignments 

on November 30, 2009

Requires natural gas facilities serving over 100,000 

people to work together to finance the Southern 

Illinois Coal to SNG Facility in Jefferson County.

http://www.ilga.gov/legislation/fulltext.asp?DocName=&Se

ssionId=76&GA=96&DocTypeId=SR&DocNum=0491&GAI

D=10&LegID=48808&SpecSess=&Session= 

Illinois SB 0380 Placed on Calendar Order 

of Concurrence House 

Amendment(s) 1 - May 4, 

2010 

Requires that the Coal Technology Development 

Assistance fund be used for capturing and storing 

CO2, and conducting research on capture and 

sequestration of CO2. (suggested edits to current 

law 20 ILCS 687/6-5).

http://www.ilga.gov/legislation/fulltext.asp?DocName=&Se

ssionId=76&GA=96&DocTypeId=SB&DocNum=380&GAID

=10&LegID=41243&SpecSess=&Session= 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 5 

State Citation Year and Status Description URL

Illinois 220 ILCS 3855/1-

80

Effective 6/1/09 Requires that new coal facilities be sited where 

GS is possible, and all must be clean coal 

technologies, and a GS facility may be 

constructed.

http://www.ilga.gov/legislation/publicacts/95/095-

1027.htm

Illinois SB 1592 (now 

public law 095-

0481)

Enacted August 28, 

2007

Allows Agency to develop electric or renewable 

energy facilities with preference given to 

facilities in locations favorable to GS, using 

carbon capture technologies.

http://www.ilga.gov/legislation/publicacts/95/095-

0481.htm

Indiana SB 224 2008 (cannot search for 

status of older bills on IN's 

legislative Web site)

Provides financial incentives and tax credits for 

clean energy, including CCS.

http://www.in.gov/legislative/bills/2008/SB/SB0224.1.html 

Indiana HB 1117 2008 (cannot search for 

status of older bills on IN's 

legislative Web site)

Provides tax incentives for coal gasification 

technologies, including CCS.

http://www.in.gov/legislative/bills/2008/HB/HB1117.1.html 

Indiana SB 211 2010, In committee, 1st 

house

Delineates the jurisdiction of the department of 

environmental management, the utility regulatory 

commission, and the department of natural 

resources with respect to various aspects of carbon 

dioxide transportation and storage.

http://www.in.gov/legislative/bills/2010/PDF/IN/IN0211.1.pd

f 

Indiana IC 8-1-8.8 2005 and 2007 Encourages use of coal gasification and other 

clean energy technologies that reduce 

greenhouse gas emissions to take advantage of 

the supply of high-sulfur coal in the Illinois 

basin. (Does not specifically mention GS) (Clean 

Energy Law).

http://www.in.gov/legislative/ic/code/title8/ar1/ch8.8.ht

ml 

Indiana SB 0115 In committee, 2nd house 

(Feb 2010)

Allows entities that have right to transport CO2 by 

pipeline eminent domain.

http://www.in.gov/legislative/bills/2010/SB/SB0115.1.html 

Iowa SF2226 Signed April 27, 2010 Imposes a moratorium on building coal plants 

for five years unless they capture and store 90% 

of CO2 emissions over the life of the project. 

Iowa utilities board is to set standards and 

requirements for GS applications.

http://coolice.legis.state.ia.us/CoolICE/default.asp?Category=BillInfo&Service=Billbook&

ga=83&menu=text&hbill=SF2226
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 6 

State Citation Year and Status Description URL

Iowa SF192 Status unknown. Requires the Department of Natural Resources to 

conduct a study on feasibility of GS, due by January 

1, 2009.

http://coolice.legis.state.ia.us/CoolICE/default.asp?category=billinfo&service=billbook&GA=8

3&hbill=SF192 

Iowa HF 2271 Subcommittee, Feb 4, 

2010

Provides for tax credits and for providing 

certifications of GS by the state.

http://coolice.legis.state.ia.us/CoolICE/default.asp?category=billinfo&service=billbook&GA=8

2&hbill=HF2271ation&fn=default.htm&xhitlist_d=currentlegislation 

Iowa Chapter 168 

(469.9)

Enacted, date not 

available

Sets up a fund ("State Power Fund") to support 

renewable, and clean energy and technologies 

to reduce greenhouse gasses, including GS.

http://search.legis.state.ia.us/nxt/gateway.dll/acts/2007

acts/1/176?fn=document-frame.htm$f=templates$3.0

Kansas HB 2419 Signed 2007 Kansas Carbon Dioxide Reduction Act 2007. http://www.kslegislature.org/bills/2008/2419.pdf

Kansas HB 2429 2007, no notes provided 

on bill status

Creates a fund for research and development of 

reclamation and energy technologies including 

carbon sequestration (does not specifically mention 

injection).

http://www.kslegislature.org/bills/2008/2429.pdf 

Kansas HB 2765 2008, no notes provided 

on bill status 

Requires CCS to help the state meet its electricity 

needs in the future.

http://www.kslegislature.org/bills/2008/2765.pdf 

Kansas SB 553 2008 Creates a cap and trade program, including off-sets 

for GS of CO2.

http://www.kslegislature.org/bills/2008/553.pdf 

Kansas HB 303 Signed 2006 Kansas Energy Development Act (2006). http://www.kslegislature.org/bills/2006/303.pdf

Kansas K.A.R. 82-3-1100 

– 82-3-1120; 82-3-

311a.

February 11, 2010, Final Final Regulations. See Appendix A for 

preliminary comparison with the Final Class VI 

Rule.

Kentucky HB 1 Signed August 30, 2007 Provides incentives for clean energy 

technologies, including CCS. 

http://www.lrc.ky.gov/record/07s2/HB1.htm
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 7 

State Citation Year and Status Description URL

Kentucky HB 213 Sent to house Rules 

committee on March 26, 

(2010 legislative session)

Creates eminent domain for CO2 pipelines for 

sequestration activities. Amendments to bill include 

placing the pipelines under the authority of the 

Kentucky State Board on Electric Generation and 

Siting, removes the authority under the Kentucky 

Division of Oil and Gas. Kentucky Public Service 

commission would be granted responsibility for 

monitoring pipelines.

http://www.lrc.ky.gov/record/10rs/hb213.htm 

Kentucky HB 491 Posted in committee on 

March 2 (2010 legislative 

session)

Declares that CO2 capture and storage is an 

important goal; directs "the Division of Oil and Gas 

Conservation to develop a regulatory plan for 

development of geologic carbon dioxide storage 

including condemnation powers; provide minimum 

requirements for permitting", covers eminent domain 

issues where KY declares ownership of certain 

geologic strata. 

http://www.lrc.ky.gov/record/10rs/hb491.htm 

Kentucky HB 588 Sent to Appropriations 

and Revenue committee 

on March 25 (2010 

legislative session)

Provides tax incentives for GS of CO2. http://www.lrc.ky.gov/record/10rs/hb588.htm 

Kentucky HB 351 Posted in committee on 

February 21 (2009 

legislative session)

Creates definitions for CO2 storage and capture, 

establishes requirements for GS, monitoring of 

carbon and protection of public health and safety.

http://www.lrc.ky.gov/record/09rs/hb351.htm 

Kentucky HB 716/ 08RS Sent to Tourism 

Development and Energy 

committee on March 4 

(2008 legislative session). 

Defeated.

Requires electric utilities to conduct studies on 

research, development, and pilot studies on CO2 

reducing activities, including CCS.

http://www.lrc.ky.gov/record/08rs/hb716.htm 

Kentucky HB 767/ 08RS Reassigned to 

Appropriations & Revenue 

in the Senate on April 

14th (2008 legislative 

session)

Provides economic incentives for constructing coal 

gasification plant with GS or retrofit a plant with GS 

capabilities using US Department of Energy or 

FutureGen funds if available.

http://www.lrc.ky.gov/record/08rs/hb767.htm 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 8 

State Citation Year and Status Description URL

Louisiana HB 1117 Signed June 17, 2008 Authorizes the Commissioner of Conservation to 

regulate CO2 injections and establishes 

procedures to obtain leases for storage 

facilities. 

http://65.36.200.64/720DE/assets/files/lawarticles/DOC_

00062.pdf

Louisiana HB 1220 Signed July 2, 2008 Authorizes the State Mineral Board to enter into 

contracts, and assume responsibility for 

sequestration storage facilities. 

http://www.legis.state.la.us/billdata/streamdocument.a

sp?did=483706

Louisiana SB 10 Signed by Governor as 

Act 450 on July 8, 2009

Grants a state and local sales and use tax 

exclusion for "manmade or anthropogenic 

carbon dioxide used in a "qualified tertiary 

recovery project" which has a severance tax 

exemption until the project reaches "payout." 

http://law.justia.com/louisiana/codes/15/86944.html

Louisiana HB 661 Signed July 10, 2009; 

effective August 15, 

2009

Louisiana Geologic Sequestration of Carbon 

Dioxide Act. 

http://www.louisianalawblog.com/uploads/file/HB661(1).pdf

Maine HP 1506/ LD2126 Signed on April 9, 2008 An Act on reducing emissions to mitigate 

climate change; notes that where carbon is 

captured and permanently stored are not 

counted as emissions from a facility. 

http://www.mainelegislature.org/legis/bills/bills_123rd/

billtexts/HP150601.asp

Maryland SB 309/HB 712 Passed third reading in 

house on March 22, 2008, 

was scheduled for hearing 

in senate on April 2, 2008, 

no further status updates 

provided

Requires 25% reduction in greenhouse gas 

emissions, including the use of carbon sequestration 

to reduce emissions (does not specifically mention 

injection). 

http://mlis.state.md.us/2008rs/billfile/sb0309.htm 

Maryland Maryland Code 2-

1206

2009 Provides for use of carbon sequestration 

projects in reducing greenhouse gas emissions 

(does not specifically mention GS of CO2). 

http://www.michie.com/maryland/lpext.dll?f=templates

&fn=main-h.htm&2.0

Maryland Maryland Code 2-

1209

2009 Requires a report by 2015 on progress made 

towards meeting emissions reduction plan by 

2020; calls for a review of science, technologies, 

and costs of these technologies that can reduce 

emissions, including carbon sequestration. 

http://www.michie.com/maryland/lpext.dll?f=templates

&fn=main-h.htm&2.0
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 9 

State Citation Year and Status Description URL

Massachusetts HB 3337 2007, status unknown Promotes use of GS with coal gasification to 

encourage use of least cost technologies for 

electricity generation.

Not found

Massachusetts S2457 3-Mar-08 Promotes the use of renewable energy and 

energy efficiency, and includes coal gasification 

technologies using CCS technologies in its 

definition of "alternative energy generating 

source."

http://www.mass.gov/legis/bills/senate/185/st02/st0245

7.htm

Massachusetts S1503 Filed 1/14/09, public 

hearing date set for 

4/15/09 

Lists gasification with CCS technology as part of 

alternative energy portfolio.

http://www.mass.gov/legis/bills/senate/186/st01pdf/ST0150

3.PDF 

Massachusetts S1940 Accompanied by a study 

order, April 29, 2008. As 

of 1/6/09, no further action 

on the study bill (S2645)

Lists gasification with CCS technology as part of 

alternative energy portfolio.

http://www.mass.gov/legis/bills/senate/185/st01/st01940.ht

m 

Massachusetts S2594 2008 Lists gasification with CCS technology as part of 

alternative energy portfolio.

http://www.mass.gov/legis/bills/senate/st02/st02594.htm 

Massachusetts S2768/H4373 Signed July 2, 2008 as 

An Act Relative to 

Green communities 

(Chapter 169, 2008)

Directs the Department of Energy Resources to 

establish an alternate energy portfolio standard, 

and states that CCS could be used to meet the 

standard. 

http://www.mass.gov/legis/bills/senate/st02/st02594.ht

m

Michigan SB 0707 Referred to Committee on 

Natural Resources and 

Environmental Affairs on 

September 4, 2007. 

Defeated.

Establishes requirements for CO2 injection wells. http://www.legislature.mi.gov/documents/2007-

2008/billintroduced/Senate/htm/2007-SIB-0707.htm 

Michigan SB 0708 (passage 

was tied to the 

passage of SB 

0707)

Referred to finance 

committee on September 

4, 2007. Defeated.

Exempts a coal-fired electric generating facility that 

captures or sequesters all CO2 emissions from the

collection of taxes under the General Property Tax 

Act.

http://www.legislature.mi.gov/(S(skz1n3eeld4f3v45muwq5s

45))/mileg.aspx?page=getobject&objectname=2007-SB0708&query=on
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 10

State Citation Year and Status Description URL

Michigan SB 801 (passage 

was tied to the 

passage of SB 

0707)

Referred to finance 

committee on September 

23, 2007. Defeated.

Provides a tax credit equal to the cost of purchasing 

or constructing CO2 capture machinery or 

equipment. 

http://www.legislature.mi.gov/(S(skz1n3eeld4f3v45muwq5s

45))/mileg.aspx?page=getobject&objectname=2007-SB0801&query=on 

Michigan HB 5604 Introduced January 1, 

2008, filed on January 10, 

2008. Defeated.

Provides a tax credit equal to the number of tons of 

eligible reductions in emissions of CO2 multiplied 

by the per ton market price for commodity CO2 

and/or the critical capacity in tons of critical CO2 

sequestration infrastructure multiplied by the per ton 

market price for commodity CO2.

http://www.legislature.mi.gov/(S(skz1n3eeld4f3v45muwq5s

45))/mileg.aspx?page=getobject&objectname=2007-HB5604&query=on 

Michigan SB 1164 Introduced March 4, 2008, 

referred to Energy Policy 

and Public Utilities on 

March 4, 2008

Creates a clean energy fund, authority for CO2 GS 

wells, and tax credits for clean energy technologies.

http://www.legislature.mi.gov/documents/2007-

2008/billintroduced/Senate/htm/2008-SIB-1164.htm 

Michigan SB 1166 Introduced, and referred 

to Energy Policy and 

Public Utilities on March 

4, 2008

Provides a tax credit equal to the cost of 

"purchasing, leasing, or constructing carbon dioxide 

capture machinery, equipment, or pipeline 

infrastructure and the cost of materials used in 

preparing, maintaining, or capping a carbon dioxide 

injection well." 

http://www.legislature.mi.gov/documents/2007-

2008/billintroduced/Senate/htm/2008-SIB-1166.htm 

Michigan HB 4016 Introduced on January 22, 

2009; printed bill filed on 

January 27, 2009

Provides a tax credit equal to the cost of 

"purchasing, leasing, or constructing carbon dioxide 

capture machinery, equipment, or pipeline 

infrastructure and the cost of materials used in 

preparing, maintaining, or capping a carbon dioxide 

injection well." 

http://www.legislature.mi.gov/(S(skz1n3eeld4f3v45muwq5s

45))/mileg.aspx?page=getobject&objectname=2009-HB4016&query=on 

Michigan SB 775 Introduced and referred to 

Natural Resources and

Environmental Affairs 

Committee on August 27, 

2009. Referred to Energy 

Policy and Public Utilities 

committee on September 

17, 2009

Authorizes a permitting regime for CCS and the 

creation of a carbon dioxide storage trust fund. 

http://www.legislature.mi.gov/(S(skz1n3eeld4f3v45muwq5s

45))/mileg.aspx?page=getobject&objectname=2009-SB0775&query=on 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 11

State Citation Year and Status Description URL

Michigan HB 5253 Introduced and referred to 

the Committee on Energy 

and Technology on 

August 19, 2009, printed 

bill was "filed" on August 

20, 2009

Proposes new legislation regarding permitting and 

liability of carbon capture schemes. 

http://www.legislature.mi.gov/(S(skz1n3eeld4f3v45muwq5s

45))/mileg.aspx?page=getobject&objectname=2009-HB5253&query=on

Minnesota HB 1666 Referred to Environment 

and Natural Resources 

Finance Division on 

March 13, 2007. 

Defeated.

Requires studies by the Minnesota Geological 

survey on GS of CO2 storage capacity in the 

Midcontinental Rift system in the state, and sets up 

a $90,000 fund to conduct the research.

https://www.revisor.mn.gov/bin/bldbill.php?bill=H1666.1.ht

ml&session=ls85

Minnesota 116J.437 2008 Requires emissions reductions, and permitting 

CCS as a way to reduce emissions (does not 

specifically mention CO2 injection) ("Green 

Economy Law").

https://www.revisor.mn.gov/statutes/?id=116J.437&ye

ar=2009&keyword_type=all&keyword=carbon+sequest

ration

Minnesota 216B.1694 2003 Provides incentives to construct a CO2 GS 

facility, and encourages seeking funding from 

U.S. Department of Energy and U.S. Department 

of Agriculture.

https://www.revisor.mn.gov/statutes/?id=216B.1694&y

ear=2009&keyword_type=all&keyword=carbon+seques

tration

Minnesota HF 2390 Introduced and referred to 

Energy Finance and 

Policy committee on May 

15, 2009

Exempts GS of CO2 from the greenhouse gas 

control plan.

https://www.revisor.mn.gov/revisor/pages/search_status/st

atus_detail.php?b=House&f=HF2390&ssn=0&y=2009 

Minnesota HF 799/ SF 0724 Introduced and referred to 

Tax committee on 

February 16, 2009

Creates tax incentives for GS. https://www.revisor.mn.gov/revisor/pages/search_status/st

atus_detail.php?b=House&f=HF0799&ssn=0&y=2009 

Minnesota S.F. 2096 

(Chapter 57)

Signed May 8, 2007 Appropriates $90,000 for a study of geologic 

sequestration capacity in Minnesota.

https://www.revisor.mn.gov/laws/?id=57&doctype=Cha

pter&type=0&year=2007

Minnesota CHAPTER 136--

S.F. No. 145

Signed May 25, 2007 GS noted as part of Next Generation Energy Act 

of 2007. 

https://www.revisor.mn.gov/laws/?id=136&doctype=Ch

apter&type=0&year=2007
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 12

State Citation Year and Status Description URL

Mississippi HB 1459 Signed March 31, 2009 Levies a gross income tax of 1.5% on 

businesses engaged in the “sale of naturally 

occurring carbon dioxide and anthropogenic 

carbon dioxide lawfully injected into the earth 

for: 1) Use as an enhanced oil recovery project, 

including, but not limited to, use for cycling, 

repressuring or lifting of oil; or 2) Permanent 

sequestration in a geological formation.” 

http://billstatus.ls.state.ms.us/documents/2009/pdf/HB/

1400-1499/HB1459SG.pdf

Mississippi HB 1458/SB 2567 Died in committee on 

February 25, 2009

Levies taxes on businesses engaged the sale of 

CO2 for EOR or sequestration.

http://billstatus.ls.state.ms.us/2009/pdf/history/HB/HB1458.

xml 

Mississippi SB 2867 Died in committee on 

February 2, 2010

Authorizes the Oil and Gas Board to have 

responsibility for GS wells.

http://billstatus.ls.state.ms.us/2010/pdf/history/SB/SB2867.

xml 

Missouri HB 2038 Marked as public hearing 

completed on March 2, 

2010. Defeated

Limits personal liability in case of death or injury due 

to a CO2 GS well or project.

http://www.house.mo.gov/content.aspx?info=/bills101/bills/

hb2038.htm 

Missouri SB 391 Introduced May 7, 2009, 

was on calendar for 

perfection on May 15, 

2009

Limits personal liability in case of death or injury due 

to a CO2 GS well or project.

http://www.senate.mo.gov/09info/pdf-bill/comm/SB391.pdf 

Missouri HB 896 Marked as public hearing 

completed on March 24, 

2009

Limits personal liability in case of death or injury due 

to a CO2 GS well or project.

http://www.house.mo.gov/billtracking/bills041/billpdf/intro/H

B0896I.PDF 

Missouri HB 1666 4/8/08 - Motion failed to 

pass (from Special 

Committee on Energy and 

Environment)

Requires Air Conservation Commission to develop 

plan that would identify opportunities for emission 

reductions measures from all verifiable and 

enforceable voluntary actions, including, but not 

limited to, carbon sequestration projects and best 

management practices.

http://www.house.mo.gov/billtracking/bills081/biltxt/intro/HB

1666I.htm 

Montana HB 3 Signed May 25, 2007 Provides tax incentives for energy development, 

including use of geologic sequestration of 

carbon dioxide.

data.opi.mt.gov/bills/specsess/0507/BillPdf/HB0003.pd

f 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 13

State Citation Year and Status Description URL

Montana HB 24 Signed May 3, 2007, but 

contingent on passage of 

SB 218. SB 218 died in 

Standing Committee on 

4/27/07 (Committee of 

Natural Resources) 

Attempts to extend eminent domain powers to CO2 

transmission and geologic sequestration. Act 

provides common carrier status to pipelines moving 

carbon dioxide and specifies that this designation 

only applies to pipelines transporting carbon dioxide 

to permanent sequestration in a geologic formation.

data.opi.mt.gov/bills/2007/BillPdf/HB0024.pdf 

Montana HB 25 Signed May 17, 2007 Requires any new coal-fired plant to sequester

50 percent of its emissions in order for its 

application for “acquisition of an equity interest 

or lease” to be approved. 

www.pewclimate.org/docUploads/montanaHB0025%20

(2).pdf 

Montana SB 498 Signed May 6, 2009 Authorizes the Montana Board of Oil and Gas 

Commission to regulate the injection of carbon 

dioxide. Permitting/Property Rights. Declares 

pore space the property of the surface owner, 

assigns ownership of injected CO2 to the 

operator, gives mineral rights primacy and 

provides for unitization for GS sites. The state is 

directed to accept long-term liability and a fund 

is created to pay for regulatory costs, 

remediation, long-term stewardship.

data.opi.mt.gov/bills/2009/billpdf/SB0498.pdf

Nebraska LB 957 2000 - bill introduced to 

review its purpose in 

2007, not resolved as of 

2008 session

Establishes Carbon Sequestration Advisory 

Committee.

http://www.legislature.ne.gov/FloorDocs/96/PDF/Final/LB9

57.pdf 

Nevada 

New Hampshire 

New Jersey S 2976 and A 4559 Introduced 12/3/2007. 

Fiscal estimate 1/10/2008.

Authorizes auction of greenhouse gas allowances; 

establishes "Global Warming Solutions Fund".

http://www.njleg.state.nj.us/2006/Bills/A5000/4559_E1.PD

F 

New Mexico EO 2006-69 Signed December 28, 

2006

Requests a study of geologic sequestration in 

New Mexico. 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 14

State Citation Year and Status Description URL

New Mexico SB 994 Signed April 3, 2007 Establishes tax credits of up to $60 million per 

plant to encourage electricity generation by 

solar thermal technology or by coal gasification 

technology with sequestration of carbon dioxide 

emissions or by use of exhaust heat currently 

lost.

 

New Mexico SB 145 Introduced January 21, 

2010, final house vote 

approving regulation on 

February 18, 2010, 

current location: Senate 

concurrence calendar

Defines ownership of pore space; owner of surface 

land owns pore space beneath; surface owner may 

transfer rights to pore space. 

http://www.nmlegis.gov/lcs/_session.aspx?chamber=S&leg

type=B&legno=%20%20%20145&year=10

New York AO5836A Introduced on February 

20, 2009; amended and 

referred to environmental 

conservation on May 1, 

2009

Authorizes the Department of Environmental 

Conservation to permit storage sites, declares that 

pore space is owned by the surface estate, and 

grants regulated public utilities and municipal 

electric corporations condemnation rights for pore 

space. 

http://assembly.state.ny.us/leg/?bn=A05836 

New York A. 8802 (also S. 

53303) NY 

legislative site 

indicates that 

AO8802 is the 

same as SB06163

Introduced June 2009; 

01/06/2010 referred to 

environmental 

conservation; 06/08/2010 

held for consideration in 

environmental 

conservation

Applies to a specific pilot project only (in 

Jamestown, New York). 

http://assembly.state.ny.us/leg/?default_fld=&bn=+A08802

%09%09&Summary=Y&Actions=Y&Text=Y 

New York SB 06163 Introduced and referred to 

Rules Committee on 

September 10, 2009, 

Advanced to Third 

Reading on March 18, 

2010

Creates a pilot program for municipal owned electric 

generating facilities that submit an application by 

December 31, 2010. 

http://assembly.state.ny.us/leg/?bn=S06163 

North Carolina 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 15

State Citation Year and Status Description URL

North Dakota SB 2095 Signed in March 2009 Instructs Industrial Commission to set rules for 

GS. Assigns ownership of injected CO2 to the 

operator, gives mineral rights primacy, and 

provides for unitization. Directs state to accept 

long-term liability, establishes fund for 

regulatory costs, remediation, and long-term 

stewardship.

http://www.legis.nd.gov/assembly/61-2009/billstatus/senate/index.aspx?ls=61 

North Dakota SB 2139 Signed April 8, 2009 Addresses pore space ownership. http://www.legis.nd.gov/assembly/61-2009/billstatus/senate/index.aspx?ls=61 

North Dakota SB 2034 Signed April 8, 2009 Creates a permanent exemption from the oil 

extraction tax for incremental production from a 

tertiary recovery project that uses carbon 

dioxide.

http://www.legis.nd.gov/assembly/61-2009/billstatus/senate/index.aspx?ls=61 

North Dakota SB 2221 Signed April 22, 2009 Creates a credit against coal conversion 

privilege taxes for facilities that achieve a 

required level of carbon dioxide capture. 

http://www.legis.nd.gov/assembly/61-2009/billstatus/senate/index.aspx?ls=61 

North Dakota NDAC Chapter 

43-05-01

Effective April 1, 2010 North Dakota Industrial Commission, Oil and 

Gas Division. Proposed rules published on 

September 16, 2009 (NDAC Chapter 43-05-01). 

Final rule effective as of April 1, 2010. See 

Appendix B for preliminary comparison with the 

Final Class VI Rule.

http://www.legis.nd.gov/information/acdata/html/..%5C

pdf%5C43-05-01.pdf 

Ohio H.C. R. No 25 Passed Ohio House June 

30, 2009

Establishes a concurrent resolution: Any proposed 

new environmental or energy legislation enacted by 

Congress should promote and encourage new 

technologies such as zero-emission advanced 

nuclear power, biomass energy, fuel cells, and clean 

coal with carbon capture and sequestration with a 

goal to bring such technologies to market as quickly 

as possible. 

http://www.legislature.state.oh.us/ResolutionText128/128_

HCR_25_I_N.html 

Ohio HB 357 Introduced 10/18/07, 

assigned to Alternative 

Energy Committee

Expands the laws governing energy development to 

include carbon capture (GS). 

http://www.legislature.state.oh.us/analysis.cfm?ID=127_H

B_357&ACT=As%20Introduced&hf=analyses127/h0357-i127.htm 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 16

State Citation Year and Status Description URL

Oklahoma SB 1765 Enacted May 22, 2008, 

approved by governor 

on June 3, 2008

Creates the Oklahoma Geologic Storage of 

Carbon Dioxide Task Force. 

http://webserver1.lsb.state.ok.us/WebBillStatus/main.h

tml 

Oklahoma SB 679 Signed May 8, 2009 Extends the report deadline for the Oklahoma 

Geologic Sequestration Task Force until 

December 15, 2009. 

 

Oklahoma SB 1326 Signed May 1, 2010 Reauthorizes task force. 

Oklahoma SB 610 Signed June 1, 2009 Establishes the "Geologic Storage of Carbon 

Dioxide Act," which authorizes the Department 

of Environmental Quality to issue CCS permits 

under certain terms and conditions. Assigns 

ownership of injected CO2 to the operator and 

gives mineral rights primacy.

http://webserver1.lsb.state.ok.us/WebBillStatus/main.h

tml 

Oklahoma SB 2024 3/31/10 Enacting clause 

stricken

Establishes the Oklahoma Carbon Capture and 

Geologic Sequestration, Transportation and 

Investment Act.

http://webserver1.lsb.state.ok.us/WebBillStatus/main.html 

Oklahoma §27A-3-4-101 

through 105

Effective July 1, 2009 Establishes a Carbon Sequestration Certification 

Program, which sets requirements for receiving 

certification of carbon sequestration activities, 

including GS. 

http://www.ok.gov/conservation/Agency_Divisions/Wat

er_Quality_Division/WQ_Carbon_Sequestration/Legisl

ation/WQ_Carbon_Sequestration_Enhancement_Act.h

tm l

Oregon 

Pennsylvania SB 92 and HB 80 Signed March 2009 HB 

80 was "removed from 

table" by PA House on 

April 21, 2010. SB 92 

was referred back to the 

Environmental 

Resources and Energy 

subcommittee in March 

2009.

Directs the Department of Conservation and 

Natural Resources to develop and operate a CO2 

sequestration network utilizing appropriate 

geologic formations and facilities on State forest 

land; also sets up fund. 

http://www.legis.state.pa.us/cfdocs/billinfo/billinfo.cfm

?syear=2009&sind=0&body=H&type=B&BN=0080

Pennsylvania SB 266 Signed July 9, 2008 Directs the Department of Environmental 

Protection to conduct a climate study, which 

must include a discussion of CCS. 

http://www.legis.state.pa.us/cfdocs/billinfo/billinfo.cfm

?syear=2007&sind=0&body=S&type=B&bn=0266 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 17

State Citation Year and Status Description URL

Pennsylvania HB 1202 Signed July 10, 2008 Authorizes the substitution of CTL derived 

diesel for the State's biodiesel mandate, 

provided that the fuel's carbon emissions are 

offset "through carbon sequestration." 

http://www.legis.state.pa.us/cfdocs/billinfo/billinfo.cfm

?syear=2007&sind=0&body=H&type=B&bn=1202 

Pennsylvania HB 2405 Was referred to the 

Environmental Resources 

and Energy subcommittee 

on April 23, 2010. 

Provides for permits for geologic sequestration and 

title to carbon dioxide; sets up immunity and liability 

transfer; establishes CO2 indemnification fund; 

provides for carbon dioxide sequestration facility and 

transportation pipeline on Commonwealth State 

forest lands; and provides for application of the 

Public Utility Code to transporters of CO2.

http://www.legis.state.pa.us/cfdocs/billinfo/billinfo.cfm?syea

r=2009&sind=0&body=H&type=B&bn=2405 

Rhode Island S 523 Introduced February 11, 

2010, Referred to Senate 

Environment & Agriculture

Provides a 20 percent credit for all qualified energy 

research expenses paid or incurred in 2009 or 2010. 

Qualified energy research expenses are qualified 

research expenses related to the fields of fuel cells 

and battery technology, renewable energy, energy 

conservation technology, efficient transmission and 

distribution of electricity, and carbon capture and 

sequestration.

http://www.rilin.state.ri.us/search/search.idq?CiRestriction=

carbon+sequestration&CiMaxRecordsPerPage=10&CiSort

=rank[d]&Abstractt=1&HTMLQueryForm=/search/search.a

sp&CiScope=/&x=30&y=18 then search for S523 

South Carolina 

South Dakota HB 1129 Signed March 11, 2009 Requires the Public Utilities Commission to 

regulate carbon dioxide pipelines. 

legis.state.sd.us/sessions/2009/Bills/HB1129ENR.pdf 

Tennessee 

Texas HB 149 Signed May 31, 2006 Directs the Railroad Commission to be 

responsible for the CO2 from the FutureGen 

program. 

http://www.capitol.state.tx.us/BillLookup/History.aspx

?LegSess=793&Bill=HB149

Texas HB 469 Signed June 19, 2009 Provides tax incentives for projects that capture 

and sequester CO2.

http://www.capitol.state.tx.us/BillLookup/History.aspx

?LegSess=81R&Bill=HB469

Texas HB 1796 Passed June 2009 Provides that the state accepts liability during 

operations and ownership of injected CO2 for 

offshore GS on public lands.

http://www.capitol.state.tx.us/BillLookup/History.aspx

?LegSess=81R&Bill=HB1796
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 18

State Citation Year and Status Description URL

Texas SB 1387 Signed May 27, 2009, 

effective September 9, 

2009

Provides that injected CO2 is property of the 

operator. Creates fund for long-term monitoring, 

remediation and enforcement.

http://www.capitol.state.tx.us/BillLookup/History.aspx

?LegSess=81R&Bill=SB1387

Texas HB 3732/SB 1785 Effective 9/1/07 Establishes the ultra-clean energy project grant 

and loan program, to be administered by the 

State Energy Conservation Office no later than 

1/1/08. Projects able to capture, sequester, or 

abate carbon dioxide emissions are eligible. If 

EPA regulates CO2, then TCEQ must create 

rules which list pollution controls, including 

projects to capture carbon dioxide from an 

anthropogenic source in Texas that is 

geologically sequestered in Texas.

http://www.legis.state.tx.us/billlookup/History.aspx?Le

gSess=80R&Bill=HB3732

Texas Proposed October 15, 

2010

Proposed Rule. See Appendix C for preliminary 

comparison with the Final Class VI Rule.

http://info.sos.state.tx.us/pls/pub/regviewer$ext.RegPage?

sl=R&app=1&p_dir=&p_rloc=228152&p_tloc=&p_ploc=&p

g=1&p_reg=228152&ti=16&pt=1&ch=5&rl=1

Utah SB 202, SB 202 

Substitute, and 

Utah Energy 

Resource 

Procurement Act 

(2008, part of SB 

202) 

Effective 2008 Directs a workgroup to establish administrative 

procedures/rules for the implementation of 

carbon capture and geologic sequestration in 

Utah.

le.utah.gov/~2008/bills/sbillenr/sb0202.pdf 

Utah Substitute SB 128 March 8, 2010, bill 

defeated in Senate

City and county carbon credits for sequestration of 

waste stream materials.

http://le.utah.gov/~2010/htmdoc/sbillhtm/SB0128S01.htm 

Utah HJR 12 Effective March 5, 2009 Joint Resolution Supporting Hydrogen Power 

from Advanced Coal and Carbon Capture and 

Sequestration Technology.

le.utah.gov/~2009/bills/hbillenr/hjr012.pdf 

Vermont 
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 19

State Citation Year and Status Description URL

Virginia SB 247 Introduced on 13 January 

2010. Passed by the 

Committee on Agriculture, 

Conservation and Natural 

Resources on 25 January 

2010.

Provides the Director of the Department of Mines, 

Minerals and Energy with the jurisdiction and 

authority to regulate and issue permits for CCS 

activities. The Bill also includes provisions for longterm liability and creates a Carbon Dioxide Storage 

Facility Trust Fund.

http://leg1.state.va.us/cgibin/legp504.exe?101+sum+SB247

Virginia SB 1416/HB 3068 

(CHAP0933)

Enacted 4/11/07 Allows utilities to recover an enhanced rate of 

return on common equity associated with the 

type of project, which may include projects 

utilizing nuclear power, renewable technologies, 

carbon capture facilities, combined cycle 

combustion turbines, and conventional coal 

facilities. 

http://leg1.state.va.us/cgibin/legp504.exe?071+sum+SB1416

Virginia SB 464, Governor 

Acts of Assembly 

CHAP 0822

Effective May 12, 2008 Establishes Virginia Commission on Energy and 

Environment as a legislative study commission 

to review and recommend steps to implement 

the Virginia Energy Plan (see notes in next row).

http://leg1.state.va.us/cgibin/legp504.exe?081+ful+CHAP0882

Virginia SB 267 January 12, 2010 passed 

in Senate but bill failed in 

House

Requires the Division of Energy to present drafts of 

updates to the Virginia Energy Plan to the 

Commission on Energy and Environment; ensures 

the Commission's responsibility to review and 

consider the direct and indirect impacts of energy 

production and use on the Commonwealth's 

environment and natural resources; and allows the 

Commission to review and consider the impact of 

environmental laws, regulations, and initiatives on 

the Commonwealth's energy supplies.

http://leg1.state.va.us/cgi-bin/legp504.exe?101+ful+SB267

Virginia SB 446 January 9, 2008, failed to 

report from Committee on 

Commerce and Labor on 

February 9, 2008

Requires that by a certain year electric energy sold 

by each supplier to retail customers be generated 

from renewable generation energy sources. 

Requires new facility to be carbon capture 

compatible.

http://leg1.state.va.us/cgibin/legp504.exe?081+sum+SB446

Washington Substitute SB 

6001 

Effective July 22, 2007 Sets GHG emission reductions. http://apps.leg.wa.gov/billinfo/summary.aspx?bill=600

1&year=2007
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 20

State Citation Year and Status Description URL

Washington Washington 

Administrative 

Code, Chapter 

173-218

Promulgated June 19, 

2008

Final rule, Underground Injection Control 

Program. Includes GS provisions. See Appendix 

D for preliminary comparison with the Final 

Class VI Rule.

 

West Virginia HB 2860 Signed by the governor 

May 26, 2009

Establishes a CO2 GS working group to develop 

a long-term strategy for the regulation of carbon 

dioxide sequestration in WV. Final report of work 

group is due in July 2011. 

http://www.legis.state.wv.us/bill_status/bills_text.cfm?

billdoc=hb2860%20enr%20sub.htm&yr=2009&sesstyp

e=rs&i=2860

Wisconsin Assembly Bill 649 

and SB 450

Introduced 1/6/10 and 

1/7/10, both failed to pass 

Senate Joint Resolution 

as of 4/28/10.

Contains numerous provisions relating to reducing 

GHG emissions (including GS), creating energy 

efficiency and promoting use of renewable 

resources to produce energy.

http://nxt.legis.state.wi.us/nxt/gateway.dll?f=templates&fn=

default.htm&d=billhist&jd=top

Wisconsin SB 81 March 6, 2007 Establishes development grants for renewable 

resource projects.

http://www.legis.state.wi.us/

Wisconsin Clearance Rule 

02-012

Effective 11/1/02 Establishes a voluntary multi-pollutant emission 

reduction registry (mentions GS).

http://www.legis.state.wi.us/rsb/code/nr/nr437.pdf

Wyoming SB 1 Effective July 1, 2008 Provides an appropriation for evaluation of 

potential carbon dioxide sequestration sites and 

activities related to the advancement for clean 

coal and carbon management activities.

http://legisweb.state.wy.us/2008/billif.htm

Wyoming HB 90 Effective July 1, 2008 Creates of a subclass of wells for CO2 GS. legisweb.state.wy.us/2008/Introduced/HB0090.pdf

Wyoming HEA 8 (HB 57) Enacted 2009 Reaffirms that the mineral estate is dominant 

regardless of who owns the pore space.

Wyoming HEA 18 (HB 89) Effective 7/1/08 Pore ownership (now 34-1-153). legisweb.state.wy.us/2008/Bills/HB0089.pdf

Wyoming HEA 20 (HB 58) Effective 7/1/09 Declares that the operator owns injected CO2 

and is liable for any effects of geologic 

sequestration.

http://legisweb.state.wy.us/2009/2009sesslaws.pdf

Wyoming HEA 25 (HB 90) Effective 7/1/08 Permit requirements. http://legisweb.state.wy.us/2009/2009sesslaws.pdf

Wyoming HEA 42 (HB 80) Effective 7/1/09 Unitization of GS sites. http://legisweb.state.wy.us/2009/2009sesslaws.pdf
Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 21

State Citation Year and Status Description URL

Wyoming HEA 26 (HB 17) Effective 7/1/10 Sets up a GS revenue account, insurance and 

liability requirements for GS well owners; also 

appears that this bill would repeal 35-11-313.

legisweb.state.wy.us/2010/Bills/HB0017.pdf 

Wyoming Final as of September 

17, 2010

Wyoming Department of Environmental Quality 

Water Quality Rules and Regulations, Chapter 

24: Class VI Injection Wells and Facilities, 

Underground Injection Control Program. See 

Appendix E for preliminary comparison with the 

Final Class VI Rule.

http://legisweb.state.wy.us/statutes/statutes.aspx?file=

titles/Title35/T35CH11AR3.htm
A-1 

Final Class VI Rule

(pre-publication version signed by the Administrator 

November 22, 2010)

on 

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

Applicability

§146.81 - Applicability

• This rule applies to any wells used to inject carbon 

dioxide specifically for the purpose of geologic 

sequestration. 

• Also applies to owners or operators of permit- or ruleauthorized Class I, Class II, or Class V experimental 

carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well 

or wells. 

§146.81 (d) - Definitions

Geologic sequestration (GS) means the long-term 

containment of a gaseous, liquid, or supercritical CO2 

stream in subsurface geologic formations. This term does 

not apply to CO2 capture or transport.

Geologic sequestration project means an injection well or 

wells used to emplace a CO2 stream beneath the 

lowermost formation containing a USDW; or, wells used 

for geologic sequestration of CO2 that have been granted 

a waiver of the injection depth requirements pursuant to 

requirements at §146.95; or, wells used for geologic 

sequestration of CO2 that have received an expansion to 

the areal extent of an existing Class II enhanced oil 

recovery or enhanced gas recovery aquifer exemption 

pursuant to §§146.4 of this chapter and 144.7(d). It 

includes the subsurface three-dimensional extent of the 

CO2 plume, associated area of elevated pressure, and 

displaced fluids, as well as the surface area above that 

delineated region.

Site closure means the point/time, as determined by the 

Director following the requirements under §146.93, at 

which the owner or operator of a geologic sequestration 

site is released from post-injection site care 

responsibilities.

Post-injection site care means appropriate monitoring 

and other actions (including corrective action) needed 

following cessation of injection to ensure that USDWs are 

not endangered, as required under §146.93.

This state regulation does not have an Applicability 

section. 

This rule applies to entities that shall operate a CO2 

storage facility. 

82-3-1100. Definitions: CO2 storage facilities.

CO2 storage means the storage of CO2 in geologic 

strata that have been converted for CO2 storage.

CO2 storage facility means the leased acreage and CO2 

storage reservoir. This term shall include the CO2 

storage well, well bore tubular goods, the wellhead, and 

any related equipment, including the last positive shutoff 

valve attached to the flow line. 

CO2 postclosure period means the time after the

CO2 closure period in which all wells are plugged and

monitoring of the storage reservoir is no longer 

necessary because the plume is stable and is not a 

threat to public health and safety or usable water.

CO2 closure period means the period of time

from the permanent cessation of active injection or 

withdrawal operations until the beginning of the CO2 

postclosure period. During this period, the operator is 

responsible for activities that include the following:

(1) Monitoring the plume’s pressure;

(2) monitoring the horizontal and vertical extent of

the plume; and

(3) monitoring plugged and abandoned wells.

Permit Conditions

§146.82 Required Class VI permit information. 82-3-1101 - 82-3-1105. Permit application, notice, 

amendments, transfer, and cancellation. 

Prior to the issuance of a construction or conversion 

permit, the owner or operator must submit the following:

• Information required in 40 CFR 144.31 (e)(1) - (6); 

• Map showing the injection well, the applicable AoR, 

and faults, if known or suspected;

Permit application conditions in this state regulation 

appear similar to the federal rule. An additional 

requirement of this state regulation is noted below. 

Each application shall contain the following information: 

Appendix A

Kansas: Permanent Administrative Regulations 

Under Article 3 (Production and Conservation of Oil and Gas) 

Preliminary Comparison with the Final Class VI Rule
A-2 

• Information on the geologic structure and 

hydrogeologic properties; 

• Tabulation of all wells within the AoR which penetrate 

the injection or confining zone(s); 

• Maps and stratigraphic cross sections indicating all 

USDWs, water wells and springs within the AoR, their 

positions relative to the injection zone(s), and the 

direction of water movement, where known; 

• Baseline geochemical data on subsurface formations;

• Proposed operating data; 

• Proposed pre-operational formation testing program; 

• Proposed stimulation program; 

• Proposed procedure to conduct injection operation; 

• Schematics of the construction details of the well; 

• Injection well construction procedures; 

• Proposed AoR and corrective action plan; 

• A demonstration of financial responsibility; 

• Proposed testing and monitoring plan; 

• Proposed injection well plugging plan; 

• Proposed post-injection site care and site closure plan; 

• Proposed alternative post-injection site care timeframe;

• Proposed emergency and remedial response plan; 

• A list of contacts identified to be within the AoR; and

• Any other information requested by the Director. 

The Director shall notify, in writing, any States, Tribes, or 

Territories within the AoR of the Class VI project of the 

permit application. 

Prior to granting approval for the operation of a Class VI 

well, the Director shall consider the following: 

• Final AoR based on modeling, using data obtained 

during logging and testing of the well and the 

formation; 

• Any relevant updates to the information on the geologic 

structure and hydrogeologic properties of the proposed 

storage site and overlying formations; 

• Information on the compatibility of the CO2 stream with 

fluids in the injection zone(s) and minerals in both the 

injection and the confining zone(s); 

• Results of the formation testing program;

• Final injection well construction procedures;

• Status of corrective action on wells in the AoR; 

• All available logging and testing program data on the 

well;

• A demonstration of mechanical integrity;

• Any updates to the any of the plans; and

• Any other information requested by the Director.

Owners or operators seeking a waiver of the requirement 

to inject below the lowermost USDW submit a 

supplemental report.

• Statement confirming that the applicant holds the 

necessary property and mineral rights for construction 

and operation of the CO2 storage facility. 

[KAR 82-3-1101(13)]

Notice of application for permit

§124.10 Public notice of permit actions and public 

comment period.

For Class VI injection well UIC permits, mailing or 

emailing a notice to State and local oil and gas regulatory 

agencies and State agencies regulating mineral 

exploration and recovery, the Director of the Public Water 

82-3-1102. Notice of application for permit and

protest. 

The notice of permit application conditions in this state 

regulation appear comprehensive, but differ from the 

federal rule in specific language throughout. 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)
A-3 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

Supply Supervision program in the State, and all 

agencies that oversee injection wells in the State.

This Kansas regulation requires the applicant to notify 

specific operators and landowners rather than the 

regulatory agencies only. See below for details.

Each applicant for a permit to operate a CO2

storage facility shall give notice on or before the date the

application is filed with the conservation division by

mailing or delivering a copy of the application to the 

following:

• Each operator or mineral lessee of record within onehalf mile of the boundary of the storage facility;

• Each owner of record of the minerals in unleased 

acreage within one-half mile of the boundary of the 

storage facility; and

• Each landowner on whose land the storage facility will 

be located.

The applicant shall publish notice of the application in 

the official county newspaper, the Kansas Register, and

the Wichita Eagle newspaper.

The applicant shall give any additional notice that the 

director deems necessary to ensure due process.

The application shall be held in abeyance for 30 days 

from the date of last publication or delivery of notice,

whichever is later. 

Geologic Site Characterization

§146.83 Minimum criteria for siting. 

A geologic system comprises: 

• An injection zone(s) of sufficient areal extent, 

thickness, porosity, and permeability to receive the 

total anticipated volume of the CO2 stream. 

• Confining zone(s) free of transmissive faults or 

fractures and of sufficient areal extent and integrity to 

contain the injected CO2 stream and displaced 

formation fluids and allow injection at proposed 

maximum pressures and volumes without initiating or 

propagating fractures in the confining zone(s).

• At the Director’s discretion, additional zones that will 

impede vertical fluid movement, are free of faults and 

fractures that may interfere with containment, allow for 

pressure dissipation, and provide additional 

opportunities for monitoring, mitigation, and 

remediation.

Siting requirements are not included in this state

regulation, but siting information is required from the 

owner or operator.

Each permit application shall contain a geologic, 

hydrogeologic, and reservoir evaluation of the proposed 

CO2 storage facility, including the predicted amount of 

CO2 that will be stored in the reservoir. The evaluation 

shall describe the geologic, geomechanic,

hydrogeologic, and reservoir characteristics of the 

proposed CO2 storage reservoir or reservoirs, the 

adjacent confining layer or layers, and the reservoir 

conditions that control the trapping mechanism.

[KAR 82-3-1101(c)(5)] 

While the Kansas regulation mentions there may be 

more than one confining layer, there is no mention that 

the Director can require secondary confining zones. 

AoR and Corrective Action

§146.84 AoR and corrective action. 

The AoR is the region surrounding the geologic 

sequestration project where USDWs may be endangered 

by the injection activity. The AoR is delineated using

computational modeling that accounts for the physical 

and chemical properties of all phases of the injected CO2

stream and is based on available site characterization, 

monitoring, and operational data. 

Part of the permit application, submit a plan that includes:

• Method for delineating the AoR; 

An AoR and corrective action plan is not included in this 

Kansas regulation. However, an AoR evaluation must be 

included in the permit application. Also, the regulation 

does not require computational modeling or periodic reevaluations of the AoR. 

Each permit application shall contain an area of review 

evaluation, which shall be certified by a licensed 

geologist or licensed engineer and shall include the 

following: 
A-4 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

• Description of the minimum fixed frequency, not to 

exceed five years, to reevaluate the AoR; monitoring 

and operational conditions that would warrant an 

earlier reevaluation; how monitoring and operational 

data will be used to inform a reevaluation; how 

corrective action will be conducted; how corrective 

action will be adjusted if there are changes in the AoR;

and how site access will be guaranteed for future 

corrective action.

To delineate the AoR and identify all wells that require 

corrective action, perform the following: 

• Predict, using existing site characterization, monitoring 

and operational data, and computational modeling, the 

projected lateral and vertical migration of the CO2

plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient 

to cause the movement of injected fluids or formation 

fluids into a USDW are no longer present, or until the 

end of a fixed time period as determined by the 

Director. The rule further describes the requirements of 

the model; 

• Identify all penetrations, including active and 

abandoned wells and underground mines, in the AoR 

that may penetrate the confining zone(s); and 

• Determine which abandoned wells in the AoR have 

been plugged. 

At the minimum fixed frequency, not to exceed five years, 

or when monitoring and operational conditions warrant: 

• Reevaluate the AoR; 

• Identify all wells in the reevaluated AoR that require 

corrective action; 

• Perform corrective action on wells requiring corrective 

action in the reevaluated AoR; and

• Submit an amended AoR and corrective action plan or 

demonstrate to the Director through monitoring data 

and modeling results that no amendment to the AoR 

and corrective action plan is needed. 

The emergency and remedial response plan and the 

demonstration of financial responsibility must account for 

the AoR delineated, regardless of whether or not 

corrective action in the AoR is phased.

All modeling inputs and data used to support AoR 

reevaluations shall be retained for 10 years.

• A review of the data of public record and all available 

records for all wells that penetrate the CO2 storage 

reservoir and those wells that penetrate the CO2 

storage reservoir within one-fourth mile of the 

boundary of the CO2 storage facility. This review shall 

determine if all the abandoned wells have been 

plugged in a manner that prevents the movement of 

CO2 or associated fluids from the CO2 storage 

reservoir and if all unplugged wells that penetrate the 

CO2 storage reservoir have adequate cement to 

isolate the storage interval from other reservoirs in the 

well and from behind the casing; and

• Identification of any wells that appear from a review of 

public records to be unplugged or improperly plugged 

or any unplugged or improperly plugged wells of which 

the applicant has actual knowledge. 

[KAR 82-3-1101(c)(7)]

Financial Responsibility

§146.85 Financial responsibility. 

The demonstration of financial responsibility in this state 

regulation appears less comprehensive than the federal 

rule. A demonstration of financial responsibility must be 

included in the permit application.

Each application shall contain a demonstration of 

financial responsibility to ensure proper operation and 

closure of the CO2 storage facility. The form and amount 

of financial responsibility shall be approved by the 

Director. Adjustments to the financial responsibility may 

The owner or operator must demonstrate and maintain 

financial responsibility as approved by the Director, until 

the Director approves the completed post-injection site 

care and site closure plan and approves site closure. The 

owner or operator may be released from a financial 

instrument in the certain circumstances.

The financial responsibility instrument(s) used must: 

• Be from the list of qualifying instruments; 

• Be sufficient to cover the cost of corrective action, 
A-5 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

injection well plugging, post injection site care and site 

closure, and emergency and remedial response; 

• Be sufficient to address endangerment of USDWs; and 

• Comprise protective conditions of coverage, including

at a minimum cancellation, renewal, and continuation 

provisions, specifications on when the provider 

becomes liable in case of cancellation if there is a 

failure to renew with a new qualifying financial 

instrument, and requirements for the provider to meet a 

minimum rating, minimum capitalization, and ability to

pass the bond rating when applicable. 

Have a detailed written estimate, in current dollars, of the 

cost of performing corrective action on wells in the AoR, 

plugging the injection well(s), post-injection site care and 

site closure, and emergency and remedial response. 

• The cost estimate must be performed for each phase 

separately and must be based on the costs to the 

regulatory agency of hiring a third party. 

• During the active life of the geologic sequestration 

project, the owner or operator must adjust the cost 

estimate for inflation within 60 days prior to the 

anniversary date of the establishment of the financial 

instrument. The Director must approve this change. 

• Whenever the current cost estimate increases/ 

decreases, the face amount of the financial assurance 

instrument may be increased/reduced to the amount of 

the current cost estimate only after the receipt of 

written approval from the Director. 

Notify the Director by certified mail of adverse financial 

conditions that may affect the ability to carry out injection 

well plugging and post-injection site care and site 

closure. 

Provide an adjustment of the cost estimate to the Director 

within 60 days of notification by the Director, if the 

Director determines during the annual evaluation of the 

qualifying financial responsibility instrument(s) that the 

most recent demonstration is no longer adequate to 

cover the cost of corrective action, injection well plugging, 

post-injection site care and site closure, and emergency 

and remedial response. 

The Director must approve the use and length of pay-inperiods for trust funds or escrow accounts. 

be required by the Director. 

[KAR 82-3-1101(c)(15)] 

Monetary penalties may be assessed by the commission 

against any CO2 storage facility operator violating any of 

the provisions of K.A.R. 82-3-1100 through K.A.R. 82-3-

1119.

[KAR 82-3-1120] 

Construction Requirements

§146.86 Injection well construction requirements. 82-3-1106. Well construction requirements.

All materials (e.g. casing and cementing materials, tubing 

and packer materials, cement and cement additives) 

used in construction must be compatible with fluids with 

which the materials may be expected to come into 

contact and must meet or exceed standards.

Casing and Cementing of Class VI Wells.

• The owner or operator must provide the quantitative 

information requested in the rule.

• Surface casing must extend through the base of the 

lowermost USDW and be cemented to the surface 

through the use of a single or multiple strings of casing 

Construction requirements in this state regulation appear

similar to federal rule. Exceptions are noted below.

All casing strings that are set in the well bore shall be 

cemented with a sufficient volume of cement to fill the 

annular space to a point 500 feet above the top of the 

CO2 storage reservoir or to the surface, whichever is 

less. 

[KAR 82-3-1106(c)]

Liners set within casing shall have cement circulated

from the bottom of the liner to the top of the liner. If 
A-6 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

and cement. 

• At least one long string casing, using a sufficient 

number of centralizers, must extend to the injection 

zone and must be cemented by circulating cement to 

the surface in one or more stages. 

• Circulation of cement may be accomplished by staging.

The Director may approve an alternative method.

Tubing and Packer.

• All owners or operators must inject fluids through 

tubing with a packer set at a depth opposite a 

cemented interval at the location approved by the 

Director. 

• The owner or operator must submit the quantitative 

information requested in the rule.

cement does not circulate, the annulus between the liner 

and casing shall be equipped in a way that the annulus

can be monitored and tested for mechanical integrity.

[KAR 82-3-1106(f)]

Each CO2 injection or withdrawal well located within 330 

feet of an inhabited residence, commercial 

establishment, church, school, or small, well-defined 

outside area shall be equipped with a down-hole safety 

shutoff. 

[KAR 82-3-1106(k)]

For tubing completions, the packer shall be set no more

than 50 feet above the uppermost perforation or open

hole of the CO2 storage reservoir. 

[KAR 82-3-1106(o)]

Logging, Sampling and Testing

§146.87 Logging, sampling, and testing prior to 

injection well operation.

82-3-1106. Well construction requirements.

During drilling and construction, the owner or operator 

must run appropriate logs, surveys and tests to 

determine or verify the depth, thickness, porosity, 

permeability, and lithology of, and the salinity of any 

formation fluids in all relevant geologic formations and 

then submit a descriptive report prepared by a 

knowledgeable log analyst that includes an interpretation 

of the results of such logs and tests.

At a minimum, such logs and tests must include:

• Deviation checks. 

• Before and upon installation of the surface casing:

- Resistivity, spontaneous potential, and caliper logs 

before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• Before and upon installation of the long string casing:

- Resistivity, spontaneous potential, porosity, caliper,

gamma ray, fracture finder logs, and any other logs 

the Director requires before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• A series of mechanical integrity tests, which may 

include:

- A pressure test with liquid or gas;

- A tracer survey such as oxygen-activation logging;

- A temperature or noise log;

- A casing inspection log. 

• Any alternative methods that are required by and/or 

approved of by the Director. 

Take whole cores or sidewall cores of the injection zone 

and confining system and formation fluid samples from 

the injection zone(s), and submit to the Director a 

detailed report prepared by a log analyst that includes: 

well log analyses, core analyses, and formation fluid 

sample information. 

Record fluid temperature, pH, conductivity, reservoir 

Construction requirements in this Kansas regulation 

state that newly drilled wells shall demonstrate internal 

and external mechanical integrity before use for CO2 

injection, as required in K.A.R. 82-3-1112 and that a well 

summary report is required. See below for details.

Information on existing wells and wells to be drilled or 

reentered shall include the following:

• A plan specifying the drilling, completion, or 

conversion procedures;

• A well bore schematic showing the name, description, 

construction, and depth of each well drilled or 

proposed to be drilled; 

• A description of the casing, tubing, and packer

including a full description of cement already in place 

or as proposed; 

• The proposed method of testing the wells to 

demonstrate mechanical integrity of the casing, 

tubing, and packer before use; and

• For existing wells and wells to be reentered, all 

available geophysical logs through the storage 

reservoir and cased-hole logs including gamma ray, 

neutron curves, cement bond log, and temperature 

log. For wells to be drilled, the information shall 

include a complete open-hole wireline log measuring 

rock formation parameters of spontaneous potential, 

resistivity, gamma ray, and neutron density through 

the storage reservoir and cased-hole logs, including 

gamma ray, neutron curves, cement bond log, and 

temperature log. Each log shall be annotated to 

identify the estimated location of the base of the 

deepest usable water formation, showing the 

stratigraphic position and thickness of all confining 

strata above the storage reservoir and the 

stratigraphic position and thickness of the storage 

reservoir. An alternative log may be used if the 

director determines that the alternative log is 

substantially equivalent to one of the logs specified. 

• An alternative log may be used, if approved by the 

director.

[KAR 82-3-1106(c): Well construction requirements.] 
A-7 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

pressure, and static fluid level of the injection zone(s).

Determine or calculate injection and confining zone(s) 

fracture pressure; physical and chemical characteristics 

of the injection and confining zone(s) and formation fluids 

in the injection zone(s).

Conduct pressure fall-off test and a pump test or

injectivity tests upon completion, but prior to operation, to 

verify hydrogeologic characteristics of the injection 

zone(s).

Provide the Director with the opportunity to witness all 

logging and testing. Submit a schedule of such activities 

to the Director 30 days prior to conducting the first test. 

All newly drilled wells shall demonstrate internal and 

external mechanical integrity before use for CO2 

injection, as required in K.A.R. 82-3-1112.

[KAR 82-3-1106(i): Well construction requirements.] 

Operating Requirements

§146.88 Injection well operating requirements. 

Ensure that injection pressure does not exceed 90 

percent of the fracture pressure of the injection zone(s) 

so as to ensure that the injection does not initiate new 

fractures or propagate existing fractures in the injection 

zone(s). All stimulation must be approved by the Director 

as part of the permit application and incorporated into the 

permit. 

Injection between the outermost casing protecting 

USDWs and the well bore is prohibited.

Fill the annulus between the tubing and the long string 

casing with a non-corrosive fluid approved by the 

Director. Maintain on the annulus a pressure that 

exceeds the operating injection pressure, unless the 

Director determines otherwise. 

Maintain mechanical integrity of the injection well at all 

times, other than during periods of well workover 

approved by the Director.

Install and use: 

• Continuous recording devices to monitor: the injection 

pressure; the rate, volume and/or mass, and 

temperature of the CO2 stream; and the pressure on 

the annulus between the tubing and the long string 

casing and annulus fluid volume; and

• Alarms and automatic surface shut-off systems or, at 

the discretion of the Director, down-hole shut-off 

systems (e.g., automatic shut-off check valves) for 

onshore wells or, other mechanical devices that 

provide equivalent protection; and

• Alarms and automatic down-hole shut-off systems for 

wells located offshore but within State territorial waters, 

designed to alert the operator and shut-in the well 

when operating parameters diverge beyond permitted 

ranges. 

If a shutdown is triggered or a loss of mechanical integrity 

is discovered, immediately investigate and identify as 

expeditiously as possible the cause of the shutoff. If, 

upon such investigation, the well appears to be lacking 

mechanical integrity: 

Operating requirements are described in the following 

sections: CO2 storage facility; permit application. [KAR 

82-3-1101], well construction requirements [KAR 82-3-

1106], report of leak, potential leak, or loss of 

containment [KAR 82-3-1113]. Requirements that 

appear to differ from the federal rule are noted below.

The operating pressure of a CO2 storage facility shall 

not be greater than 75% of the fracture gradient for the 

storage reservoir as measured in PSIG. 

[KAR 82-3-1101(c)(9)]

Each CO2 injection or withdrawal well located within 330 

feet of an inhabited residence, commercial 

establishment, church, school, or small, well-defined 

outside area shall be equipped with a down-hole safety 

shutoff. 

[KAR 82-3-1106(k)]

If a CO2 storage well fails to demonstrate mechanical 

integrity, the operator shall either repair and retest the 

storage well to demonstrate mechanical integrity; or plug 

the storage well according to K.A.R. 82-3- 1118, within 

90 days.

[KAR 82-3-1112(g)]

The storage facility shall have a continuously operating

supervisory control and data acquisition (SCADA) 

system approved by the director to monitor operations

for each individual CO2 storage well. The SCADA 

system shall be connected by a communication link with 

the local control room or any remote control center for 

service and maintenance crews. If an emergency

occurs, the equipment shall be capable of automatically

closing all inlets and outlets to the CO2 storage facility. 

Each sensor or indicator shall be calibrated annually,

and the documentation shall be kept for five years.

[KAR 82-3-11073(f)] 

Each operator shall report each leak, each potential 

leak, and any pressure changes or other monitoring data 

that indicate a loss of containment of injected CO2 or 

associated fluids. The report shall be made orally and be 
A-8 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

• Immediately cease injection;

• Take all steps reasonably necessary to determine 

whether there may have been a release of the injected 

CO2 stream or formation fluids into any unauthorized 

zone;

• Notify the Director within 24 hours;

• Restore and demonstrate mechanical integrity to the 

satisfaction of the Director prior to resuming injection; 

• Notify Director when injection is expected to resume.

confirmed in writing within three business days following 

the oral report.

[KAR 82-3-1113(a)]

The operator shall submit a written summary of the

cause(s) within 10 days following the written report in 

above. The summary shall also evaluate whether the 

situation poses a threat to public health and safety,

usable water, or property. 

[KAR 82-3-1113(b)] 

Within 30 days following the summary report required by 

above, the operator shall submit an action plan to repair 

the leak or regain containment for the conservation 

division’s review and approval. 

[KAR 82-3-1113(c)] 

The installation of observation or monitoring wells may 

be required by the director to gain additional information 

about the leak or loss of containment.

[KAR 82-3-1113(d)] 

Additional reports may be required by the Director until 

the leak or loss of containment is remediated.

[KAR 82-3-1113(e)] 

Mechanical Integrity

§146.89 Mechanical integrity. 82-3-1112. Mechanical integrity testing.

A Class VI well has mechanical integrity if there is no 

significant leak in the casing, tubing, or packer; and there 

is no significant fluid movement into a USDW through 

channels adjacent to the injection well bore.

To evaluate the absence of significant leaks, following an 

initial annulus pressure test, continuously monitor 

injection pressure, rate, injected volumes; pressure on 

the annulus between tubing and long-string casing; and 

annulus fluid volume. 

 

At least once per year, use an approved tracer survey or

temperature or noise log to determine the absence of 

significant fluid movement. 

 

If required by the Director, the owner or operator must 

run a casing inspection log to determine the presence or 

absence of corrosion in the long-string casing. 

The Director may require additional or alternative tests to 

evaluate mechanical integrity. 

To obtain approval for a new mechanical integrity test, 

the Director must submit a written request to the 

Administrator and the Administrator may approve the 

request. Any alternate method approved by the 

Administrator will be published in the Federal Register

and may be used in all States. 

The owner or operator and the Director must apply 

methods and standards generally accepted in the 

industry. When the owner or operator reports the results 

of mechanical integrity tests to the Director, he/she shall 

Mechanical integrity requirements in this state regulation 

appear similar to federal proposed rule. Exceptions are 

noted below.

Demonstrate internal integrity by performing a 

successful pressure test on each CO2 storage well 

before placing the storage well in operation and at least 

once every two years thereafter. 

• A minimum fluid pressure of 300 psig shall be applied 

to the tubing casing annulus at the surface for a period 

of 30 minutes. Internal mechanical integrity shall be 

demonstrated if the applied pressure does not 

decrease by more than 10 percent.

[KAR 82-3-1112(c)]

Demonstrate external integrity at least once every four 

years by cased hole logs. A minimum of a gamma ray, 

neutron, and temperature logs shall be run from 50 feet 

above the point of injection continuously to the surface. 

[KAR 82-3-1112(e) & (f)] 

If a CO2 storage well fails to demonstrate mechanical

integrity, the operator of the well shall, upon discovery,

isolate each leak in a manner that contains CO2 and

associated fluids in the storage well or storage reservoir

and demonstrates that the well does not pose a threat to

public health and safety and usable water. The operator

shall either repair and retest the storage well to 

demonstrate mechanical integrity; or plug the storage 

well according to K.A.R. 82-3- 1118, within 90 days. 

[KAR 82-3-1112(g)]
A-9 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

include a description of the test(s) and the method(s) 

used. In making his/her evaluation, the Director must 

review monitoring and other test data submitted since the 

previous evaluation.

Testing and Monitoring Requirements

§146.90 Testing and monitoring requirements. 82-3-1108. Storage facility monitoring and reporting.

Testing and monitoring must, at a minimum, include:

• Analysis of CO2 stream with sufficient frequency to 

yield data representative of its chemical and physical 

characteristics; 

• Installation and use of continuous recording devices to 

monitor injection pressure, rate, and volume; the 

pressure on the annulus between the tubing and the 

long string casing; and the annulus fluid volume added;

• Corrosion monitoring of the well materials for loss of 

mass, thickness, cracking, pitting, and other signs of 

corrosion must be performed on a quarterly basis to 

ensure that the well components meet the minimum 

standards for material strength and performance by 

analyzing coupons, routing the CO2 stream through a 

loop; or using an alternative method approved by the 

Director.

• Periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s) 

through the confining zone(s) or additional zones.

• A demonstration of external mechanical integrity at 

least once per year until the injection well is plugged; 

and, if required by the Director, a casing inspection log; 

• A pressure fall-off test at least once every five years;

• Testing and monitoring to track the extent of the CO2

plume and the presence or absence of elevated 

pressure (e.g., the pressure front) by using:

- Direct methods in the injection zone(s); and,

- Indirect methods, unless the Director determines that 

such methods are not appropriate;

• The Director may require surface air monitoring and/or 

soil gas monitoring. 

• Any additional monitoring, as required by the Director 

• Review the testing and monitoring plan at least once 

every five years. Amended plans or demonstrations 

shall be submitted to the Director within one year of an 

AoR reevaluation, after any significant changes to the 

facility, or when required by the Director.

• A quality assurance and surveillance plan. 

Testing and monitoring requirements are described in 

the storage facility monitoring and reporting section 

[KAR 82-3-1108] and throughout this state regulation.

Requirements that appear to differ from the federal rule 

are noted below.

A monitoring plan to ensure containment of the CO2 

within the CO2 storage facility boundaries which 

includes monitoring wells to monitor for CO2 migration 

vertically and horizontally. 

[KAR 82-3-1101(c)(14)(I)] 

During the first year of operations, the operator shall file 

monthly pressure, injection, and withdrawal reports, 

containing maximum, minimum, and average wellhead 

pressure reading, total amount of CO2 injected and 

withdrawn each week; and cumulative total of CO2 in 

the storage facility. 

[KAR 82-3-1108(a)] 

During the second year of operations and every year 

after, the operator shall file quarterly pressure, injection, 

and withdrawal reports. 

[KAR 82-3-1108(b)] 

The CO2 injectate shall be sampled monthly and tested 

for the percentage of CO2. 

[KAR 82-3-1108(c)] 

The operator shall submit a detailed map showing the 

areal extent of the CO2 plume annually. The operator 

shall include a narrative description of how the areal 

extent of the CO2 plume was determined. 

[KAR 82-3-1108(e)] 

The storage facility shall have a continuously operating 

supervisory control and data acquisition (SCADA) 

system approved by the director to monitor operations

for each individual CO2 storage well. 

[KAR 82-3-1107(f)] 

Leak detectors are required near residences, 

commercial establishments, churches, schools, or small, 

well-defined outside areas.

[KAR 82-3-1107(h)]

A leak detector shall be placed at any CO2 storage well 

located within 330 feet of an inhabited residence, 

commercial establishment, church, school, or small, 

well-defined outside area; each enclosed compressor 

site; and any building housing a CO2 pipe connection.

The required leak detectors shall be integrated with 

automated warning systems. The inspection and testing 
A-10

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

of these leak detectors shall meet the requirements of 

K.A.R. 82-3-1111.

[KAR 82-3-1107(i)] 

Reporting Requirements 

§146.91 Reporting requirements. 82-3-1108. Storage facility monitoring and reporting.

The owner or operator must, at a minimum, provide the 

following reports to the Director, for each permitted Class 

VI well:

Semi-annual reports containing:

• Any changes to the physical, chemical, and other 

relevant characteristics of the CO2 stream from the 

proposed operating data;

• Monthly average, maximum, and minimum values for 

injection pressure, flow rate and volume, and annular 

pressure; 

• A description of any event that exceeds operating 

parameters for annulus pressure or injection pressure 

specified in the permit;

• A description of any event which triggers a shut-off 

device required and the response taken;

• The monthly volume and/or mass of the CO2 stream 

injected over the reporting period and the volume 

injected cumulatively over the life of the project;

• Monthly annulus fluid volume added; and 

• The results of monitoring prescribed. 

Report, within 30 days, the results of:

• Periodic tests of mechanical integrity;

• Any well workover; and,

• Any other test of the injection well conducted by the 

permittee if required by the Director.

Report, within 24 hours of:

• Any evidence that the injected CO2 stream or 

associated pressure front may cause an endangerment 

to a USDW; 

• Any noncompliance with a permit condition, or 

malfunction of the injection system, which may cause 

fluid migration into or between USDWs;

• Any triggering of a shut-off system (i.e., down-hole or 

at the surface); 

• Any failure to maintain mechanical integrity; or.

• Any release of CO2 to the atmosphere or biosphere. 

Owners or operators must notify the Director in writing 30 

days in advance of:

• Any planned well workover; 

• Any planned stimulation activities, other than 

stimulation for formation testing conducted under 

§146.82; and

• Any other planned test of the injection well conducted 

by the permittee. 

Regardless of whether a State has primary enforcement 

responsibility, owners or operators must submit all 

required reports, submittals, and notifications under 

subpart H of this part to EPA in an electronic format 

approved by EPA.

Reporting requirements are described in the storage 

facility monitoring and reporting section [KAR 82-3-1108] 

and throughout this state regulation. Requirements that 

appear to differ from the federal rule are noted below.

During the first year of operations, the operator shall file 

monthly pressure, injection, and withdrawal reports, 

containing maximum, minimum, and average wellhead 

pressure reading, total amount of CO2 injected and 

withdrawn each week; and cumulative total of CO2 in 

the storage facility. Each monthly report shall be due on 

or before the 10th of the month for the previous month 

and shall contain the maximum, minimum, and average 

wellhead pressure reading for the month; total amount of 

CO2 withdrawn and injected each week; and cumulative 

total of CO2 in the storage facility.

[KAR 82-3-1108(a)] 

During the second year of operations and every year 

after, the operator shall file quarterly pressure, injection, 

and withdrawal reports. Each quarterly report shall 

contain the maximum, minimum, and average wellhead 

pressure reading for the month; total amount of CO2 

withdrawn and injected each week; and cumulative total 

of CO2 in the storage facility.

[KAR 82-3-1108(b)] 

The CO2 injectate shall be sampled monthly and tested 

at a Kansas certified laboratory for the percentage of 

CO2. The report shall be filed with the conservation 

division on or before the 28th day of the following month.

[KAR 82-3-1108(c)] 

The original field record consisting of magnetic tapes, 

digital electronic data, meter charts, or records of CO2 

injected or withdrawn shall be retained for at least five 

years. This information shall be made available to the 

conservation division upon request.

[KAR 82-3-1108(d)] 

The operator shall submit a detailed map showing the 

areal extent of the CO2 plume annually. The operator 

shall include a narrative description of how the areal 

extent of the CO2 plume was determined. 

[KAR 82-3-1108(e)] 

Each sensor or indicator of the continuously operating 

supervisory control and data acquisition (SCADA) 

system shall be calibrated annually, and the 

documentation shall be kept for five years.

[KAR 82-3-1107(f)] 

The operator shall submit a written report summarizing

the annual review of the safety plan to the conservation 

division within 30 days following the review. 
A-11

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

Records shall be retained by the owner or operator as 

follows: 

• All data collected under §146.82 for Class VI permit 

applications shall be retained throughout the life of the 

geologic sequestration project and for 10 years 

following site closure.

• Data on the nature and composition of all injected 

fluids collected pursuant to §146.90(a) shall be 

retained until 10 years after site closure. The Director 

may require the owner or operator to deliver the 

records to the Director at the conclusion of the 

retention period. 

• Monitoring data collected pursuant to §146.90(b) 

through (i) shall be retained for 10 years after it is 

collected.

• Well plugging reports, post-injection site care data, 

including data and information used to develop the 

demonstration of the alternative post-injection site care 

timeframe, and the site closure report shall be retained 

for 10 years following site closure.

• The Director has authority to require the owner or 

operator to retain any records required in this subpart 

for longer than 10 years after site closure.

[KAR 82-3-1109(d)] 

The operator shall maintain a record of leak detector

each inspection, including the inspection results, for at 

least five years and shall make each record available to 

the conservation division upon request. 

[KAR 82-3-1111(d)] 

Each operator shall report each leak, each potential 

leak, and any pressure changes or other monitoring data 

that indicate a loss of containment of injected CO2 or 

associated fluids. The report shall be made orally and be 

confirmed in writing within three business days following 

the oral report.

[KAR 82-3-1113(a)]

The operator shall submit a written summary of the

cause(s) within 10 days following the written report in 

above. The summary shall also evaluate whether the 

situation poses a threat to public health and safety,

usable water, or property.

[KAR 82-3-1113(b)]

Within 30 days following the summary report required by 

above, the operator shall submit an action plan to repair 

the leak or regain containment for the conservation 

division’s review and approval. 

[KAR 82-3-1113(c)] 

The installation of observation or monitoring wells may 

be required by the director to gain additional information 

about the leak or loss of containment.

[KAR 82-3-1113(d)]

Additional reports may be required by the Director until 

the leak or loss of containment is remediated.

[KAR 82-3-1113(e)] 

Well Plugging

§146.92 Injection well plugging. 82-3-1114. Temporary abandonment of storage

Wells; 

82-3-1115. Temporary abandonment of a storage

Facility; 

82-3-1116. Application for decommissioning and

abandonment of storage facility;

82-3-1118. Plugging methods and procedures,

plugging report, and plugging fee for CO2 storage 

wells.

Prior to the well plugging, the owner or operator must 

flush each Class VI injection well with a buffer fluid, 

determine bottomhole reservoir pressure, and perform a 

final external mechanical integrity test. 

Well Plugging Plan must include the following 

information:

• Appropriate tests or measures for determining 

bottomhole reservoir pressure;

• Appropriate testing methods to ensure external 

mechanical integrity;

• The type and number of plugs to be used;

• The placement of each plug, including the elevation of 

Well plugging requirements in this state regulation 

appear similar to the federal rule. Exceptions are noted 

below.

Provide a written plugging plan to the appropriate 

conservation division district office and the conservation 

division central office at least 30 days before the

planned commencement of plugging operations.

[KAR 82-3-1118(a)(1)] 

Perform one of the following: set a mechanical bridge 

plug or other control device approved by the director 

immediately above the CO2 storage reservoir or storage 
A-12

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

the top and bottom of each plug;

• The type, grade, and quantity of material to be used in 

plugging. The material must be compatible with the 

CO2 stream; and

• The method of placement of the plugs.

Notice of intent to plug. 

The owner or operator must notify the Director in writing 

at least 60 days before plugging of a well. At this time, if 

any changes have been made to the original well 

plugging plan, the owner or operator must also provide 

the revised well plugging plan. The Director may allow for 

a shorter notice period. Any amendments to the injection 

well plugging plan must be approved by the Director, 

must be incorporated into the permit, and are subject to 

the permit modification requirements. 

Plugging report. 

Within 60 days after plugging, the owner or operator must 

submit a plugging report to the Director. The report must 

be certified as accurate by the owner or operator and by 

the person who performed the plugging operation (if 

other than the owner or operator.) The owner or operator 

shall retain the well plugging report for 10 years following 

site closure. 

reservoirs; or place a cement plug across and above the 

CO2 storage reservoir or storage reservoirs by a method 

approved by the appropriate conservation division 

district office. 

[KAR 82-3-1118(a)(3)]

Within 90 days after a CO2 storage well ceases 

operation, the operation shall (1) plug the well or (2) file 

an application with the conservation division requesting 

temporary abandonment. 

[KAR 82-3-1114(a)] 

Applications for one-year extensions of temporary 

abandonment may be granted by the director for a 

maximum of 10 years. 

[KAR 82-3-1114(c)]

Any operator of a CO2 storage facility may temporarily 

abandon the storage facility upon submitting written 

notice to the conservation division. The notice shall be 

submitted to the conservation division at least 90 days 

before the temporary abandonment. 

[KAR 82-3-1115(a)]

Applications for one-year extensions of temporary 

abandonment may be granted by the director for a 

maximum of 10 years. 

[KAR 82-3-1115(c)] 

Post-injection Site Care

§146.93 Post-injection site care and site closure. 82-3-1117. Postclosure determination

Part of the permit application, includes the following: 

• Pressure differential between pre-injection and 

predicted post-injection pressures in injection zone(s);

• Predicted position of the CO2 plume and associated 

pressure front at site closure; 

• Description of post-injection monitoring location, 

methods, and proposed frequency; and

• A proposed schedule for submitting post-injection site 

care monitoring results to the Director. 

• The duration of the post-injection site care timeframe 

and, if approved by the Director, the demonstration of 

the alternative post-injection site care timeframe. 

Upon cessation of injection, submit an amended plan or 

demonstrate to the Director no amendment is needed.

May modify and resubmit within 30 days of such change. 

At the Director's discretion, demonstrate during the 

permitting process that an alternative post-injection site 

care timeframe is appropriate and ensures nonendangerment of USDWs. The demonstration must be 

based on site-specific information, including the results of 

site-specific computational modeling; the predicted 

timeframe for pressure decline; the predicted rate of CO2 

plume migration; site-specific chemical processes that 

will result in CO2 trapping; the predicted rate of CO2 

trapping; characterization of the confining zone(s); 

laboratory analyses or studies to verify the information on 

trapping; the presence of potential conduits for fluid 

movement and the quality of abandoned well plugs within 

Post-injection site care requirements in this state 

regulation appear similar to the federal rule. Exceptions 

are noted below.

The CO2 storage facility operator shall demonstrate that 

both of the following conditions are met before

postclosure status may be granted: 

• The CO2 plume has stabilized, is contained within the 

storage reservoir, and is not a threat to public health 

and safety and usable water. 

• The CO2 storage reservoir pressure is stable. 

[KAR 82-3-1117(b)]

If the application is denied, the closure period activities

shall continue as directed by the director. 

[KAR 82-3-1117(c)]

In this state regulation, a time frame for post-injection 

site care is not specified and therefore an alternative 

time frame is also not specified. 
A-13

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

the AoR; the distance between the injection zone and the 

USDWs above and/or below the injection zone; and any 

additional site-specific factors determined by the Director. 

The demonstration must meet the criteria at 

§146.93(c)(2) for ensuring the quality and accuracy of the 

data and models on which the demonstration is based.

Monitor the site following the cessation of injection to 

show the position of the CO2 plume and pressure front 

and demonstrate that USDWs are not being endangered. 

• Continue to conduct monitoring as specified in the 

Director-approved plan for at least 50 years following 

the cessation of injection or for the duration of the 

approved alternative timeframe, unless he/she makes 

a demonstration. At the Director’s discretion, the 

monitoring must continue until the project no longer 

poses an endangerment to USDWs. 

Notify the Director in writing at least 120 days before site 

closure. If any changes have been made to the original

plan, the owner or operator must also provide the revised 

plan. The Director may allow for a shorter notice period.

After the Director has authorized site closure, plug all 

monitoring wells in a way which will not allow movement 

of injection or formation fluids that endangers a USDW.

Submit a site closure report to the Director within 90 days 

of site closure, which must be retained at a location 

chosen by the Director for 10 years. Report includes: 

• Documentation of appropriate injection and monitoring 

well plugging. Provide a copy of a survey plat; 

• Documentation of appropriate notification and 

information to such State, local and Tribal authorities 

that have authority over drilling activities; and

• Records reflecting the nature, composition, and volume 

of the CO2 stream.

Record a notation on the deed to the facility property that 

will in perpetuity provide any potential purchaser:

• The fact that land has been used to sequester CO2; 

• The name of the agency or authority with which the 

survey plat was filed and the address of the EPA 

Regional Office to which it was submitted; and

• Volume of fluid injected, the injection zone (s) it was 

injected, and the period over which injection occurred. 

Retain for 10 years following site closure, records 

collected during post-injection site care period. Deliver 

the records to the Director at the end of the retention 

period. Retain records at location chosen by the Director. 
A-14

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

Emergency and Remedial Response

§146.94 Emergency and remedial response. 82-3-1109. Annual review of safety plan; safety plan 

update; 

82-3-1110. Safety inspection.

As part of the permit application, the owner or operator 

must provide the Director with an emergency and 

remedial response plan that describes actions the owner 

or operator must take to address movement of the 

injection or formation fluids that may cause an 

endangerment to a USDW during construction, operation, 

and post-injection site care periods. 

If evidence shows potential endangerment of USDWs, 

the owner or operator should cease injection; notify the 

Director within 24 hours; implement the emergency and 

remedial response plan. Prior to re-commencing 

injection, demonstrate to the Director non-endangerment 

to USDWs. 

 

Periodically review the emergency and remedial 

response plan at least once every five years. Amended 

plans or demonstrations shall be submitted to the 

Director within one year of an AoR reevaluation; following 

any significant changes to the facility; or when required 

by the Director.

Emergency and remedial response requirements in this 

state regulation appear similar to federal rule. 

Exceptions are noted below.

Each operator of a CO2 storage facility shall conduct an 

annual review of the safety plan with its field staff and an 

agent of the conservation division.

[KAR 82-3-1109(a)]

Each operator of a CO2 storage facility shall perform an 

annual safety inspection of the storage field to ensure 

that all safety equipment and monitoring equipment are 

in working order.

[KAR 82-3-1110(a)]

Injection Depth Waiver Requirements

§146.95 Class VI injection depth waiver requirements. 

In seeking a waiver of the requirement to inject below the 

lowermost USDW, the owner or operator must submit a 

supplemental report concurrent with permit application.

Details about the possible demonstrations and other 

requirements are noted in the rule text.

The Director must submit, to the Regional Administrator, 

documentation of a list of requirements described in the 

rule text.

The Director shall give public notice that a waiver 

application has been submitted. The notice shall clearly 

state:

• The depth of the proposed injection zone(s); 

• The location of the injection well(s);

• The name and depth of all USDWs within the AoR;

• A map of the AoR; 

• The names of any public water supplies affected, 

reasonably likely to be affected, or served by USDWs 

in the AoR; and,

• The results of UIC-Public Water System Supervision 

consultation. 

Following public notice, the Regional Administrator shall 

provide written concurrence or non-concurrence 

regarding waiver issuance. 

If a waiver is issued, within 30 days of waiver issuance, 

EPA shall post the information detailed in the rule text on

the Office of Water’s Web site.

Upon receipt of a waiver of the requirement to inject 

This state regulation makes no mention of and therefore

has no criteria for an injection depth waiver.
A-15

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Kansas Final Rule

(K.A.R. 82-3-1100 – 82-3-1120; 82-3-311a. Final in 

Kansas Register on February 11, 2010.)

below the lowermost USDW for geologic sequestration, 

the owner or operator must comply with all requirements, 

certain modified requirements, and any additional 

requirements requested by the Director.
B-1 

Appendix B

North Dakota, Article 43-05, Georlogic Storage of Carbon Dioxide

Preliminary Comparison with the Final Class VI Rule

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

Applicability

§146.81 - Applicability 43-05-01-02. Scope of chapter.

• This rule applies to any wells used to inject carbon 

dioxide specifically for the purpose of geologic 

sequestration. 

• Also applies to owners or operators of permit- or ruleauthorized Class I, Class II, or Class V experimental 

carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well 

or wells. 

This chapter governs the geologic storage of carbon 

dioxide (meaning the “the permanent or short-term 

underground storage of carbon dioxide in a storage 

reservoir”). 

§146.81 (d) - Applicability: Definitions 43-05-01-01. Definitions: CO2 storage facilities.

Geologic sequestration "Geologic storage" means the permanent or short-term

underground storage of carbon dioxide in a storage 

reservoir. 

 (GS) means the long-term 

containment of a gaseous, liquid, or supercritical CO2

stream in subsurface geologic formations. This term does 

not apply to CO2 capture or transport.

Geologic sequestration project "Storage facility" means the reservoir, underground 

equipment, and surface facilities and equipment used or 

proposed to be used in a geologic storage operation. It 

does not include pipelines used to transport carbon 

dioxide to the storage facility.

means an injection well or 

wells used to emplace a CO2 stream beneath the 

lowermost formation containing a USDW; or, wells used 

for geologic sequestration of CO2 that have been granted 

a waiver of the injection depth requirements pursuant to 

requirements at §146.95; or, wells used for geologic 

sequestration of CO2 that have received an expansion to 

the areal extent of an existing Class II enhanced oil 

recovery or enhanced gas recovery aquifer exemption 

pursuant to §§146.4 of this chapter and 144.7(d). It 

includes the subsurface three-dimensional extent of the 

CO2 plume, associated area of elevated pressure, and 

displaced fluids, as well as the surface area above that 

delineated region.

Site closure "Postclosure period" means that period after the 

commission has issued a certificate of completion.

means the point/time, as determined by the 

Director following the requirements under §146.93, at 

which the owner or operator of a geologic sequestration 

site is released from post-injection site care 

responsibilities.

Post-injection site care "Closure period" means that period from permanent 

cessation of carbon dioxide injection until the 

commission issues a certificate of project completion.

means appropriate monitoring 

and other actions (including corrective action) needed 

following cessation of injection to ensure that USDWs are 

not endangered, as required under §146.93.

Permit Conditions

§146.82 Required Class VI permit information. 43-05-01-05, Storage Facility Permit; 

43-05-01-09, Well Permit Application Requirements. 

Prior to the issuance of a construction or conversion 

permit, the owner or operator must submit the following:

• Information required in 40 CFR 144.31 (e)(1) - (6); 

• Map showing the injection well, the applicable AoR, 

and faults, if known or suspected;

• Information on the geologic structure and 

hydrogeologic properties; 

• Tabulation of all wells within the AoR which penetrate 

the injection or confining zone(s); 

• Maps and stratigraphic cross sections indicating all 

USDWs, water wells and springs within the AoR, their 

Permit application conditions in this state regulation 

appear similar to the federal rule. However, the state has 

additional rules has addressing subsurface rights and 

public safety. Major differences include the following: 

• Requirements for a pre-operational formation testing 

program or stimulation program were not found in the 

state reguilation.

• Testing programs are not specifically required as part 

of the application, but a [pressure] testing plan must 

be submitted to the commission for prior approval. 

[43-05-01-11(13)] Monitoring and leak detection plans 
B-2 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

positions relative to the injection zone(s), and the 

direction of water movement, where known; 

• Baseline geochemical data on subsurface formations;

• Proposed operating data; 

• Proposed pre-operational formation testing program; 

• Proposed stimulation program; 

• Proposed procedure to conduct injection operation; 

• Schematics of the construction details of the well; 

• Injection well construction procedures; 

• Proposed AoR and corrective action plan; 

• A demonstration of financial responsibility; 

• Proposed testing and monitoring plan; 

• Proposed injection well plugging plan; 

• Proposed post-injection site care and site closure plan; 

• Proposed alternative post-injection site care timeframe;

• Proposed emergency and remedial response plan; 

• A list of contacts identified to be within the AoR; and

• Any other information requested by the Director. 

The Director shall notify, in writing, any States, Tribes, or 

Territories within the AoR of the Class VI project of the 

permit application. 

Prior to granting approval for the operation of a Class VI 

well, the Director shall consider the following: 

• Final AoR based on modeling, using data obtained 

during logging and testing of the well and the 

formation; 

• Any relevant updates to the information on the geologic 

structure and hydrogeologic properties of the proposed 

storage site and overlying formations; 

• Information on the compatibility of the CO2 stream with 

fluids in the injection zone(s) and minerals in both the 

injection and the confining zone(s); 

• Results of the formation testing program;

• Final injection well construction procedures;

• Status of corrective action on wells in the AoR; 

• All available logging and testing program data on the 

well;

• A demonstration of mechanical integrity;

• Any updates to the any of the plans; and

• Any other information requested by the Director.

Owners or operators seeking a waiver of the requirement 

to inject below the lowermost USDW submit a 

supplemental report.

are required with the application.

• It is not clear that the required “closure plan” is 

comparable to the injection well plugging, PISC, 

and/or site closure plan. 

The state regulation contains little detail on the Director’s 

criteria for consideration of a permit application.

There are no waiver provisions.

Notice of application for permit

§ 124.10 Public notice of permit actions and public 

comment period.

43-05-01-08. Amalgamation of subsurface rights to 

operate geological storage unit.

For Class VI injection well UIC permits, mailing or 

emailing a notice to State and local oil and gas regulatory 

agencies and State agencies regulating mineral 

exploration and recovery, the Director of the Public Water 

Supply Supervision program in the State, and all 

agencies that oversee injection wells in the State.

This North Dakota regulation focuses on subsurface 

rights and requires the applicant to notify specific 

operators and landowners rather than the regulatory

agencies only. Notice must be provided to:

• Each operator of mineral extraction activities within 

the facility and within one-half mile [.80 kilometer] 

outside of the facility area;

• Each mineral lessee of record within the facility area 

and within one-half mile [.80 kilometer] of its outside 

boundary;
B-3 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

• Each owner of record of the surface within the facility 

area and one-half mile [.80 kilometer] of its outside 

boundary;

• Each owner of record of minerals within the project 

area and within one-half mile [.80 kilometer] of its 

outside boundary;

• Each owner and each lessee of record of the pore 

space within the storage reservoir and within one-half 

mile [.80 kilometer] of the reservoir’s boundary; and

• Any other persons as required by the commission. 

The Commission will post public notice in a newspaper 

in Bismarck, North Dakota, and in a newspaper of 

general circulation in the county where the land affected 

or some part thereof is situated. 

Geologic Site Characterization

§146.83 Minimum criteria for siting. 43-05-01-05. Storage facility permit.

A geologic system comprises: 

• An injection zone(s) of sufficient areal extent, 

thickness, porosity, and permeability to receive the 

total anticipated volume of the CO2 stream. 

• Confining zone(s) free of transmissive faults or 

fractures and of sufficient areal extent and integrity to 

contain the injected CO2 stream and displaced 

formation fluids and allow injection at proposed 

maximum pressures and volumes without initiating or 

propagating fractures in the confining zone(s). 

• At the Director’s discretion, additional zones that will 

impede vertical fluid movement, are free of faults and 

fractures that may interfere with containment, allow for 

pressure dissipation, and provide additional 

opportunities for monitoring, mitigation, and 

remediation.

Requirements with minimum geological criteria for siting 

are not included in this state regulation. However, the 

applicant must provide with the application “any 

available geophysical data and assessments of any 

regional tectonic activity, local seismicity and regional or 

local fault zones, and a comprehensive description of 

local and regional structural or stratigraphic features. 

The evaluation must describe the storage reservoir’s 

mechanisms of geologic confinement, including rock 

properties, regional pressure gradients, structural 

features, and adsorption characteristics with regard to 

the ability of that confinement to prevent migration of 

carbon dioxide beyond the proposed storage reservoir.” 

[43-05-01-05(1)(b)(2)] 

“The commission shall approve limits that, with a 

reasonable degree of certainty, will avoid initiating a new 

fracture or propagating an existing fracture in the 

confining zone or cause the movement of injection or 

formation fluids into an underground source of drinking 

water.” [43-05-01-05(1)(b)(5)] 

AoR and Corrective Action

§146.84 AoR and corrective action. 43-05-01-05. Storage facility permit.

The AoR is the region surrounding the geologic 

sequestration project where USDWs may be endangered 

by the injection activity. The AoR is delineated using

computational modeling that accounts for the physical 

and chemical properties of all phases of the injected CO2

stream and is based on available site characterization, 

monitoring, and operational data. 

Part of the permit application, submit a plan that includes:

• Method for delineating the AoR; 

• Description of the minimum fixed frequency, not to 

exceed five years, to reevaluate the AoR; monitoring 

and operational conditions that would warrant an 

earlier reevaluation; how monitoring and operational 

data will be used to inform a reevaluation; how 

corrective action will be conducted; how corrective 

action will be adjusted if there are changes in the AoR;

and how site access will be guaranteed for future 

corrective action.

Under this North Dakota regulation, permit applicants 

must submit a “technical evaluation of the proposed 

storage facility,” which includes identification of many of 

the physical elements that are identified in the facility 

area. However, this technical evaluation:

• Does not refer to the delineation of an area of review 

nor require information on the methods for delineating 

the area.

• Does not include requirements for periodic 

reevaluations of the area.

• Does not provide detail on the requirements of the 

model. The rule contains little discussion about 

measuring the extent of the plume over time However 

the State’s regulation requires information on the 

“areal extent of the storage reservoir” and “the extent 

of the pore space that will be occupied by [CO2]”). 

North Dakota requires public safety and emergency 

response plans that detail the safety procedures 
B-4 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

November 22, 2010) (Final, Effective April 1, 2010)

To delineate the AoR and identify all wells that require 

corrective action, perform the following: 

• Predict, using existing site characterization, monitoring 

and operational data, and computational modeling, the 

projected lateral and vertical migration of the CO2

plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient 

to cause the movement of injected fluids or formation 

fluids into a USDW are no longer present, or until the 

end of a fixed time period as determined by the 

Director. The rule further describes the requirements of 

the model; 

• Identify all penetrations, including active and 

abandoned wells and underground mines, in the AoR 

that may penetrate the confining zone(s); and 

• Determine which abandoned wells in the AoR have 

been plugged. 

At the minimum fixed frequency, not to exceed five years, 

or when monitoring and operational conditions warrant: 

• Reevaluate the AoR; 

• Identify all wells in the reevaluated AoR that require 

corrective action; 

• Perform corrective action on wells requiring corrective 

action in the reevaluated AoR; and

• Submit an amended AoR and corrective action plan or 

demonstrate to the Director through monitoring data 

and modeling results that no amendment to the AoR 

and corrective action plan is needed. 

The emergency and remedial response plan and the 

demonstration of financial responsibility must account for 

the AoR delineated, regardless of whether or not 

corrective action in the AoR is phased.

All modeling inputs and data used to support AoR 

reevaluations shall be retained for 10 years.

concerning the facility and residential, commercial, and 

public land use within one mile. These plans must 

address CO2 leakage or loss of containment. Plans 

must be updated annually.

Financial Responsibility

§146.85 Financial responsibility. 43-05-01-05(1)(d) 

The owner or operator must demonstrate and maintain 

financial responsibility as approved by the Director, until 

the Director approves the completed post-injection site 

care and site closure plan and approves site closure. The 

owner or operator may be released from a financial 

instrument in the certain circumstances.

The financial responsibility instrument(s) used must: 

• Be from the list of qualifying instruments; 

• Be sufficient to cover the cost of corrective action, 

injection well plugging, post injection site care and site 

closure, and emergency and remedial response; 

• Be sufficient to address endangerment of USDWs; and 

• Comprise protective conditions of coverage, including

at a minimum cancellation, renewal, and continuation 

provisions, specifications on when the provider 

becomes liable in case of cancellation if there is a 

failure to renew with a new qualifying financial 

instrument, and requirements for the provider to meet a 

Permit applications must include “a performance bond in 

an amount and under terms set by the commission to 

provide it with funds sufficient to satisfy any regulatory 

obligation that the storage operator fails to fulfill. If the 

commission uses a part of the bond, the storage 

operator shall immediately replenish the bond or secure 

a new bond to ensure that the full bond amount set by 

the commission is maintained.” 

No additional detail on financial responsibility is included 

in this regulation including the delineation of specific 

regulatory obligations such as the cost of corrective 

action, injection well plugging, post injection site care 

and site closure, and emergency and remedial 

response.
B-5 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

minimum rating, minimum capitalization, and ability to 

pass the bond rating when applicable. 

Have a detailed written estimate, in current dollars, of the 

cost of performing corrective action on wells in the AoR, 

plugging the injection well(s), post-injection site care and 

site closure, and emergency and remedial response. 

• The cost estimate must be performed for each phase 

separately and must be based on the costs to the 

regulatory agency of hiring a third party. 

• During the active life of the geologic sequestration 

project, the owner or operator must adjust the cost 

estimate for inflation within 60 days prior to the 

anniversary date of the establishment of the financial 

instrument. The Director must approve this change. 

• Whenever the current cost estimate increases/ 

decreases, the face amount of the financial assurance 

instrument may be increased/reduced to the amount of 

the current cost estimate only after the receipt of 

written approval from the Director. 

Notify the Director by certified mail of adverse financial 

conditions that may affect the ability to carry out injection 

well plugging and post-injection site care and site 

closure. 

Provide an adjustment of the cost estimate to the Director 

within 60 days of notification by the Director, if the 

Director determines during the annual evaluation of the 

qualifying financial responsibility instrument(s) that the 

most recent demonstration is no longer adequate to 

cover the cost of corrective action, injection well plugging, 

post-injection site care and site closure, and emergency 

and remedial response. 

The Director must approve the use and length of pay-inperiods for trust funds or escrow accounts. 

Construction Requirements

§146.86 Injection well construction requirements. 43-05-01-11. Well operational standards.

All materials (e.g. casing and cementing materials, tubing 

and packer materials, cement and cement additives) 

used in construction must be compatible with fluids with 

which the materials may be expected to come into 

contact and must meet or exceed standards.

Casing and Cementing of Class VI Wells.

• The owner or operator must provide the quantitative 

information requested in the rule.

• Surface casing must extend through the base of the 

lowermost USDW and be cemented to the surface 

through the use of a single or multiple strings of casing 

and cement. 

• At least one long string casing, using a sufficient 

number of centralizers, must extend to the injection 

zone and must be cemented by circulating cement to 

the surface in one or more stages. 

• Circulation of cement may be accomplished by staging. 

The Director may approve an alternative method.

Tubing and Packer.

Construction requirements in this state regulation appear 

similar to but less specific than the federal rule.

However, note that many of the requirements reference 

43-02-3-21, which was not reviewed.

• Surface casing in all newly drilled carbon dioxide 

injection and subsurface observation wells drilled 

below the underground source of drinking water must 

be set fifty feet below the base of the Fox Hills 

formation and cemented pursuant to section 43-02-03-

21. [43-05-01-11(1)]

• The long string casing in all injection and subsurface 

observation wells must be cemented pursuant to 

section 43-02-03-21. [43-05-01-11(2)]

• Any liner set in the well bore must be cemented with a 

sufficient volume of cement to fill the annular space. 

[43-05-01-11(3)] 

• The packer must be set at a depth at which the packer 
B-6 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

• All owners or operators must inject fluids through 

tubing with a packer set at a depth opposite a 

cemented interval at the location approved by the 

Director. 

• The owner or operator must submit the quantitative 

information requested in the rule.

will be opposite a cemented interval of the long string

casing and must be set no more than fifty feet [15.24 

meters] above the uppermost perforation or open hole 

for the storage reservoirs. 

Logging, Sampling and Testing

§146.87 Logging, sampling, and testing prior to 

injection well operation.

43-05-01-09. Well permit application requirements; 

43-05-01-11. Well operational standards.

During drilling and construction, the owner or operator 

must run appropriate logs, surveys and tests to 

determine or verify the depth, thickness, porosity, 

permeability, and lithology of, and the salinity of any 

formation fluids in all relevant geologic formations and 

then submit a descriptive report prepared by a 

knowledgeable log analyst that includes an interpretation 

of the results of such logs and tests.

At a minimum, such logs and tests must include:

• Deviation checks. 

• Before and upon installation of the surface casing:

- Resistivity, spontaneous potential, and caliper logs 

before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• Before and upon installation of the long string casing:

- Resistivity, spontaneous potential, porosity, caliper, 

gamma ray, fracture finder logs, and any other logs 

the Director requires before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• A series of mechanical integrity tests, which may 

include:

- A pressure test with liquid or gas;

- A tracer survey such as oxygen-activation logging;

- A temperature or noise log;

- A casing inspection log; 

• Any alternative methods that are required by and/or 

approved of by the Director. 

Take whole cores or sidewall cores of the injection zone 

and confining system and formation fluid samples from 

the injection zone(s), and submit to the Director a 

detailed report prepared by a log analyst that includes: 

well log analyses, core analyses, and formation fluid 

sample information. 

Record fluid temperature, pH, conductivity, reservoir 

pressure, and static fluid level of the injection zone(s).

Determine or calculate injection and confining zone(s) 

fracture pressure; physical and chemical characteristics 

of the injection and confining zone(s) and formation fluids 

in the injection zone(s).

Conduct pressure fall-off test and a pump test or

injectivity tests upon completion, but prior to operation, to 

verify hydrogeologic characteristics of the injection 

Logging, sampling, and testing requirements in this state 

regulation appear similar to federal rule. Exceptions are 

noted below.

No later than the conclusion of well drilling and 

completion activities, a permit application shall be 

submitted to operate an injection well and must include 

at a minimum: 

• The well’s complete dual induction or equivalent log 

through the storage reservoir. Such a log shall be run 

prior to setting casing through the storage reservoir. 

Logs must be annotated to identify the estimated 

location of the base of the deepest underground 

source of drinking water, showing the stratigraphic 

position and thickness of all confining strata above the 

storage reservoir and the reservoir’s stratigraphic 

position and thickness unless that information has 

been previously submitted. When approved in 

advance by the commission, this information can be 

demonstrated with a dual induction or equivalent log 

run in a nearby well or by such other method

acceptable to the commission; 

• An affidavit specifying the chemical constituents of the 

injection stream other than carbon dioxide and their 

relative proportions; 

• Proof that the long string of casing of the well is 

cemented adequately so that the carbon dioxide is 

confined to the storage reservoirs. Such proof must be 

provided in the form of a cement bond log or the 

results of a fluid movement study or such other 

method specified by the commission; and 

• The results of a mechanical-integrity test, if applicable 

to well type, of the casing in accordance with the 

pressure test requirements of this section if a test was 

run within one calendar year preceding the request for 

a conversion permit for a previously drilled well.

[43-05-01-09(3)(c) through (3)(f)]

All newly drilled wells must establish internal and 

external mechanical integrity as specified by the 

commission. All other wells to be used as injection wells 

must demonstrate mechanical integrity as specified by 

the commission prior to use for injection: 

• Pressure tests. At a minimum, the pressure must be 

applied to the tubing casing annulus at the surface for 

a period of thirty minutes and must have no decrease 

in pressure greater than ten percent of the required 

minimum test pressure. The packer must be set at a 

depth at which the packer will be opposite a cemented 

interval of the long string casing and must be set no 

more than fifty feet above the uppermost perforation 
B-7 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

zone(s).

Provide the Director with the opportunity to witness all 

logging and testing. Submit a schedule of such activities 

to the Director 30 days prior to conducting the first test. 

or open hole for the storage reservoirs; and 

• The commission may require additional testing, such 

as a bottom hole temperature and pressure 

measurements, tracer survey, temperature survey, 

gamma ray log, neutron log, noise log, casing 

inspection log, or a combination of two or more of 

these surveys and logs, to demonstrate mechanical 

integrity. 

[43-05-01-11(13)] 

Operating Requirements

§146.88 Injection well operating requirements.

Ensure that injection pressure does not exceed 90 

percent of the fracture pressure of the injection zone(s) 

so as to ensure that the injection does not initiate new 

fractures or propagate existing fractures in the injection 

zone(s). All stimulation must be approved by the Director 

as part of the permit application and incorporated into the 

permit. 

Injection between the outermost casing protecting 

USDWs and the well bore is prohibited.

Fill the annulus between the tubing and the long string 

casing with a non-corrosive fluid approved by the 

Director. Maintain on the annulus a pressure that 

exceeds the operating injection pressure, unless the 

Director determines otherwise. 

Maintain mechanical integrity of the injection well at all 

times, other than during periods of well workover 

approved by the Director.

Install and use: 

• Continuous recording devices to monitor: the injection 

pressure; the rate, volume and/or mass, and 

temperature of the CO2 stream; and the pressure on 

the annulus between the tubing and the long string 

casing and annulus fluid volume; and

• Alarms and automatic surface shut-off systems or, at 

the discretion of the Director, down-hole shut-off 

systems (e.g., automatic shut-off check valves) for 

onshore wells or, other mechanical devices that 

provide equivalent protection; and

• Alarms and automatic down-hole shut-off systems for 

wells located offshore but within State territorial waters, 

designed to alert the operator and shut-in the well 

when operating parameters diverge beyond permitted 

ranges. 

If a shutdown is triggered or a loss of mechanical integrity 

is discovered, immediately investigate and identify as 

expeditiously as possible the cause of the shutoff. If, 

upon such investigation, the well appears to be lacking 

mechanical integrity: 

• Immediately cease injection;

• Take all steps reasonably necessary to determine 

whether there may have been a release of the injected 

CO2 stream or formation fluids into any unauthorized 

zone;

• Notify the Director within 24 hours;

The operating requirements in North Dakota’s 

regulations are similar but less specific than the federal 

regulations. 

• This North Dakota regulation does not provide a 

specific baseline injection pressure. However, the 

regulation indicates that the “maximum allowed 

injection pressure . . . shall be approved by the 

commission and specified in the permit. In approving a 

maximum injection pressure limit, the commission 

shall consider the results of well tests and other 

studies that assess the risks of tensile failure and 

shear failure.” [43-05-01-05(1)(b)(5)] 

• No specific prohibition from injecting between the 

outermost casing protecting USDWs and the well bore 

was found in this North Dakota regulation.

• No specific requirement to fill the annulus between the 

tubing and the long string casing with a non-corrosive 

fluid was found. However, the state regulation 

indicates that all wellhead components, packers, and 

similar equipment must be of quality that can 

withstand the corrosive nature of carbon dioxide. [43-

05-01-11(10) & (11)] 

• North Dakota’s requirements for continuous recording 

devices are discussed under §146.90 (“Testing and 

Monitoring Requirements”). 

• Automated leak detection devices and alarms are 

required. [43-05-01-14(1)] 

• All injection wells must be equipped with shutoff 

systems designed to alert the operator and shut in 

wells when necessary. [43-05-01-11(16)] 

• Immediate notification is requried. [43-05-01-14(1)]
B-8 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

• Restore and demonstrate mechanical integrity to the 

satisfaction of the Director prior to resuming injection; 

• Notify Director when injection is expected to resume.

Mechanical Integrity

§146.89 Mechanical integrity. 43-05-01-11. Well operational standards

A Class VI well has mechanical integrity if there is no 

significant leak in the casing, tubing, or packer; and there 

is no significant fluid movement into a USDW through 

channels adjacent to the injection well bore.

To evaluate the absence of significant leaks, following an

initial annulus pressure test, continuously monitor 

injection pressure, rate, injected volumes; pressure on 

the annulus between tubing and long-string casing; and 

annulus fluid volume. 

 

At least once per year, use an approved tracer survey or

temperature or noise log to determine the absence of 

significant fluid movement. 

 

If required by the Director, the owner or operator must 

run a casing inspection log to determine the presence or 

absence of corrosion in the long-string casing. 

The Director may require additional or alternative tests to 

evaluate mechanical integrity. 

To obtain approval for a new mechanical integrity test, 

the Director must submit a written request to the 

Administrator and the Administrator may approve the 

request. Any alternate method approved by the 

Administrator will be published in the Federal Register

and may be used in all States. 

The owner or operator and the Director must apply 

methods and standards generally accepted in the 

industry. When the owner or operator reports the results 

of mechanical integrity tests to the Director, he/she shall 

include a description of the test(s) and the method(s) 

used. In making his/her evaluation, the Director must 

review monitoring and other test data submitted since the 

previous evaluation.

The mechanical integrity requirements in North Dakota’s 

regulations are similar but less specific than the federal 

regulations (i.e., frequency for internal or external MITs 

is not specified). 

All newly drilled wells must establish internal and 

external mechanical integrity as specified by the 

commission and demonstrate continued mechanical 

integrity through periodic testing as determined by the 

commission. All other wells to be used as injection wells 

must demonstrate mechanical integrity as specified by 

the commission prior to use for injection and be tested 

on an ongoing basis as determined by the commission 

using these methods:

• Pressure tests. Injection wells, equipped with tubing 

and packer as required, must be pressure-tested as 

required by the commission. A testing plan must be 

submitted to the commission for prior approval. At a 

minimum, the pressure must be applied to the tubing 

casing annulus at the surface for a period of thirty 

minutes and must have no decrease in pressure 

greater than ten percent of the required minimum test 

pressure. The packer must be set at a depth at which 

the packer will be opposite a cemented interval of the 

long string casing and must be set no more than fifty 

feet [15.24 meters] above the uppermost perforation 

or open hole for the storage reservoirs; and

• The commission may require additional testing, such 

as a bottom hole temperature and pressure 

measurements, tracer survey, temperature survey, 

gamma ray log, neutron log, noise log, casing 

inspection log, or a combination of two or more of 

these surveys and logs, to demonstrate mechanical 

integrity.

Testing and Monitoring Requirements

§146.90 Testing and monitoring requirements. 

Testing and monitoring must, at a minimum, include:

• Analysis of CO2 stream with sufficient frequency to 

yield data representative of its chemical and physical 

characteristics; 

• Installation and use of continuous recording devices to 

monitor injection pressure, rate, and volume; the 

pressure on the annulus between the tubing and the 

long string casing; and the annulus fluid volume added;

• Corrosion monitoring of the well materials for loss of 

mass, thickness, cracking, pitting, and other signs of 

corrosion must be performed on a quarterly basis to 

ensure that the well components meet the minimum

standards for material strength and performance by 

analyzing coupons, routing the CO2 stream through a 

loop; or using an alternative method approved by the 

The testing and monitoring requirements in North 

Dakota’s regulations are similar but less specific than 

the federal regulations. 

This state regulation requires a “A leak detection and 

monitoring plan utilizing subsurface observation wells to 

monitor any movement of the carbon dioxide outside of 

the storage reservoir. This may include the collection of 

baseline information of carbon dioxide background 

concentrations in ground water, surface soils, and 

chemical composition of in situ waters within the facility 

area and the storage reservoir and within one mile [1.61 

kilometers] of the facility area’s outside boundary. 

Provisions in the plan will be dictated by the site 

characteristics as documented by materials submitted in 
B-9 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

Director.

• Periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s) 

through the confining zone(s) or additional zones.

• A demonstration of external mechanical integrity at 

least once per year until the injection well is plugged; 

and, if required by the Director, a casing inspection log; 

• A pressure fall-off test at least once every five years;

• Testing and monitoring to track the extent of the CO2

plume and the presence or absence of elevated 

pressure (e.g., the pressure front) by using:

- Direct methods in the injection zone(s); and,

- Indirect methods, unless the Director determines that 

such methods are not appropriate;

• The Director may require surface air monitoring and/or 

soil gas monitoring. 

• Any additional monitoring, as required by the Director 

• Review the testing and monitoring plan at least once 

every five years. Amended plans or demonstrations 

shall be submitted to the Director within one year of an 

AoR reevaluation, after any significant changes to the 

facility, or when required by the Director.

• A quality assurance and surveillance plan. 

support of the permit application.” [43-05-01-05(1)(d) 

and (e)]

Reporting Requirements 

§146.91 Reporting requirements. 43-05-01-18. Quarterly and annual reporting 

requirements; 

43-05-01-14. Leak detection and reporting; 

43-05-01-03. Books and records to be kept to 

substantiate reports. 

The owner or operator must, at a minimum, provide the 

following reports to the Director, for each permitted Class 

VI well:

Semi-annual reports containing:

• Any changes to the physical, chemical, and other 

relevant characteristics of the CO2 stream from the

proposed operating data;

• Monthly average, maximum, and minimum values for 

injection pressure, flow rate and volume, and annular 

pressure; 

• A description of any event that exceeds operating 

parameters for annulus pressure or injection pressure 

specified in the permit;

• A description of any event which triggers a shut-off 

device required and the response taken;

• The monthly volume and/or mass of the CO2 stream 

injected over the reporting period and the volume 

injected cumulatively over the life of the project;

• Monthly annulus fluid volume added; and 

• The results of monitoring prescribed. 

Report, within 30 days, the results of:

• Periodic tests of mechanical integrity;

• Any well workover; and,

• Any other test of the injection well conducted by the 

permittee if required by the Director.

Report, within 24 hours of:

North Dakota requires quarterly reporting. The reporting 

requirements in North Dakota’s regulations are similar 

but less specific than the federal regulations. 

• The storage operator shall file with the commission 

quarterly, or more frequently if the commission 

requires, a report on the volume of carbon dioxide 

injected into or withdrawn since the last report, the 

average injection rate, average composition of the 

carbon dioxide stream, wellhead and downhole 

temperature and pressure data, or other pertinent 

operational parameters as required by the 

commission. [43-05-01-18] 

• The storage operator must immediately report to the 

commission any leak detected at any well or surface 

facility. 

• The storage operator must immediately report to the 

commission any pressure changes or other monitoring 

data from subsurface observation wells that indicate 

the presence of leaks in the storage reservoir.

• The storage operator must immediately report to the 

commission any other indication that the storage 

facility is not containing carbon dioxide, whether the 

lack of containment concerns the storage reservoir, 

surface equipment, or any other aspect of the storage 

facility.

[43-05-01-14]

Records must be retained for six years. [43-05-01-03]
B-10

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

• Any evidence that the injected CO2 stream or 

associated pressure front may cause an endangerment 

to a USDW; 

• Any noncompliance with a permit condition, or 

malfunction of the injection system, which may cause 

fluid migration into or between USDWs;

• Any triggering of a shut-off system (i.e., down-hole or 

at the surface); 

• Any failure to maintain mechanical integrity; or.

• Any release of CO2 to the atmosphere or biosphere. 

Owners or operators must notify the Director in writing 30 

days in advance of:

• Any planned well workover; 

• Any planned stimulation activities, other than 

stimulation for formation testing conducted under 

§146.82; and

• Any other planned test of the injection well conducted 

by the permittee. 

Regardless of whether a State has primary enforcement 

responsibility, owners or operators must submit all 

required reports, submittals, and notifications under 

subpart H of this part to EPA in an electronic format 

approved by EPA.

Records shall be retained by the owner or operator as 

follows: 

• All data collected under §146.82 for Class VI permit 

applications shall be retained throughout the life of the 

geologic sequestration project and for 10 years 

following site closure.

• Data on the nature and composition of all injected 

fluids collected pursuant to §146.90(a) shall be 

retained until 10 years after site closure. The Director 

may require the owner or operator to deliver the 

records to the Director at the conclusion of the 

retention period. 

• Monitoring data collected pursuant to §146.90(b) 

through (i) shall be retained for 10 years.

• Well plugging reports, post-injection site care data, 

including data and information used to develop the 

demonstration of the alternative post-injection site care 

timeframe, and the site closure report shall be retained 

for 10 years following site closure.

• The Director has authority to require the owner or 

operator to retain any records required in this subpart 

for longer than 10 years after site closure.

Well Plugging

§146.92 Injection well plugging. 43-05-01-19. Facility closure. 

Prior to the well plugging, the owner or operator must 

flush each Class VI injection well with a buffer fluid, 

determine bottomhole reservoir pressure, and perform a 

final external mechanical integrity test. 

Well Plugging Plan must include the following 

information:

• Appropriate tests or measures for determining 

bottomhole reservoir pressure;

• Appropriate testing methods to ensure external 

Plugging requirements in this state regulation appear 

similar to but less specific than the federal rule.

However, note that many of the requirements reference 

43-02-3-21, which was not reviewed.

• The storage operator shall submit a monitoring plan 

for the closure period for approval by the commission, 

including a proposal specifying which wells will be 

plugged and which will remain unplugged to be used 

as subsurface observation wells.

• The well casing must be cut off at a depth of five feet 
B-11

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

mechanical integrity;

• The type and number of plugs to be used;

• The placement of each plug, including the elevation of 

the top and bottom of each plug;

• The type, grade, and quantity of material to be used in 

plugging. The material must be compatible with the 

CO2 stream; and

• The method of placement of the plugs.

Notice of intent to plug. 

The owner or operator must notify the Director in writing 

at least 60 days before plugging of a well. At this time, if 

any changes have been made to the original well 

plugging plan, the owner or operator must also provide 

the revised well plugging plan. The Director may allow for 

a shorter notice period. Any amendments to the injection 

well plugging plan must be approved by the Director, 

must be incorporated into the permit, and are subject to 

the permit modification requirements. 

Plugging report. 

Within 60 days after plugging, the owner or operator must 

submit a plugging report to the Director. The report must 

be certified as accurate by the owner or operator and by 

the person who performed the plugging operation (if 

other than the owner or operator.) The owner or operator 

shall retain the well plugging report for 10 years following 

site closure. 

[1.52 meters] below the surface and a steel plate 

welded on top identifying the well name and that it 

was used for carbon dioxide injection.

• Wells other than those deemed as subsurface 

observation wells per subsection 2 shall be plugged 

by the storage operator in accordance with section 43-

02-03-34.

Post-injection Site Care

§146.93 Post-injection site care and site closure. 43-05-01-19. Facility closure. 

Part of the permit application, includes the following:

• Pressure differential between pre-injection and 

predicted post-injection pressures in injection zone(s);

• Predicted po sition o f t he CO2 plume and a ssociated 

pressure front at site closure; 

• Description of post-injection monitoring location, 

methods, and proposed frequency; and

• A proposed schedule for submitting post-injection site 

care monitoring results to the Director. 

• The duration of the post-injection site care timeframe 

and, if approved by the Director, the demonstration of 

the alternative post-injection site care timeframe. 

Upon cessation of injection, submit an a mended plan or 

demonstrate to the Director no amendment is needed.

May modify and resubmit within 30 days of such change. 

At the Director's discretion, demonstrate during the

permitting process that an alternative post-injection site 

care timeframe is appropriate and ensures nonendangerment of USDWs. The demonstration must be 

based on site-specific information, including the results of 

site-specific computational modeling; the predicted 

timeframe for pressure decline; the predicted rate of CO2 

plume migration; site-specific chemical processes that 

will result in CO2 trapping; the predicted rate of CO2 

trapping; characterization of the confining zone(s); 

laboratory analyses or studies to verify the information on 

trapping; the presence of potential conduits for fluid 

movement and the quality of abandoned well plugs within 

PISC and site closure requirements in this state 

regulation appear similar to but less specific than the

federal rule. 

• Prior to the conclusion of the operational period, and 

at a time set by the commission, the storage operator 

must provide an assessment of the operations 

conducted during the operational period, including the 

volumes injected, volumes extracted, all chemical 

analyses conducted, and a summary of all monitoring 

efforts. The report must also document the stored 

carbon dioxide’s location and characteristics and 

predict how it might move during the closure period.

• The storage operator shall submit a monitoring plan 

for the closure period for approval by the commission, 

including a proposal specifying which wells will be 

plugged and which will remain unplugged to be used 

as subsurface observation wells.

• Following well plugging and removal of all surface 

equipment, the surface must be reclaimed to the 

commission’s specifications that will, in general, return 

the land as closely as practicable to original condition.

• The commission shall develop in conjunction with the 

storage operator a continuing monitoring plan for the 

postclosure period, including a review and final 

approval of wells to be plugged.

• Upon project closure, all wells designated by the 

commission must be properly plugged and 

abandoned; all storage facility equipment, 

appurtenances, and structures removed; and the 

project area reclaimed to the commission’s 
B-12

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

the AoR; the distance between the injection zone and the 

USDWs above and/or below the injection zone; and any 

additional site-specific factors determined by the Director. 

The demonstration must meet the criteria at 

§146.93(c)(2) for ensuring the quality and accuracy of the 

data and models on which the demonstration is based.

Monitor the site following the cessation of injection to 

show the position of the CO2 plume and pressure front 

and demonstrate that USDWs are not being endangered. 

• Continue to conduct monitoring as specified in the 

Director-approved plan for at least 50 years following 

the cessation of injection or for the duration of the 

approved alternative timeframe, unless he/she makes 

a demonstration. At the Director’s discretion, the 

monitoring must continue until the project no longer 

poses an endangerment to USDWs. 

Notify the Director in writing at least 120 days before site 

closure. If any changes have been made to the original

plan, the owner or operator must also provide the revised 

plan. The Director may allow for a shorter notice period.

After the Director has authorized site closure, plug all 

monitoring wells in a way which will not allow movement 

of injection or formation fluids that endangers a USDW.

Submit a site closure report to the Director within 90 days 

of site closure, which must be retained at a location 

chosen by the Director for 10 years. Report includes: 

• Documentation of appropriate injection and monitoring 

well plugging. Provide a copy of a survey plat; 

• Documentation of appropriate notification and 

information to such State, local and Tribal authorities 

that have authority over drilling activities; and

• Records reflecting the nature, composition, and volume 

of the CO2 stream.

Record a notation on the deed to the facility property that 

will in perpetuity provide any potential purchaser:

• The fact that land has been used to sequester CO2; 

• The name of the agency or authority with which the 

survey plat was filed and the address of the EPA 

Regional Office to which it was submitted; and

• Volume of fluid injected, the injection zone (s) it was 

injected, and the period over which injection occurred. 

Retain for 10 years following site closure, records 

collected during post-injection site care period. Deliver 

the records to the Director at the end of the retention 

period. Retain records at location chosen by the Director. 

specifications that will, in general, return the land as 

closely as practicable to original condition. 

• All subsurface observation and ground water 

monitoring wells as approved in the closure plan must 

remain in place for continued monitoring during the 

closure period.

• Before the closure period ends and at a time set by 

the commission, the storage operator shall provide a 

final assessment of the stored carbon dioxide’s 

location, characteristics, and its future movement and 

location within the storage reservoir.

• The rule has no timeframe for PISC (nor an alternate 

timeframe).

 

Emergency and Remedial Response

§146.94 Emergency and remedial response. 43-05-01-05. Storage facility permit; 

43-05-01-14. Leak detection and reporting. 

As part of the permit application, the owner or operator 

must provide the Director with an emergency and 

remedial response plan that describes actions the owner 

or operator must take to address movement of the 

injection or formation fluids that may cause an 

endangerment to a USDW during construction, operation, 

Emergency and remedial response requirements in this 

state regulation appear similar to federal rule. 

This North Dakota regulation requires a detailed 

description of the storage facility’s public safety and 

emergency response plan. The plan must detail the 
B-13

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

North Dakota, Chapter 43-05: Geologic Storage of 

Carbon Dioxide

(Final, Effective April 1, 2010)

and post-injection site care periods. 

If evidence shows potential endangerment of USDWs, 

the owner or operator should cease injection; notify the 

Director within 24 hours; implement the emergency and 

remedial response plan. Prior to re-commencing 

injection, demonstrate to the Director non-endangerment 

to USDWs. 

 

Periodically review the emergency and remedial 

response plan at least once every five years. Amended 

plans or demonstrations shall be submitted to the 

Director within one year of an AoR reevaluation; following 

any significant changes to the facility; or when required 

by the Director.

safety procedures concerning the facility and residential, 

commercial, and public land use within one mile [1.61 

kilometers], or any other distance set by the 

commission, of the outside boundary of the area. The 

public safety and emergency response procedures must 

include contingency plans for carbon dioxide leakage 

from any well, flow lines, or other facility and identify 

specific contractors and equipment vendors capable of 

providing necessary services and equipment to respond 

to such leaks or loss of containment from the storage 

reservoir. These emergency response procedures must 

be reviewed and updated annually [4 3-05-01-05(1)(d)]. 

The storage operator must immediately report to the 

commission any leak detected at any well or surface 

facility.

The storage operator must immediately report to the 

commission any pressure changes or other monitoring 

data from subsurface observation wells that indicate the 

presence of leaks in the storage reservoir.

The storage operator must immediately report to the 

commission any other indication that the storage facility 

is not containing carbon dioxide, whether the lack of 

containment concerns the storage reservoir, surface 

equipment, or any other aspect of the storage facility.
C-1 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

Applicability

§146.81 – Applicability. §5.201. Applicability and Compliance.

• This rule applies to any wells used to inject carbon 

dioxide specifically for the purpose of geologic 

sequestration. 

• Also applies to owners or operators of permit- or ruleauthorized Class I, Class II, or Class V experimental 

carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well 

or wells. 

• This subchapter applies to the geologic storage of 

anthropogenic CO2 in, and the injection of 

anthropogenic CO2 into, a reservoir that is initially or 

may be productive of oil, gas, or geothermal resources 

or a saline formation directly above or below that 

reservoir. 

• This subchapter applies to a well that is authorized as 

or converted to an anthropogenic CO2 injection well 

for geologic storage.

§146.81 (d) – Applicability: Definitions. §5.102 Definitions. 

Geologic sequestration Geologic storage: The long-term containment of 

anthropogenic carbon dioxide in a reservoir.

(GS) means the long-term 

containment of a gaseous, liquid, or supercritical carbon 

dioxide stream in subsurface geologic formations. This 

term does not apply to carbon dioxide capture or 

transport.

Geologic sequestration project Geologic storage facility or storage facility: The 

underground reservoir, underground equipment, 

injection wells, and surface buildings and equipment 

used or to be used for the geologic storage of 

anthropogenic carbon dioxide and all surface and 

subsurface rights and appurtenances necessary to the 

operation of a facility for the geologic storage of 

anthropogenic carbon dioxide. The term includes any 

reasonable and necessary areal buffer, subsurface 

monitoring zones, and pressure fronts. The term does 

not include a pipeline used to transport carbon dioxide 

from the facility at which the carbon dioxide is captured 

to the geologic storage facility. The storage of carbon 

dioxide incidental to or as part of enhanced recovery 

operations does not in itself automatically render a 

facility a geologic storage facility.

means an injection well or 

wells used to emplace a carbon dioxide stream beneath 

the lowermost formation containing a USDW; or, wells 

used for geologic sequestration of carbon dioxide that 

have been granted a waiver of the injection depth 

requirements pursuant to requirements at §146.95; or, 

wells used for geologic sequestration of carbon dioxide 

that have received an expansion to the areal extent of an 

existing Class II enhanced oil recovery or enhanced gas 

recovery aquifer exemption pursuant to §§146.4 of this 

chapter and 144.7(d). It includes the subsurface threedimensional extent of the carbon dioxide plume, 

associated area of elevated pressure, and displaced 

fluids, as well as the surface area above that delineated 

region.

Site closure Facility closure: The point at which the operator of a 

geologic storage facility is released from post-injection 

storage facility care responsibilities.

means the point/time, as determined by the 

Director following the requirements under §146.93, at 

which the owner or operator of a geologic sequestration 

site is released from post-injection site care 

responsibilities.

Post-injection site care Post-injection facility care: Monitoring and other actions 

(including corrective action) needed following cessation 

of injection to assure that underground sources of 

drinking water are not endangered and that the 

anthropogenic carbon dioxide remains confined to the 

permitted injection interval.

means appropriate monitoring 

and other actions (including corrective action) needed 

following cessation of injection to ensure that USDWs are 

not endangered, as required under §146.93.

Appendix C 

Texas: Subchapter B. Geologic Storage and Associated Injection of 

Anthropogenic Carbon Dioxide - 16 TAC §§5.201 - 5.208

Preliminary Comparison with the Final Class VI Rule
C-2 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

Permit Conditions

§146.82 Required Class VI permit information. §5.202 Permit Required; 

§5.203 Application Requirements. 

Prior to the issuance of a construction or conversion 

permit, the owner or operator must submit the following:

• Information required in 40 CFR 144.31 (e)(1) - (6); 

• Map showing the injection well, the applicable AoR, 

and faults, if known or suspected;

• Information on the geologic structure and 

hydrogeologic properties;

• Tabulation of all wells within the AoR which penetrate 

the injection or confining zone(s);

• Maps and stratigraphic cross sections indicating all 

USDWs, water wells and springs within the AoR, their 

positions relative to the injection zone(s), and the 

direction of water movement, where known;

• Baseline geochemical data on subsurface formations;

• Proposed operating data;

• Proposed pre-operational formation testing program;

• Proposed stimulation program;

• Proposed procedure to conduct injection operation;

• Schematics of the construction details of the well;

• Injection well construction procedures;

• Proposed AoR and corrective action plan;

• A demonstration of financial responsibility;

• Proposed testing and monitoring plan;

• Proposed injection well plugging plan;

• Proposed post-injection site care and site closure plan;

• Proposed alternative post-injection site care timeframe;

• Proposed emergency and remedial response plan; 

• A list of contacts identified to be within the AoR; and

• Any other information requested by the Director. 

The Director shall notify, in writing, any States, Tribes, or 

Territories within the AoR of the Class VI project of the 

permit application.

Prior to granting approval for the operation of a Class VI 

well, the Director shall consider the following: 

• Final AoR based on modeling, using data obtained 

during logging and testing of the well and the 

formation; 

• Any relevant updates to the information on the geologic 

structure and hydrogeologic properties of the proposed 

storage site and overlying formations; 

• Information on the compatibility of the carbon dioxide 

stream with fluids in the injection zone(s) and minerals 

in both the injection and the confining zone(s); 

• Results of the formation testing program;

• Final injection well construction procedures;

• Status of corrective action on wells in the AoR; 

• All available logging and testing program data on the 

well;

• A demonstration of mechanical integrity;

• Any updates to the any of the plans; and

• Any other information requested by the Director.

Permit application conditions in this proposed state 

regulation appear similar to the federal rule with 

significant detail provided for each of the plans that are 

required. For the delineation of the AoR this proposed 

state regulation specifies the time periods to predict CO2 

movement in the computational modeling. See details 

below. 

Using computational modeling, the applicant must 

predict the lateral and vertical extent of migration for the 

CO2 plume and formation fluids and the pressure 

differentials required to cause movement of injected 

fluids or formation fluids into an underground source of 

drinking water in the subsurface for the following time 

periods: 

• Five years after initiation of injection;

• From initiation of injection to the end of the injection 

period proposed by the applicant; and

• From initiation of injection to 10 years after the end of 

the injection period proposed by the applicant.

[5.203(e)(C)(ii)] 
C-3 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

Owners or operators seeking a waiver of the requirement 

to inject below the lowermost USDW submit a 

supplemental report.

Geologic Site Characterization

§146.83 Minimum criteria for siting. §5.206(a) Permit Standards: General criteria

A geologic system comprises: 

• An injection zone(s) of sufficient areal extent, 

thickness, porosity, and permeability to receive the 

total anticipated volume of the carbon dioxide stream.

• Confining zone(s) free of transmissive faults or 

fractures and of sufficient areal extent and integrity to 

contain the injected carbon dioxide stream and 

displaced formation fluids and allow injection at 

proposed maximum pressures and volumes without 

initiating or propagating fractures in the confining 

zone(s).

• At the Director’s discretion, additional zones that will 

impede vertical fluid movement, are free of faults and 

fractures that may interfere with containment, allow for 

pressure dissipation, and provide additional 

opportunities for monitoring, mitigation, and 

remediation.

Siting requirements in this proposed state regulation do 

not include the Director’s discretion to require additional 

zones. Besides this exception, siting requirements in this 

proposed state regulation appear similar to the federal 

rule. 

AoR and Corrective Action

§146.84 AoR and corrective action. §5.203(d) Area of review and corrective action 

The AoR is the region surrounding the geologic 

sequestration project where USDWs may be endangered 

by the injection activity. The AoR is delineated using

computational modeling that accounts for the physical 

and chemical properties of all phases of the injected CO2 

stream and is based on available site characterization, 

monitoring, and operational data. 

Part of the permit application, submit a plan that includes:

• Method for delineating the AoR; 

• Description of the minimum fixed frequency, not to 

exceed five years, to reevaluate the AoR; monitoring 

and operational conditions that would warrant an 

earlier reevaluation; how monitoring and operational 

data will be used to inform a reevaluation; how 

corrective action will be conducted; how corrective 

action will be adjusted if there are changes in the AoR; 

and how site access will be guaranteed for future 

corrective action.

To delineate the AoR and identify all wells that require 

corrective action, perform the following: 

• Predict, using existing site characterization, monitoring 

and operational data, and computational modeling, the 

projected lateral and vertical migration of the CO2 

plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient 

to cause the movement of injected fluids or formation 

fluids into a USDW are no longer present, or until the 

end of a fixed time period as determined by the 

The requirement for an area of review and corrective 

action plan in this proposed state regulation appears 

similar to the federal proposed rule. 
C-4 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

Director. The rule further describes the requirements of 

the model; 

• Identify all penetrations, including active and 

abandoned wells and underground mines, in the AoR 

that may penetrate the confining zone(s); and 

• Determine which abandoned wells in the AoR have 

been plugged.

At the minimum fixed frequency, not to exceed five years, 

or when monitoring and operational conditions warrant: 

• Reevaluate the AoR; 

• Identify all wells in the reevaluated AoR that require 

corrective action; 

• Perform corrective action on wells requiring corrective 

action in the reevaluated AoR; and

• Submit an amended AoR and corrective action plan or 

demonstrate to the Director through monitoring data 

and modeling results that no amendment to the AoR 

and corrective action plan is needed. 

The emergency and remedial response plan and the 

demonstration of financial responsibility must account for 

the AoR delineated, regardless of whether or not 

corrective action in the AoR is phased.

All m odeling i nputs an d da ta us ed t o s upport A oR 

reevaluations shall be retained for 10 years.

Financial Responsibility

§146.85 Financial responsibility. §5.205 Fees, Financial Responsibility, and Financial 

Assurance.

The owner or operator must demonstrate and maintain 

financial responsibility as approved by the Director, until 

the Director approves the completed post-injection site 

care and site closure plan and approves site closure. The 

owner or operator may be released from a financial 

instrument in the certain circumstances.

The financial responsibility instrument(s) used must: 

• Be from the list of qualifying instruments;

• Be sufficient to cover the cost of corrective action, 

injection well plugging, post injection site care and site 

closure, and emergency and remedial response; 

• Be sufficient to address endangerment of USDWs; and 

• Comprise protective conditions of coverage, including 

at a minimum cancellation, renewal, and continuation 

provisions, specifications on when the provider 

becomes liable in case of cancellation if there is a 

failure to renew with a new qualifying financial 

instrument, and requirements for the provider to meet a 

minimum rating, minimum capitalization, and ability to 

pass the bond rating when applicable.

Have a detailed written estimate, in current dollars, of the 

cost of performing corrective action on wells in the AoR, 

plugging the injection well(s), post-injection site care and 

site closure, and emergency and remedial response. 

The demonstration and maintenance of financial 

responsibility in this proposed state regulation appears 

similar to the federal rule and cover the cost of corrective 

action, injection well plugging, post injection site care 

and site closure, and emergency and remedial 

response. [5.205(b)(1) Exceptions are noted below.

A non-refundable base application fee, injection fee, and 

post-injection care fee must be remitted to the 

Commission with the application. The anthropogenic 

CO2 storage trust fund shall be capped at $5,000,000. 

[5.205(a)] 

In determining whether the person is financially 

responsible, the director must rely on:

• The most recent audited annual report filed with the 

SEC; or the most recent quarterly report filed with the 

SEC; or the most recent audited financial statement (if 

the first two do not apply).

[5.205(b)(2)] 

The determination of the amount of financial assurance

is subject to the following:

• The director must approve the dollar amount. The 

amount must be equal to or greater than the maximum 

amount to perform corrective action, emergency 
C-5 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

• The cost estimate must be performed for each phase 

separately and must be based on the costs to the 

regulatory agency of hiring a third party. 

• During the active life of the geologic sequestration 

project, the owner or operator must adjust the cost 

estimate for inflation within 60 days prior to the 

anniversary date of the establishment of the financial 

instrument. The Director must approve this change. 

• Whenever the current cost estimate increases/ 

decreases, the face amount of the financial assurance 

instrument may be increased/reduced to the amount of 

the current cost estimate only after the receipt of 

written approval from the Director. 

Notify the Director by certified mail of adverse financial 

conditions that may affect the ability to carry out injection 

well plugging and post-injection site care and site 

closure. 

Provide an adjustment of the cost estimate to the Director 

within 60 days of notification by the Director, if the 

Director determines during the annual evaluation of the 

qualifying financial responsibility instrument(s) that the 

most recent demonstration is no longer adequate to 

cover the cost of corrective action, injection well plugging, 

post-injection site care and site closure, and emergency 

and remedial response.

The Director must approve the use and length of pay-inperiods for trust funds or escrow accounts. 

response and remedial action, post-injection 

monitoring and site care, and closure of the geologic 

storage facility, exclusive of plugging costs. 

• A qualified professional engineer licensed by the State 

of Texas must prepare or supervise the preparation of 

the highest likely estimated cost to close the facility

• The Commission may use the proceeds of financial 

assurance to pay plugging costs if the financial 

assurance is insufficient for the plugging. 

[5.205(c)(2)(C)] 

Upon the incapacity of a bank or surety company by 

reason of bankruptcy, etc, the Commission must issue a 

notice to any operator who is without bond coverage and 

must specify a reasonable period to replace bond 

coverage, not to exceed 90 days. 

[5.205(d)(3)] 

Construction Requirements

§146.86 Injection well construction requirements. §5.203(e) Application requirements: Injection well 

construction

§5.206(b) Performance standards: Injection well

construction

All materials (e.g. casing and cementing materials, tubing 

and packer materials, cement and cement additives) 

used in construction must be compatible with fluids with 

which the materials may be expected to come into 

contact and must meet or exceed standards.

Casing and Cementing of Class VI Wells.

• The owner or operator must provide the quantitative 

information requested in the rule.

• Surface casing must extend through the base of the 

lowermost USDW and be cemented to the surface 

through the use of a single or multiple strings of casing 

and cement. 

• At least one long string casing, using a sufficient 

number of centralizers, must extend to the injection 

zone and must be cemented by circulating cement to 

the surface in one or more stages. 

• Circulation of cement may be accomplished by staging. 

The Director may approve an alternative method.

Tubing and Packer.

• All owners or operators must inject fluids through 

Construction requirements in this proposed state 

regulation appear similar to federal rule with 

requirements for fully cemented surface and long string 

casings, tubing and packer. Exceptions are noted below.

All injection wells must inject fluids through tubing set on 

a mechanical packer. Packers must be set no higher 

than 100 feet above the top of the permitted injection 

interval or at a location approved by the director.

[5.203(e)(C)(i)] 

The wellhead of each injection well must be equipped 

with a pressure observation valve on the tubing and 

each annulus of the well. 

[5.203(e)(C)(ii)] 
C-6 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

tubing with a packer set at a depth opposite a 

cemented interval at the location approved by the 

Director. 

• The owner or operator must submit the quantitative 

information requested in the rule.

Logging, Sampling and Testing

§146.87 Logging, sampling, and testing prior to 

injection well operation.

§5.203(f) Application requirements: Plan for logging, 

sampling, testing of injection wells after permitting 

but before injection.

During drilling and construction, the owner or operator 

must run appropriate logs, surveys and tests to 

determine or verify the depth, thickness, porosity, 

permeability, and lithology of, and the salinity of any 

formation fluids in all relevant geologic formations and 

then submit a descriptive report prepared by a 

knowledgeable log analyst that includes an interpretation 

of the results of such logs and tests.

At a minimum, such logs and tests must include:

• Deviation checks. 

• Before and upon installation of the surface casing:

- Resistivity, spontaneous potential, and caliper logs 

before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• Before and upon installation of the long string casing: 

- Resistivity, spontaneous potential, porosity, caliper, 

gamma ray, fracture finder logs, and any other logs 

the Director requires before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• A series of mechanical integrity tests, which may 

include:

- A pressure test with liquid or gas;

- A tracer survey such as oxygen-activation logging;

- A temperature or noise log;

- A casing inspection log; 

• Any alternative methods that are required by and/or 

approved of by the Director. 

Take whole cores or sidewall cores of the injection zone 

and confining system and formation fluid samples from 

the injection zone(s), and submit to the Director a 

detailed report prepared by a log analyst that includes: 

well log analyses, core analyses, and formation fluid 

sample information. 

Record fluid temperature, pH, conductivity, reservoir 

pressure, and static fluid level of the injection zone(s).

Determine or calculate injection and confining zone(s) 

fracture pressure; physical and chemical characteristics 

of the injection and confining zone(s) and formation fluids 

in the injection zone(s).

Logging, sampling, and testing requirements in this 

proposed state regulation appear similar to federal rule. 
C-7 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

Conduct pressure fall-off test and a pump test or 

injectivity tests upon completion, but prior to operation, to 

verify hydrogeologic characteristics of the injection 

zone(s).

Provide the Director with the opportunity to witness all 

logging and testing. Submit a schedule of such activities 

to the Director 30 days prior to conducting the first test.

Operating Requirements

§146.88 Injection well operating requirements. §5.206(c) Permit Standards: Operating a geologic 

storage facility

Ensure that injection pressure does not exceed 90 

percent of the fracture pressure of the injection zone(s) 

so as to ensure that the injection does not initiate new 

fractures or propagate existing fractures in the injection 

zone(s). All stimulation must be approved by the Director 

as part of the permit application and incorporated into the 

permit. 

Injection between the outermost casing protecting 

USDWs and the well bore is prohibited.

Fill the annulus between the tubing and the long string 

casing with a non-corrosive fluid approved by the 

Director. Maintain on the annulus a pressure that 

exceeds the operating injection pressure, unless the 

Director determines otherwise. 

Maintain mechanical integrity of the injection well at all 

times, other than during periods of well workover 

approved by the Director.

Install and use: 

• Continuous recording devices to monitor: the injection 

pressure; the rate, volume and/or mass, and 

temperature of the CO2 stream; and the pressure on 

the annulus between the tubing and the long string 

casing and annulus fluid volume; and

• Alarms and automatic surface shut-off systems or, at 

the discretion of the Director, down-hole shut-off 

systems (e.g., automatic shut-off check valves) for 

onshore wells or, other mechanical devices that 

provide equivalent protection; and

• Alarms and automatic down-hole shut-off systems for 

wells located offshore but within State territorial waters, 

designed to alert the operator and shut-in the well 

when operating parameters diverge beyond permitted 

ranges.

If a shutdown is triggered or a loss of mechanical integrity 

is discovered, immediately investigate and identify as 

expeditiously as possible the cause of the shutoff. If, 

upon such investigation, the well appears to be lacking 

mechanical integrity:

• Immediately cease injection;

• Take all steps reasonably necessary to determine 

whether there may have been a release of the injected 

Operating requirements in this proposed state regulation

appear similar to federal proposed rule including the 

requirements for alarms and automatic shut-off systems. 

Exceptions are noted below.

The total volume of CO2 injected into the storage facility 

must be metered through a master meter or a series of 

master meters. The volume of CO2 injected into each 

injection well must be metered through an individual well 

meter. 

[5.206(c)(2)(B)] 

The operator must comply with a maximum surface

injection pressure limit approved by the director and 

specified in the permit. In approving a maximum surface 

injection pressure limit, the director must consider the 

results of well tests and, where appropriate,

geomechanical or other studies that assess the risks of 

tensile failure and shear failure. The director must 

approve limits that, with a reasonable degree of 

certainty, will avoid initiation or propagation of fractures

in the confining zone or cause otherwise nontransmissive faults or fractures transecting the confining 

zone to become transmissive. In no case may injection 

pressure cause movement of injection fluids or formation 

fluids in a manner that endangers underground sources 

of drinking water. The director may approve a plan for 

controlled artificial fracturing of the injection zone. 

[5.206(c)(2)(C)] The State rule does not establish 

maximum injection pressure as a function of fracture 

pressure.

The operator must continuously record, continuously 

monitor, or control by a preset high-low pressure sensor 

switch the wellhead pressure of each injection well. 

[5.206(c)(2)(E)]
C-8 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

CO2 stream or formation fluids into any unauthorized 

zone;

• Notify the Director within 24 hours;

• Restore and demonstrate mechanical integrity to the 

satisfaction of the Director prior to resuming injection; 

• Notify Director when injection is expected to resume.

Mechanical Integrity

§146.89 Mechanical integrity. §5.203(h) Application requirements: Mechanical 

integrity testing; 

§5.206(e) Permit Standards: Mechanical integrity

A Class VI well has mechanical integrity if there is no 

significant leak in the casing, tubing, or packer; and there 

is no significant fluid movement into a USDW through 

channels adjacent to the injection well bore.

To evaluate the absence of significant leaks, following an 

initial annulus pressure test, continuously monitor 

injection pressure, rate, injected volumes; pressure on 

the annulus between tubing and long-string casing; and 

annulus fluid volume.

 

At least once per year, use an approved tracer survey or 

temperature or noise log to determine the absence of 

significant fluid movement.

 

If required by the Director, the owner or operator must 

run a casing inspection log to determine the presence or 

absence of corrosion in the long-string casing. 

The Director may require additional or alternative tests to 

evaluate mechanical integrity. 

To obtain approval for a new mechanical integrity test, 

the Director must submit a written request to the 

Administrator and the Administrator may approve the 

request. Any alternate method approved by the 

Administrator will be published in the Federal Register

and may be used in all States.

The owner or operator and the Director must apply 

methods and standards generally accepted in the 

industry. When the owner or operator reports the results 

of mechanical integrity tests to the Director, he/she shall 

include a description of the test(s) and the method(s) 

used. In making his/her evaluation, the Director must 

review monitoring and other test data submitted since the 

previous evaluation.

Mechanical integrity requirements in this proposed state 

regulation appear similar to federal rule including 

continuous monitoring for internal mechanical integrity. 

Exceptions are noted below.

 

The mechanical integrity testing plan, as part of a permit 

application, must include a schedule for the mechanical 

integrity performance tests at a minimum frequency of 

five years. At least once every five years, the operator 

must confirm that the injected fluids are confined to the 

injection zone using a method approved by the director 

(e.g., diagnostic surveys such as oxygen-activation 

logging or temperature or noise logs). 

[5.203(h)(2) & (h)(1)(D)] (i.e., external MIT every 5 

years). 

Testing and Monitoring Requirements

§146.90 Testing and monitoring requirements. §5.203(j) Application requirements: Plan for 

monitoring, sampling, and testing after initiation of 

operation;

§5.206(d) Permit Standards: Monitoring, sampling, 

and testing requirements. 

Testing and monitoring must, at a minimum, include:

• Analysis of CO2 stream with sufficient frequency to 

yield data representative of its chemical and physical 

Testing and monitoring requirements in this proposed 

state regulation appear similar to the federal rule. 

Exceptions are noted below.
C-9 

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

characteristics; 

• Installation and use of continuous recording devices to 

monitor injection pressure, rate, and volume; the 

pressure on the annulus between the tubing and the 

long string casing; and the annulus fluid volume added;

• Corrosion monitoring of the well materials for loss of 

mass, thickness, cracking, pitting, and other signs of 

corrosion must be performed on a quarterly basis to 

ensure that the well components meet the minimum 

standards for material strength and performance by 

analyzing coupons, routing the CO2 stream through a 

loop; or using an alternative method approved by the 

Director.

• Periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s) 

through the confining zone(s) or additional zones.

• A demonstration of external mechanical integrity at 

least once per year until the injection well is plugged; 

and, if required by the Director, a casing inspection log; 

• A pressure fall-off test at least once every five years;

• Testing and monitoring to track the extent of the CO2 

plume and the presence or absence of elevated 

pressure (e.g., the pressure front) by using:

- Direct methods in the injection zone(s); and,

- Indirect methods, unless the Director determines that 

such methods are not appropriate;

• The Director may require surface air monitoring and/or 

soil gas monitoring. 

• Any additional monitoring, as required by the Director 

• Review the testing and monitoring plan at least once 

every five years. Amended plans or demonstrations 

shall be submitted to the Director within one year of an 

AoR reevaluation, after any significant changes to the 

facility, or when required by the Director.

• A quality assurance and surveillance plan. 

After initiation of injection, the performance on a semiannual basis of corrosion monitoring of the well

materials. The operator must report the results of such 

monitoring annually. 

[5.203(j)(2)(C)] 

The state rule includes monitoring of geochemical and 

geophysical changes, including: 

• Periodic sampling of the fluid temperature, pH, 

conductivity, reservoir pressure and static fluid level of 

the injection zone and monitoring for pressure 

changes, and for changes in geochemistry, in a 

permeable and porous formation near to and above 

the top confining zone; 

• Periodic monitoring of the quality and geochemistry of 

an underground source of drinking water within the 

area of review and the formation fluid in a permeable 

and porous formation near to and above the top 

confining zone to detect any movement of the injected 

CO2 through the confining zone into that monitored 

formation; 

• The location and number of monitoring well justified 

on the basis of the area of review, injection rate and 

volume, geology, and the presence of artificial 

penetrations and other factors specific to the geologic 

storage facility; and 

• The monitoring frequency and spatial distribution of 

monitoring wells based on baseline geochemical data 

collected under subsection (c)(2) of this section and 

any modeling results in the area of review evaluation.

Tracking the extent of the CO2 plume and the position of 

the pressure front by using indirect, geophysical 

techniques, which may include seismic, electrical, 

gravity, or electromagnetic surveys and/or down-hole 

CO2 detection tools.

Additional monitoring as the director may determine to 

be necessary to support, upgrade, and improve 

computational modeling of the area of review evaluation 

and to determine compliance with the requirements that 

the injection activity not allow the movement of fluid 

containing any contaminant into underground sources of 

drinking water and that the injected fluid remain within 

the permitted interval.

§5.203(j)(2)(D) 

Reporting Requirements 

§146.91 Reporting requirements. §5.207 Reporting and Record-Keeping. 

The owner or operator must, at a minimum, provide the 

following reports to the Director, for each permitted Class 

VI well:

Semi-annual reports containing:

• Any changes to the physical, chemical, and other 

relevant characteristics of the CO2 stream from the 

proposed operating data;

Reporting requirements in this proposed state regulation

appear similar to the federal rule. Exceptions are noted 

below.

The operator must file a complete record of all tests in 

duplicate with the district office within 30 day s after the 

testing. 

[5.207(a)(1)] 
C-10

Final Class VI Rule

(pre-publication version signed by the Administrator on 

Texas Proposed Rule

(October 15, 2010) 

November 22, 2010)

• Monthly average, maximum, and minimum values for 

injection pressure, flow rate and volume, and annular 

pressure; 

• A description of any event that exceeds operating 

parameters for annulus pressure or injection pressure 

specified in the permit;

• A description of any event which triggers a shut-off 

device required and the response taken;

• The monthly volume and/or mass of the CO2 stream 

injected over the reporting period and the volume 

injected cumulatively over the life of the project;

• Monthly annulus fluid volume added; and 

• The results of monitoring prescribed.

Report, within 30 days, the results of:

• Periodic tests of mechanical integrity;

• Any well workover; and,

• Any other test of the injection well conducted by the 

permittee if required by the Director.

Report, within 24 hours of:

• Any evidence that the injected CO2 stream or 

associated pressure front may cause an endangerment 

to a USDW; 

• Any noncompliance with a permit condition, or 

malfunction of the injection system, which may cause 

fluid migration into or between USDWs;

• Any triggering of a shut-off system (i.e., down-hole or 

at the surface); 

• Any failure to maintain mechanical integrity; or.

• Any release of CO2 to the atmosphere or biosphere. 

Owners or operators must notify the Director in writing 30 

days in advance of:

• Any planned well workover; 

• Any planned stimulation activities, other than 

stimulation for formation testing conducted under 

§146.82; and

• Any other planned test of the injection well conducted 

by the permittee. 

Regardless of whether a State has primary enforcement 

responsibility, owners or operators must submit all 

required reports, submittals, and notifications under 

subpart H of this part to EPA in an electronic format 

approved by EPA.

Records shall be retained by the owner or operator as 

follows: 

• All data collected under §146.82 for Class VI permit 

applications shall be retained throughout the life of the 

geologic sequestration project and for 10 years 

following site closure.

• Data on the nature and composition of all injected 

fluids collected pursuant to §146.90(a) shall be 

retained until 10 years after site closure. The Director 

may require the owner or operator to deliver the 

Semi-annual report. The operator must report:

• A summary of well head pressure monitoring;

• A description of any event that significantly

[5.207(a)(2)(C)(i) & (iv)] 

exceeds 

operating parameters for annulus pressure or injection 

pressure as specified in the permit.

Unlike t he f ederal r ule, t his pr oposed s tate r egulation

does not require the semi-annual reporting of: 

• The monthly volume and/or mass of the CO2 stream 

injected over the reporting period and the volume 

injected cumulatively over the life of the project;

• Monthly annulus fluid volume added. 

[§146.91(a)(5) & (6)]

The operator must retain all wellhead pressure records, 

metering records, a nd integrity t est r esults f or at l east 

five years.

[5.207(c)] 
C-11

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

records to the Director at the conclusion of the 

retention period. 

• Monitoring data collected pursuant to §146.90(b) 

through (i) shall be retained for 10 years after it is 

collected.

• Well plugging reports, post-injection site care data, 

including data and information used to develop the 

demonstration of the alternative post-injection site care 

timeframe, and the site closure report shall be retained 

for 10 years following site closure.

• The Director has authority to require the owner or 

operator to retain any records required in this subpart 

for longer than 10 years after site closure.

Well Plugging

§146.92 Injection well plugging. §5.203(k) Application requirements: Well plugging 

plan; 

§5.206(i) Permit Standards: Well plugging. 

Prior to the well plugging, the owner or operator must 

flush each Class VI injection well with a buffer fluid, 

determine bottomhole reservoir pressure, and perform a 

final external mechanical integrity test. 

Well Plugging Plan must include the following 

information:

• Appropriate tests or measures for determining 

bottomhole reservoir pressure;

• Appropriate testing methods to ensure external 

mechanical integrity;

• The type and number of plugs to be used;

• The placement of each plug, including the elevation of 

the top and bottom of each plug;

• The type, grade, and quantity of material to be used in 

plugging. The material must be compatible with the 

CO2 stream; and

• The method of placement of the plugs.

Notice of intent to plug. 

The owner or operator must notify the Director in writing 

at least 60 days before plugging of a well. At this time, if 

any changes have been made to the original well 

plugging plan, the owner or operator must also provide 

the revised well plugging plan. The Director may allow for 

a shorter notice period. Any amendments to the injection 

well plugging plan must be approved by the Director, 

must be incorporated into the permit, and are subject to 

the permit modification requirements. 

Plugging report. 

Within 60 days after plugging, the owner or operator must 

submit a plugging report to the Director. The report must 

be certified as accurate by the owner or operator and by 

the person who performed the plugging operation (if 

other than the owner or operator.) The owner or operator 

shall retain the well plugging report for 10 years following 

site closure.

The well plugging plan in this proposed state regulation

applies to all monitoring wells that penetrate the base of 

usable quality water and all injection wells upon 

abandonment. Well plugging requirements in this 

proposed state regulation appear similar to the federal 

rule but also address monitoring wells. Exceptions are 

noted below.

The operator will file a notice of intention to plug and 

abandon a well with the appropriate Commission district

office and the division in Austin at least five days prior to 

the beginning of plugging operations. The applicant’s 

plan must ensure that within 30 days after plugging the 

operator will file a complete well plugging record in 

duplicate with the appropriate district office.

[5.203(k)(3)(B) & (k)(4)] 
C-12

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

Post-injection Site Care

§146.93 Post-injection site care and site closure. §5.206(j) Permit Standards: Post-injection storage 

facility care and closure; 

§5.206(k) Permit Standards: Deed notation; 

§5.206(l) Permit Standards: Retention of records; 

§5.206(m) Signs. 

Part of the permit application, includes the following:

• Pressure differential between pre-injection and 

predicted post-injection pressures in injection zone(s);

• Predicted position of the CO2 plume and associated 

pressure front at site closure; 

• Description of post-injection monitoring location, 

methods, and proposed frequency; and

• A proposed schedule for submitting post-injection site 

care monitoring results to the Director. 

• The duration of the post-injection site care timeframe 

and, if approved by the Director, the demonstration of 

the alternative post-injection site care timeframe. 

Upon cessation of injection, submit an amended plan or 

demonstrate to the Director no amendment is needed. 

May modify and resubmit within 30 days of such change. 

At the Director's discretion, demonstrate during the 

permitting process that an alternative post-injection site 

care timeframe is appropriate and ensures nonendangerment of USDWs. The demonstration must be 

based on site-specific information, including the results of 

site-specific computational modeling; the predicted 

timeframe for pressure decline; the predicted rate of CO2 

plume migration; site-specific chemical processes that 

will result in CO2 trapping; the predicted rate of CO2 

trapping; characterization of the confining zone(s); 

laboratory analyses or studies to verify the information on 

trapping; the presence of potential conduits for fluid 

movement and the quality of abandoned well plugs within 

the AoR; the distance between the injection zone and the 

USDWs above and/or below the injection zone; and any 

additional site-specific factors determined by the Director. 

The demonstration must meet the criteria at 

§146.93(c)(2) for ensuring the quality and accuracy of the 

data and models on which the demonstration is based.

Monitor the site following the cessation of injection to 

show the position of the CO2 plume and pressure front 

and demonstrate that USDWs are not being endangered. 

• Continue to conduct monitoring as specified in the 

Director-approved plan for at least 50 years following 

the cessation of injection or for the duration of the

approved alternative timeframe, unless he/she makes 

a demonstration. At the Director’s discretion, the 

monitoring must continue until the project no longer 

poses an endangerment to USDWs. 

Notify the Director in writing at least 120 days before site 

closure. If any changes have been made to the original 

plan, the owner or operator must also provide the revised 

Post-injection site care requirements in this proposed 

state regulation appear similar to the federal rule.

Exceptions are noted below. 

Prior to authorization for storage facility closure, the 

operator must demonstrate all of the following: 

• The estimated magnitude and extent of the facility

plume and the area of elevated pressure);

• Footprint (the CO2 or displaced formation fluids that 

will endanger underground sources of drinking water;

• That the injected or displaced fluids are not expected 

to migrate in the future in a manner that encounters a 

potential leakage pathway into underground sources 

of drinking water;

• That the injection wells at the site completed into or 

through the injection zone or confining zone will be 

plugged and abandoned in accordance with these 

requirements; and 

• Any remaining facility monitoring wells will be properly 

plugged or are being managed by a person and in a 

manner approved by the director. [5.206(j)(3)]

A time frame for post-injection site care is not specified 

in this proposed state regulation nor is an alternate 

plan.. 

The operator must retain for five years following storage 

facility closure records collected during the post-injection 

storage facility care period. The operator must deliver 

the records to the director at the conclusion of the 

retention period, and the records must thereafter be 

retained at the Austin headquarters of the Commission.

[5.206(l)] 

The operator must identify each location at which 

geologic storage activities take place, including each 

injection well, by a sign that meets the requirements 

specified in §3.3(1), (2), and (5) of this title. In addition, 

each sign must include a telephone number where the 

operator or a representative of the operator can be 

reached 24 hours a day, seven days a week in the event 

of an emergency.

[5.206(m)]

 
C-13

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

plan. The Director may allow for a shorter notice period.

After the Director has authorized site closure, plug all 

monitoring wells in a way which will not allow movement 

of injection or formation fluids that endangers a USDW.

Submit a site closure report to the Director within 90 days 

of site closure, which must be retained at a location 

chosen by the Director for 10 years. Report includes: 

• Documentation of appropriate injection and monitoring 

well plugging. Provide a copy of a survey plat;

• Documentation of appropriate notification and 

information to such State, local and Tribal authorities 

that have authority over drilling activities; and

• Records reflecting the nature, composition, and volume 

of the CO2 stream.

Record a notation on the deed to the facility property that 

will in perpetuity provide any potential purchaser:

• The fact that land has been used to sequester CO2; 

• The name of the agency or authority with which the 

survey plat was filed and the address of the EPA 

Regional Office to which it was submitted; and

• Volume of fluid injected, the injection zone (s) it was 

injected, and the period over which injection occurred. 

Retain for 10 years following site closure, records 

collected during post-injection site care period. Deliver 

the records to the Director at the end of the retention 

period. Retain records at location chosen by the Director.

Emergency and Remedial Response

§146.94 Emergency and remedial response. §5.206(g) Permit Standards: Emergency, mitigation, 

and remedial response. 

As part of the permit application, the owner or operator 

must provide the Director with an emergency and 

remedial response plan that describes actions the owner 

or operator must take to address movement of the 

injection or formation fluids that may cause an 

endangerment to a USDW during construction, operation, 

and post-injection site care periods. 

If evidence shows potential endangerment of USDWs, 

the owner or operator should cease injection; notify the 

Director within 24 hours; implement the emergency and 

remedial response plan. Prior to re-commencing 

injection, demonstrate to the Director non-endangerment 

to USDWs. 

 

• Periodically review the emergency and remedial 

response plan at least once every five years. Amended 

plans or demonstrations shall be submitted to the 

Director within one year of an AoR reevaluation; 

following any significant changes to the facility; or

when required by the Director.

Emergency and remedial response requirements in this 

proposed state regulation appear similar to federal rule. 

Additional requirements are noted below.

Training.

• The operator must train all employees before 

commencing injection and storage operations at the 

facility. The operator must train each subsequently 

hired employee before that employee commences 

work at the storage facility.

• The operator must hold a safety meeting with each 

contractor prior to the commencement of any new 

contract work at a storage facility. The operator must 

explain emergency measures specific to the 

contractor’s work in the contractor safety meeting.

• The operator must provide training schedules, training 

dates, and course outlines to Commission personnel 

upon request for the purpose of Commission review to 

determine compliance. 

[5.206(g)(2)] 
C-14

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Texas Proposed Rule

(October 15, 2010) 

Class VI Injection Depth Waiver Requirements

§146.95 Class VI injection depth waiver requirements.

In seeking a waiver of the requirement to inject below the

lowermost USDW, the owner or operator must submit a 

supplemental report concurrent with permit application.

Details about the possible demonstrations and other 

requirements are noted in the rule text.

The Director must submit, to the Regional Administrator, 

documentation of a list of requirements described in the 

rule text.

The Director shall give public notice that a waiver 

application has been submitted. The notice shall clearly 

state:

• The depth of the proposed injection zone(s); 

• The location of the injection well(s);

• The name and depth of all USDWs within the AoR;

• A map of the AoR; 

• The names of any public water supplies affected, 

reasonably likely to be affected, or served by USDWs 

in the AoR; and,

• The results of UIC-Public Water System Supervision 

consultation. 

Following public notice, the Regional Administrator shall 

provide written concurrence or non-concurrence 

regarding waiver issuance. 

If a waiver is issued, within 30 days of waiver issuance, 

EPA shall post the information detailed in the rule text on 

the Office of Water’s Web site.

Upon receipt of a waiver of the requirement to inject 

below the lowermost USDW for geologic sequestration, 

the owner or operator must comply with all requirements, 

certain modified requirements, and any additional 

requirements requested by the Director.

This proposed state regulation has no option of an 

injection depth waiver.
D-1

 Appendix D 

Washington Administrative Code 

Preliminary Comparison with the Final Class VI Rule 

This review only includes the definitions and regulations specific to Class V wells used to inject carbon dioxide for 

permanent geologic sequestration. There are additional requirements that apply to the geologic sequestration in 

addition to all other classes regulated by Washington in WAC Chapter 173-218. 

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 2X, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

Applicability

§146.81 - Applicability Section 3. Applicability





This rule applies to any wells used to inject carbon 

dioxide specifically for the purpose of geologic 

sequestration. 

Also applies to owners or operators of permit- or ruleauthorized Class I, Class II, or Class V experimental 

carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well 

or wells. 

This rule applies to Class V UIC wells used for the 

geologic sequestration of carbon dioxide. 

§146.81 (d) - Applicability: Definitions 173-218-030. Definitions.

Geologic sequestration (GS) means the long-term Geologic sequestration of carbon dioxide means the 

containment of a gaseous, liquid, or supercritical carbon injection of carbon dioxide into subsurface geologic 

dioxide stream in subsurface geologic formations. This formations to permanently prevent its release into the 

term does not apply to carbon dioxide capture or atmosphere. 

transport. 

Geologic sequestration project means an injection well or Geologic sequestration project means the surface and 

wells used to emplace a carbon dioxide stream beneath underground facilities used to inject carbon dioxide for 

the lowermost formation containing a USDW; or, wells sequestration and includes: Geologic containment 

used for geologic sequestration of carbon dioxide that system, monitoring zone(s) and surface facilities 

have been granted a waiver of the injection depth described in the permit application. 

requirements pursuant to requirements at §146.95; or, 

wells used for geologic sequestration of carbon dioxide Geologic sequestration project boundary means a three 

that have received an expansion to the areal extent of an dimensional boundary defined in permit that encloses all 

existing Class II enhanced oil recovery or enhanced gas surface and underground facilities of the geologic 

recovery aquifer exemption pursuant to §§146.4 of this sequestration project and extends vertically to the 

chapter and 144.7(d). It includes the subsurface three- overlying ground surface. 

dimensional extent of the carbon dioxide plume, 

associated area of elevated pressure, and displaced 

fluids, as well as the surface area above that delineated 

region. 

Permit Conditions

§146.82 Required Class VI permit information. 173-218-115 (1). Permit required; 

173-218-115 (2). Permit application. 

Prior to the issuance of a construction or conversion 

permit, the owner or operator must submit the following: 

 Information required in 40 CFR 144.31 (e)(1) - (6); 

 Map showing the injection well, the applicable AoR, 

and faults, if known or suspected; 

 Information on the geologic structure and 

hydrogeologic properties; 

 Tabulation of all wells within the AoR which penetrate 

the injection or confining zone(s); 

 Maps and stratigraphic cross sections indicating all 

USDWs, water wells and springs within the AoR, their 

The permit requirements appear to be similar to the 

federal requirements. Class V UIC wells used for the 

geologic sequestration of carbon dioxide must have a 

state waste discharge permit under chapter 173-216 

WAC, which established enforceable limits on 

contaminants in the discharge. 

Geologic and hydrogeologic evaluations are required. 

The existing geologic, geophysical, geomechanical, 

geochemical, hydrogeological and engineering data 

shall be evaluated as part of the application. 

                                                           

1 Only the sections specific to geologic sequestration were reviewed. Specifically the definition and specific requirements for Class V wells used

to inject carbon dioxide for permanent geologic sequestration sections were compared to the federal regulations.
D-2

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

positions relative to the injection zone(s), and the [WAC 173-218-115 (2)] 

direction of water movement, where known; 

 Baseline geochemical data on subsurface formations; A permit authorizing the geologic sequestration of 

 Proposed operating data; carbon dioxide shall include information supporting the 

 Proposed pre-operational formation testing program; demonstration required by WAC 173-200-050 (3)(b)(vi) 

 Proposed stimulation program; and all of the following in WAC 173-218-115 (2): Permit 

 Proposed procedure to conduct injection operation; application. 

 Schematics of the construction details of the well; 

 Injection well construction procedures; 

 Proposed AoR and corrective action plan; 

Requirements that vary from the federal requirements 

are listed below: 

 A demonstration of financial responsibility; 

 Proposed testing and monitoring plan; 

 Proposed injection well plugging plan; 

 Proposed post-injection site care and site closure plan; 

Applicants must include a description of how the project 

will address: 

 All jurisdictional boundaries within ten miles of the 

geologic sequestration project boundary such as:  Proposed alternative post-injection site care timeframe; International borders, state borders, local jurisdictions,  Proposed emergency and remedial response plan; tribal land, national parks or state parks;  A list of contacts identified to be within the AoR; and  Accessibility for operations and monitoring in areas  Any other information requested by the Director. where access is restricted by: Shorelines, flood plains, 

urban or other development, and any other natural or The Director shall notify, in writing, any States, Tribes, or man-made limiting factors; Territories within the AoR of the Class VI project of the  Active Holocene faults within five miles and seismic 

permit application. risks; 

Prior to granting approval for the operation of a Class VI An evaluation of absorption characteristics or 

well, the Director shall consider the following: geochemical reaction/mineralization processes, with  Final AoR based on modeling, using data obtained regard to the ability to prevent migration of CO2 beyond during logging and testing of the well and the the proposed geologic containment system must be formation; included. 

 Any relevant updates to the information on the geologic 

structure and hydrogeologic properties of the proposed An evaluation of the potential displacement of in situ 

storage site and overlying formations; fluids and the potential impact on ground water 

 Information on the compatibility of the carbon dioxide resources, if any must be submitted. 

stream with fluids in the injection zone(s) and minerals 

in both the injection and the confining zone(s); A detailed description of the proposed project public 

 Results of the formation testing program; safety and emergency response plan. The plan shall 

 Final injection well construction procedures; detail the safety procedures concerning the facility and 

 Status of corrective action on wells in the AoR; residential, commercial, and public land use within one 

 All available logging and testing program data on the mile, or any other distance as deemed necessary by the 

well; department, of the boundary of geologic sequestration 

 A demonstration of mechanical integrity; project area. The public safety and emergency response 

 Any updates to the any of the plans; and procedures shall include contingency plans for leakage 

 Any other information requested by the Director.

Owners or operators seeking a waiver of the requirement 

to inject below the lowermost USDW submit a 

supplemental report. 

from any well, flow lines, or other permitted facility. The 

public safety and emergency response procedures also 

shall identify specific contractors and equipment vendors 

capable of providing necessary services and equipment 

to respond to incidents such as: Injection well leaks or 

loss of containment from injection wells or releases from 

the geologic containment system. These emergency 

response procedures shall be updated as necessary 

throughout the operational life of the permitted storage 

facilities. 

A detailed worker safety plan that addresses safety 

training and safe working procedures at the facility. 

A risk assessment that identifies and quantifies hazards, 

probabilities, features, events and processes that might 

result in undesirable impacts to public health and the 

environment. 
D-3

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

The payment of the application fee must occur with the 

permit submission. 

[WAC 173-218-115 (2)] 

Geologic Site Characterization

§146.83 Minimum criteria for siting. 173-218-115 (2). Permit application. 

A geologic system comprises: WAC requires GS wells to be located in geologic system 

 An injection zone(s) of sufficient areal extent, that will prevent endangerment of underground sources 

thickness, porosity, and permeability to receive the of drinking water. 

total anticipated volume of the carbon dioxide stream. [WAC 173-218-115 (2)] 

 Confining zone(s) free of transmissive faults or 

fractures and of sufficient areal extent and integrity to Applicants must submit information on the predicted 

contain the injected carbon dioxide stream and extent of the injected CO2 plume determined with 

displaced formation fluids and allow injection at modeling tools acceptable to the department that use all 

proposed maximum pressures and volumes without available geologic and reservoir engineering information, 

initiating or propagating fractures in the confining and the projected response and storage capacity of the 

zone(s). geologic containment system. 

 At the Director’s discretion, additional zones that will [WAC 173-218-115 (2)] 

impede vertical fluid movement, are free of faults and 

fractures that may interfere with containment, allow for 

pressure dissipation, and provide additional 

opportunities for monitoring, mitigation, and 

remediation.

AoR and Corrective Action

§146.84 AoR and corrective action. 173-218-115 (2). Permit application. 

The AoR is the region surrounding the geologic 

sequestration project where USDWs may be endangered 

by the injection activity. The AoR is delineated using 

computational modeling that accounts for the physical 

and chemical properties of all phases of the injected CO2 

stream and is based on available site characterization, 

monitoring, and operational data. 

Part of the permit application, submit a plan that includes: 

 Method for delineating the AoR; 

 Description of the minimum fixed frequency, not to 

exceed five years, to reevaluate the AoR; monitoring 

and operational conditions that would warrant an 

earlier reevaluation; how monitoring and operational 

data will be used to inform a reevaluation; how 

corrective action will be conducted; how corrective 

action will be adjusted if there are changes in the AoR; 

and how site access will be guaranteed for future 

corrective action. 

To delineate the AoR and identify all wells that require 

corrective action, perform the following: 

 Predict, using existing site characterization, monitoring 

and operational data, and computational modeling, the 

projected lateral and vertical migration of the CO2 

plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient 

to cause the movement of injected fluids or formation 

fluids into a USDW are no longer present, or until the 

end of a fixed time period as determined by the 

Director. The rule further describes the requirements of 

the model; 

 Identify all penetrations, including active and 

abandoned wells and underground mines, in the AoR 

WAC defines the AoR or boundaries of the geologic 

sequestration project which shall be calculated to 

include the area containing ninety-five percent of the 

injected CO2 mass one hundred years after the 

completion of all CO2 injection or the plume boundary at 

the point in time when expansion is less than one 

percent per year, whichever is greater, or another 

method approved by the department. 

The WAC requires similar types of information to be 

submitted about the AoR as in the federal regulations. A 

frequency to re-evaluate the AoR is not specified in 173-

281-115. 

[WAC 173-218-115 (2)] 

WAC includes requirements for performing corrective 

action.
D-4

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

that may penetrate the confining zone(s); and 

 Determine which abandoned wells in the AoR have 

been plugged. 

At the minimum fixed frequency, not to exceed five years, 

or when monitoring and operational conditions warrant: 

 Reevaluate the AoR; 

 Identify all wells in the reevaluated AoR that require 

corrective action; 

 Perform corrective action on wells requiring corrective 

action in the reevaluated AoR; and 

 Submit an amended AoR and corrective action plan or 

demonstrate to the Director through monitoring data 

and modeling results that no amendment to the AoR 

and corrective action plan is needed. 

The emergency and remedial response plan and the 

demonstration of financial responsibility must account for 

the AoR delineated, regardless of whether or not 

corrective action in the AoR is phased. 

All modeling inputs and data used to support AoR 

reevaluations shall be retained for 10 years. 

Financial Responsibility

§146.85 Financial responsibility. 173-218-115 (7). Financial assurance. 

The owner or operator must demonstrate and maintain 

financial responsibility as approved by the Director, until 

the Director approves the completed post-injection site 

care and site closure plan and approves site closure. The 

owner or operator may be released from a financial 

instrument in the certain circumstances. 

The financial responsibility instrument(s) used must: 

 Be from the list of qualifying instruments; 

 Be sufficient to cover the cost of corrective action, 

injection well plugging, post injection site care and site 

closure, and emergency and remedial response; 

 Be sufficient to address endangerment of USDWs; and 

 Comprise protective conditions of coverage, including 

at a minimum cancellation, renewal, and continuation 

provisions, specifications on when the provider 

becomes liable in case of cancellation if there is a 

failure to renew with a new qualifying financial 

instrument, and requirements for the provider to meet a 

minimum rating, minimum capitalization, and ability to 

pass the bond rating when applicable. 

Have a detailed written estimate, in current dollars, of the 

cost of performing corrective action on wells in the AoR, 

plugging the injection well(s), post-injection site care and 

site closure, and emergency and remedial response. 

 The cost estimate must be performed for each phase 

separately and must be based on the costs to the 

regulatory agency of hiring a third party. 

 During the active life of the geologic sequestration 

project, the owner or operator must adjust the cost 

estimate for inflation within 60 days prior to the 

anniversary date of the establishment of the financial 

instrument. The Director must approve this change. 

 Whenever the current cost estimate increases/ 

The WAC includes specific financial assurance 

requirements. The instruments slightly differ from the 

federal requirements and the financial responsibility plan 

needs to be updated annually to include cost changes 

due to inflation. 

The owner or operator shall establish a closure and 

post-closure account to cover all closure and postclosure expenses. The performance security held in the 

account may be: 

 Bank letters of credit; 

 Cash deposits; 

 Negotiable securities; 

 An assignment of savings account; 

 A savings certificate in a Washington bank; 

 A corporate surety bond executed in favor of the 

department by a corporation authorized to do 

business in the state of Washington; or 

 Other financial instruments or performance security 

acceptable to the department. 

[WAC 173-218-115 (7)] 
D-5

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

decreases, the face amount of the financial assurance 

instrument may be increased/reduced to the amount of 

the current cost estimate only after the receipt of 

written approval from the Director. 

Notify the Director by certified mail of adverse financial 

conditions that may affect the ability to carry out injection 

well plugging and post-injection site care and site 

closure. 

Provide an adjustment of the cost estimate to the Director 

within 60 days of notification by the Director, if the 

Director determines during the annual evaluation of the 

qualifying financial responsibility instrument(s) that the 

most recent demonstration is no longer adequate to 

cover the cost of corrective action, injection well plugging, 

post-injection site care and site closure, and emergency 

and remedial response. 

The Director must approve the use and length of pay-inperiods for trust funds or escrow accounts. 

Construction Requirements

§146.86 Injection well construction requirements. 173-218-115 (3). Geologic sequestration well 

standards; 

173-218-115 (4). Permit terms and conditions. 

All materials (e.g. casing and cementing materials, tubing The minimum standards for construction and 

and packer materials, cement and cement additives) maintenance of wells in Chapter 173-160 WAC apply to 

used in construction must be compatible with fluids with sequestration wells. Additional requirements apply to the 

which the materials may be expected to come into casing materials and cement. The casing and cement 

contact and must meet or exceed standards. must be designed and tested to withstand the reactive 

fluids and expected conditions encountered during the 

Casing and Cementing of Class VI Wells. geologic sequestration project, including the post-

 The owner or operator must provide the quantitative closure period. 

information requested in the rule. [WAC 173-218-115 (3)] 

 Surface casing must extend through the base of the 

lowermost USDW and be cemented to the surface All terms and conditions listed in WAC 173-216-110, 

through the use of a single or multiple strings of casing state waste discharge permit program, apply. In addition, 

and cement. the following terms and conditions shall apply to injection 

 At least one long string casing, using a sufficient permits for the geologic sequestration of carbon dioxide 

number of centralizers, must extend to the injection listed in 173-218-115(4) Permit terms and conditions. 

zone and must be cemented by circulating cement to Theses conditions do not include all of the consideration 

the surface in one or more stages. included in the federal requirements. 

 Circulation of cement may be accomplished by staging. [WAC 173-218-115 (4)] 

The Director may approve an alternative method. 

Tubing and Packer.

 All owners or operators must inject fluids through 

tubing with a packer set at a depth opposite a 

cemented interval at the location approved by the 

Director. 

 The owner or operator must submit the quantitative 

information requested in the rule. 

Logging, Sampling and Testing

§146.87 Logging, sampling, 

injection well operation.

and testing prior to 173-218-115 (3). Geologic sequestration well 

standards. 

During drilling and construction, the owner or operator An annual test for casing integrity/corrosion and other 

must run appropriate logs, surveys and tests to tests are required. Any finding of inadequate structural 

determine or verify the depth, thickness, porosity, integrity shall be reported to the department within 

permeability, and lithology of, and the salinity of any twenty-four hours. [WAC 173-218-115 (3)] 
D-6

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

formation fluids in all relevant geologic formations and 

then submit a descriptive report prepared by a 

knowledgeable log analyst that includes an interpretation 

of the results of such logs and tests. 

At a minimum, such logs and tests must include: 

 Deviation checks. 

 Before and upon installation of the surface casing: 

- Resistivity, spontaneous potential, and caliper logs 

before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented. 

 Before and upon installation of the long string casing: 

- Resistivity, spontaneous potential, porosity, caliper, 

gamma ray, fracture finder logs, and any other logs 

the Director requires before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented. 

 A series of mechanical integrity tests, which may 

include: 

- A pressure test with liquid or gas; 

- A tracer survey such as oxygen-activation logging; 

- A temperature or noise log; 

- A casing inspection log; 

 Any alternative methods that are required by and/or 

approved of by the Director. 

Take whole cores or sidewall cores of the injection zone 

and confining system and formation fluid samples from 

the injection zone(s), and submit to the Director a 

detailed report prepared by a log analyst that includes: 

well log analyses, core analyses, and formation fluid 

sample information. 

Record fluid temperature, pH, conductivity, reservoir 

pressure, and static fluid level of the injection zone(s). 

Determine or calculate injection and confining zone(s) 

fracture pressure; physical and chemical characteristics 

of the injection and confining zone(s) and formation fluids 

in the injection zone(s). 

Conduct pressure fall-off test and a pump test or 

injectivity tests upon completion, but prior to operation, to 

verify hydrogeologic characteristics of the injection 

zone(s). 

Provide the Director with the opportunity to witness all 

logging and testing. Submit a schedule of such activities 

to the Director 30 days prior to conducting the first test. 

Operating Requirements

§146.88 Injection well operating requirements. 173-218-115 (1). Permit required; 

173-218-115 (2). Permit application; 

173-218-115 (4). Permit terms and conditions. 

Ensure that injection pressure does not exceed 90 Each operating requirement in the federal regulations is 

percent of the fracture pressure of the injection zone(s) not specifically mentioned in 173-218-115. Operators 

so as to ensure that the injection does not initiate new are required to be in compliance with all permit 

fractures or propagate existing fractures in the injection conditions and operations cannot endanger USDWs. 
D-7

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

zone(s). All stimulation must be approved by the Director 

as part of the permit application and incorporated into the 

permit. 

Injection between the outermost casing protecting 

USDWs and the well bore is prohibited. 

Fill the annulus between the tubing and the long string 

casing with a non-corrosive fluid approved by the 

Director. Maintain on the annulus a pressure that 

exceeds the operating injection pressure, unless the 

Director determines otherwise. 

Maintain mechanical integrity of the injection well at all 

times, other than during periods of well workover 

approved by the Director. 

Install and use: 

 Continuous recording devices to monitor: the injection 

pressure; the rate, volume and/or mass, and 

temperature of the CO2 stream; and the pressure on 

the annulus between the tubing and the long string 

casing and annulus fluid volume; and 

 Alarms and automatic surface shut-off systems or, at 

the discretion of the Director, down-hole shut-off 

systems (e.g., automatic shut-off check valves) for 

onshore wells or, other mechanical devices that 

provide equivalent protection; and 

 Alarms and automatic down-hole shut-off systems for 

wells located offshore but within State territorial waters, 

designed to alert the operator and shut-in the well 

when operating parameters diverge beyond permitted 

ranges. 

If a shutdown is triggered or a loss of mechanical integrity 

is discovered, immediately investigate and identify as 

expeditiously as possible the cause of the shutoff. If, 

upon such investigation, the well appears to be lacking 

mechanical integrity: 

 Immediately cease injection; 

 Take all steps reasonably necessary to determine 

whether there may have been a release of the injected 

CO2 stream or formation fluids into any unauthorized 

zone; 

 Notify the Director within 24 hours; 

 Restore and demonstrate mechanical integrity to the 

satisfaction of the Director prior to resuming injection; 

 Notify Director when injection is expected to resume. 

The WAC requires operator to use all known, available 

and reasonable methods of prevention, control and 

treatment to remove contaminants, such as sulfur 

compounds and other contaminants, from the injected 

CO2. Geologic sequestration of carbon dioxide shall not 

be used for the disposal of non-CO2 contaminants that 

can be removed with known treatment technologies. 

[WAC 173-218-115 (1) and (4)]

The maximum allowed injection pressure shall be no 

greater than eighty percent of the formation fracture 

pressure as determined by a mini-frac injection test or 

multiple-stage, minimum threshold fracture injection test 

or other method approved by the department. The 

geologic containment system shall not be subjected to 

injection pressures in excess of the calculated fracture 

pressure even for short periods of time. Higher operating 

pressures may only be allowed if approved in writing by 

the department. 

[WAC 173-218-115 (2)] 

Mechanical Integrity

§146.89 Mechanical integrity. 173-218-155 (2). Permit application; 

173-218-115 (4). Permit terms and conditions. 

A Class VI well has mechanical integrity if there is no Permit applications must include a well casing, 

significant leak in the casing, tubing, or packer; and there cementing, and integrity testing program. 

is no significant fluid movement into a USDW through [WAC 173-218-115 (2)] 

channels adjacent to the injection well bore. 

Wells shall be periodically tested to assess their 

To evaluate the absence of significant leaks, following an structural integrity. Annual tests shall include Wireline 

initial annulus pressure test, continuously monitor surveys for casing integrity/corrosion assessment and 

injection pressure, rate, injected volumes; pressure on other appropriate tests. An injection well casing pressure 

the annulus between tubing and long-string casing; and test must be conducted prior to use and retested at least 
D-8

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

annulus fluid volume. once prior to each permit renewal or when casing 

 integrity/corrosion assessments identify risks. Any 

At least once per year, use an approved tracer survey or finding of inadequate structural integrity shall be 

temperature or noise log to determine the absence of reported to the department within twenty-four hours. 

significant fluid movement. [WAC 173-218-115 (4)] 

 

If required by the Director, the owner or operator must 

run a casing inspection log to determine the presence or 

absence of corrosion in the long-string casing. 

The Director may require additional or alternative tests to 

evaluate mechanical integrity. 

To obtain approval for a new mechanical integrity test, 

the Director must submit a written request to the 

Administrator and the Administrator may approve the 

request. Any alternate method approved by the 

Administrator will be published in the Federal Register

and may be used in all States. 

The owner or operator and the Director must apply 

methods and standards generally accepted in the 

industry. When the owner or operator reports the results 

of mechanical integrity tests to the Director, he/she shall 

include a description of the test(s) and the method(s) 

used. In making his/her evaluation, the Director must 

review monitoring and other test data submitted since the 

previous evaluation. 

Testing and Monitoring Requirements

§146.90 Testing and monitoring requirements. 173-218-115 (2). Permit application; 

173-218-115 (4). Permit terms and conditions. 

Testing and monitoring must, at a minimum, include: The WAC 173-218-155 lists several types of monitoring 

 Analysis of CO2 stream with sufficient frequency to plans that must be submitted with the permit application. 

yield data representative of its chemical and physical Monitoring plans similar to the federal requirements are 

characteristics; included in the WAC. Additional monitoring requirements 

 Installation and use of continuous recording devices to are listed below: 

monitor injection pressure, rate, and volume; the  A corrosion monitoring and prevention plan for all 

pressure on the annulus between the tubing and the wells and surface facilities. 

long string casing; and the annulus fluid volume added;  A leak detection and monitoring plan for all wells and 

 Corrosion monitoring of the well materials for loss of surface facilities, that define the threshold for 

mass, thickness, cracking, pitting, and other signs of determining that a leak has occurred and shall 

corrosion must be performed on a quarterly basis to address: identification of any failure of the 

ensure that the well components meet the minimum containment system; identification of release to the 

standards for material strength and performance by atmosphere; identification of degradation of any 

analyzing coupons, routing the CO2 stream through a ground water or surface water resources; and 

loop; or using an alternative method approved by the identification of migration of CO2 or other 

Director. contaminants into any overlying oil and natural gas 

 Periodic monitoring of the ground water quality and reservoirs. 

geochemical changes above the confining zone(s) 

through the confining zone(s) or additional zones. A risk assessment that identifies and quantifies hazards, 

 A demonstration of external mechanical integrity at probabilities, features, events and processes that might 

least once per year until the injection well is plugged; result in undesirable impacts to public health and the 

and, if required by the Director, a casing inspection log; environment is required. 

 A pressure fall-off test at least once every five years; 

 Testing and monitoring to track the extent of the CO2 A mitigation and remediation plan that identifies trigger 

plume and the presence or absence of elevated thresholds and corrective actions to be taken prior to a 

pressure (e.g., the pressure front) by using: containment system failure, if ground water quality in the 

- Direct methods in the injection zone(s); and, monitoring zone or above is degraded, or if carbon 

- Indirect methods, unless the Director determines that dioxide is released to the atmosphere. 

such methods are not appropriate; [WAC 173-218-115 (2)] 
D-9

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 









The Director may require surface air monitoring and/or 

soil gas monitoring. 

Any additional monitoring, as required by the Director 

Review the testing and monitoring plan at least once 

every five years. Amended plans or demonstrations 

shall be submitted to the Director within one year of an 

AoR reevaluation, after any significant changes to the 

facility, or when required by the Director. 

A quality assurance and surveillance plan. 

Monitoring for geologic sequestration projects are similar 

to the federal requirements. 

[WAC 173-218-115 (4)] 

Reporting Requirements 

§146.91 Reporting requirements. 173-218-115 (4). Permit terms and conditions.

The owner or operator must, at a minimum, provide the 

following reports to the Director, for each permitted Class 

VI well: 

Semi-annual reports containing: 

 Any changes to the physical, chemical, and other 

relevant characteristics of the CO2 stream from the 

proposed operating data; 

 Monthly average, maximum, and minimum values for 

injection pressure, flow rate and volume, and annular 

pressure; 

 A description of any event that exceeds operating 

parameters for annulus pressure or injection pressure 

specified in the permit; 

 A description of any event which triggers a shut-off 

device required and the response taken; 

 The monthly volume and/or mass of the CO2 stream 

injected over the reporting period and the volume 

injected cumulatively over the life of the project; 

 Monthly annulus fluid volume added; and 

 The results of monitoring prescribed. 

Report, within 30 days, the results of: 

 Periodic tests of mechanical integrity; 

 Any well workover; and, 

 Any other test of the injection well conducted by the 

permittee if required by the Director. 

Report, within 24 hours of: 

 Any evidence that the injected CO2 stream or 

associated pressure front may cause an endangerment 

to a USDW; 

 Any noncompliance with a permit condition, or 

malfunction of the injection system, which may cause 

fluid migration into or between USDWs; 

 Any triggering of a shut-off system (i.e., down-hole or 

at the surface); 

 Any failure to maintain mechanical integrity; or. 

 Any release of CO2 to the atmosphere or biosphere. 

Owners or operators must notify the Director in writing 30 

days in advance of: 

 Any planned well workover; 

 Any planned stimulation activities, other than 

stimulation for formation testing conducted under 

§146.82; and 

 Any other planned test of the injection well conducted 

by the permittee. 

The reporting requirements in WAC include quarterly 

and annual reports. The reports include operational 

information and updates of modeling and finical 

assurance information. The specific requirements are 

discussed below. 

Quarterly reports shall be submitted to the department of 

ecology that include the following: 

 Physical, chemical and other relevant characterization 

of the injected fluids; 

 Monthly average, maximum and minimum values for 

injection pressure, flow rate, volume injected and 

annular pressure; 

 Updated data for modeling that will project and/or 

establish the spatial distribution of CO2 in the 

subsurface; 

 Results from monitoring zone leak detection; 

 Results from any other tests/work completed during 

the reporting period, such as mechanical integrity 

tests, geophysical surveys, acoustic monitoring, well 

repairs, etc. 

[WAC 173-218-115 (4)] 

Annual reports shall be submitted to the department that 

include: 

 A summary of the data collected throughout the year, 

including any trends, observations, predictions as well 

as calculated spatial distribution of injected CO2; 

 List of all noncompliance with the permit along with an 

explanation of the cause(s) and subsequent remedial 

measures taken; 

 Updated modeling based on the monitoring 

observations and measurements including a summary 

of calculated spatial distribution of CO2 and all other 

conditions in the subsurface necessary to establish 

the effectiveness of the geologic containment system, 

as well as a discussion of history matching and an 

assessment of the model's accuracy to date. Updated 

projections of project response and capacity based on 

operational experience, including all new geologic 

data and information; 

 Observed anomalies from predicted behavior shall be 

identified and explained; 

 Discussion of suggested changes in project 

management or suggested amendment of permit 

conditions; 

 A report on the financial assurance account which 

includes updated calculation of cost estimates for all 

closure and post-closure activities and documentation 
D-10

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

that the account is adequately funded to cover the 

Regardless of whether a State has primary enforcement calculated cost. 

responsibility, owners or operators must submit all [WAC 173-218-115 (4)] 

required reports, submittals, and notifications under 

subpart H of this part to EPA in an electronic format 

approved by EPA. 

Records shall be retained by the owner or operator as 

follows: 

 All data collected under §146.82 for Class VI permit 

applications shall be retained throughout the life of the 

geologic sequestration project and for 10 years 

following site closure. 

 Data on the nature and composition of all injected 

fluids collected pursuant to §146.90(a) shall be 

retained until 10 years after site closure. The Director 

may require the owner or operator to deliver the 

records to the Director at the conclusion of the 

retention period. 

 Monitoring data collected pursuant to §146.90(b) 

through (i) shall be retained for 10 years after it is 

collected. 

 Well plugging reports, post-injection site care data, 

including data and information used to develop the 

demonstration of the alternative post-injection site care 

timeframe, and the site closure report shall be retained 

for 10 years following site closure. 

 The Director has authority to require the owner or 

operator to retain any records required in this subpart 

for longer than 10 years after site closure. 

Well Plugging

§146.92 Injection well plugging. 

Prior to the well plugging, the owner or operator must There are no requirements for plugging a well included 

flush each Class VI injection well with a buffer fluid, in 173-218-115. 

determine bottomhole reservoir pressure, and perform a 

final external mechanical integrity test. 

Well Plugging Plan must include the following 

information: 

 Appropriate tests or measures for determining 

bottomhole reservoir pressure; 

 Appropriate testing methods to ensure external 

mechanical integrity; 

 The type and number of plugs to be used; 

 The placement of each plug, including the elevation of 

the top and bottom of each plug; 

 The type, grade, and quantity of material to be used in 

plugging. The material must be compatible with the 

carbon dioxide stream; and 

 The method of placement of the plugs. 

Notice of intent to plug. 

The owner or operator must notify the Director in writing 

at least 60 days before plugging of a well. At this time, if 

any changes have been made to the original well 

plugging plan, the owner or operator must also provide 

the revised well plugging plan. The Director may allow for 

a shorter notice period. Any amendments to the injection 

well plugging plan must be approved by the Director, 

must be incorporated into the permit, and are subject to 
D-11

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

the permit modification requirements at §§144.39 or 

144.41 of this chapter, as appropriate. 

Plugging report. 

Within 60 days after plugging, the owner or operator must 

submit a plugging report to the Director. The report must 

be certified as accurate by the owner or operator and by 

the person who performed the plugging operation (if 

other than the owner or operator.) The owner or operator 

shall retain the well plugging report for 10 years following 

site closure.

Post-injection Site Care

§146.93 Post-injection site care and site closure. 173-218-115 (5). Closure;

173-218-115 (6) Post-closure activities. 

Part of the permit application, includes the following: The federal regulations prescribe requirements for post-

 Pressure differential between pre-injection and 

predicted post-injection pressures in injection zone(s); 

 Predicted position of the CO2 plume and associated 

pressure front at site closure; 

 Description of post-injection monitoring location, 

injection site care (PISC). The WAC does not discuss 

what the PISC will include but it does specify when 

closure must begin. It does not therefore specify a PISC 

time frame (nor a means to determine an alternative 

time frame). 

methods, and proposed frequency; and 

 A proposed schedule for submitting post-injection site 

care monitoring results to the Director. 

 The duration of the post-injection site care timeframe 

and, if approved by the Director, the demonstration of 

the alternative post-injection site care timeframe. 

Upon cessation of injection, submit an amended plan or 

demonstrate to the Director no amendment is needed. 

May modify and resubmit within 30 days of such change. 

At the Director's discretion, demonstrate during the 

permitting process that an alternative post-injection site 

care timeframe is appropriate and ensures nonendangerment of USDWs. The demonstration must be 

based on site-specific information, including the results of 

site-specific computational modeling; the predicted 

timeframe for pressure decline; the predicted rate of CO2 

plume migration; site-specific chemical processes that 

will result in CO2 trapping; the predicted rate of CO2 

trapping; characterization of the confining zone(s); 

laboratory analyses or studies to verify the information on 

trapping; the presence of potential conduits for fluid 

movement and the quality of abandoned well plugs within 

the AoR; the distance between the injection zone and the 

USDWs above and/or below the injection zone; and any 

additional site-specific factors determined by the Director. 

The demonstration must meet the criteria at 

§146.93(c)(2) for ensuring the quality and accuracy of the 

data and models on which the demonstration is based. 

Monitor the site following the cessation of injection to 

show the position of the CO2 plume and pressure front 

and demonstrate that USDWs are not being endangered. 

 Continue to conduct monitoring as specified in the 

Director-approved plan for at least 50 years following 

the cessation of injection or for the duration of the 

approved alternative timeframe, unless he/she makes 

a demonstration. At the Director’s discretion, the 

monitoring must continue until the project no longer 

Closure requirements are triggered if all of the project's 

carbon dioxide injections are interrupted for a period of 

one hundred eighty consecutive days. Injection project 

management may include injection and resting periods 

possibly exceeding one hundred eighty days for 

individual injection wells. The closure triggers are for the 

entire injection facility, not individual wells. The 

department may extend this one hundred eighty day 

period, in writing, upon the request of the operator, if the 

operator demonstrates that carbon dioxide injection will 

resume within a period of not more than two years. The 

operator shall review and amend the closure plan as 

needed, at a minimum the plan shall be reviewed at 

each permit renewal. Proposed amendments shall be 

effective only after approved in writing by the 

department. Approval of proposed amendments shall 

not delay the commencement of closure activities using 

the most recent approved closure plan. If the operator 

fails to begin closure, or is not able to begin closure, the 

department shall use the financial assurance account to 

begin closure activities. 

[WAC 173-218-115 (5)] 

The operator is obligated to renew and be covered 

under permit and pay all appropriate permit fees 

throughout the post-closure period. The operator shall 

continue all required monitoring and reporting 

throughout the closure and post-closure period. The 

operator shall review and amend the post-closure plan 

as needed, at a minimum the plan shall be reviewed at 

each permit renewal. 

The post-closure period shall continue until the 

department determines that modeling and monitoring 

demonstrate that conditions in the geologic containment 

system indicate that there is little or no risk of future 

environmental impacts and there is high confidence in 

the effectiveness of the containment system and related 

trapping mechanisms. The postclosure period shall be 

complete only after the operator has received written 
D-12

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

poses an endangerment to USDWs. 

Notify the Director in writing at least 120 days before site 

closure. If any changes have been made to the original 

plan, the owner or operator must also provide the revised 

plan. The Director may allow for a shorter notice period. 

After the Director has authorized site closure, plug all 

monitoring wells in a way which will not allow movement 

of injection or formation fluids that endangers a USDW. 

Submit a site closure report to the Director within 90 days 

of site closure, which must be retained at a location 

chosen by the Director for 10 years. Report includes: 

 Documentation of appropriate injection and monitoring 

well plugging. Provide a copy of a survey plat; 

 Documentation of appropriate notification and 

information to such State, local and Tribal authorities 

that have authority over drilling activities; and 

 Records reflecting the nature, composition, and volume 

of the CO2 stream. 

Record a notation on the deed to the facility property that 

will in perpetuity provide any potential purchaser: 

 The fact that land has been used to sequester CO2; 

 The name of the agency or authority with which the 

survey plat was filed and the address of the EPA 

Regional Office to which it was submitted; and 

 Volume of fluid injected, the injection zone (s) it was 

injected, and the period over which injection occurred. 

Retain for 10 years following site closure, records 

collected during post-injection site care period. Deliver 

the records to the Director at the end of the retention 

period. Retain records at location chosen by the Director. 

approval from the department. If the operator fails to or 

is not able to continue the post-closure activities as 

required, the department shall use the financial 

assurance account to complete post-closure activities. 

Any funds remaining in the financial assurance account 

shall be released to the operator upon the department's 

approval of the completion of the post-closure period. 

[WAC 173-218-115 (6)] 

Emergency and Remedial Response

§146.94 Emergency and remedial response. 173-218-115 (8). Mitigation and remediation.

As part of the permit application, the owner or operator Similar to the federal requirements applicants are 

must provide the Director with an emergency and required to submit a mitigation and remediation plan in 

remedial response plan that describes actions the owner WAC 173-218-115 (2). Each project must develop a 

or operator must take to address movement of the mitigation and remediation plan that identifies trigger 

injection or formation fluids that may cause an thresholds and corrective actions to be taken if the 

endangerment to a USDW during construction, operation, containment system fails, if water quality outside the 

and post-injection site care periods. geologic containment system is degraded, if carbon 

dioxide is released to the atmosphere or if any other 

If evidence shows potential endangerment of USDWs, factor poses an unacceptable risk to public health or the 

the owner or operator should cease injection; notify the environment. 

Director within 24 hours; implement the emergency and 

remedial response plan. Prior to re-commencing The mitigation and remediation plan shall: 

injection, demonstrate to the Director non-endangerment  Define leakage (i.e., trigger threshold), leak detection 

to USDWs. and identification; 

  Address caprock and spill-point leaks; 

Periodically review the emergency and remedial  Address well bore leaks from project wells or response plan at least once every five years. Amended previously unidentified wells; 

plans or demonstrations shall be submitted to the  Identify immediate responses to protect public health, Director within one year of an AoR reevaluation; following safety and the environment; any significant changes to the facility; or when required  Provide a detailed list of notifications and surveys; by the Director.As part of the permit application, the 

owner or operator must provide the Director with an 

emergency and remedial response plan that describes 

 Address remedial measures such as: Well repairs, 

reduced injection pressure, reservoir or formation 

pressure, creation of a pressure barrier through 
D-13

Final Class VI Rule 

(pre-publication version signed by the Administrator on 

November 22, 2010)

Washington Final Rule1

(Chapter 173-218-030 and 173-218-115 Washington 

Administrative Code. Last updated June 19, 2008) 

actions the owner or operator must take to address increased pressure above geologic containment 

movement of the injection or formation fluids that may system, interception, recovery and reinjection of CO2 

cause an endangerment to a USDW during construction, or the removal of injected materials; 

operation, and post-injection site care periods.  Address redefining the geologic containment system 

or closure and abandonment of the sequestration 

If evidence shows potential endangerment of USDWs, project. 

the owner or operator should cease injection; notify the 

Director within 24 hours; implement the emergency and The geologic specific requirements do not address 

remedial response plan. Prior to re-commencing procedural requirements in the event of endangerment. 

injection, demonstrate to the Director non-endangerment [173-218-115 (8)] 

to USDWs. 

 

 Periodically review the emergency and remedial 

response plan at least once every five years. Amended 

plans or demonstrations shall be submitted to the 

Director within one year of an AoR reevaluation; 

following any significant changes to the facility; or 

when required by the Director. 
E-1

Appendix E

Wyoming Department of Environmental Quality Water Quality Rules and Regulations

Chapter 24: Class VI Injection Wells and Facilities

Underground Injection Control Program

Preliminary Comparison with the Final Class VI Rule

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

Applicability

§146.81 - Applicability Section 3. Applicability

• This rule applies to any wells used to inject carbon 

dioxide specifically for the purpose of geologic 

sequestration. 

• Also applies to owners or operators of permit- or ruleauthorized Class I, Class II, or Class V experimental 

carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well 

or wells. 

Applicability in this state regulation appears similar to the 

federal rule. An additional requirement is noted below. 

These regulations do not apply to the injection of any 

carbon dioxide stream that meets the definition of a 

hazardous waste.

§146.81 (d) - Applicability: Definitions Section 2. Definitions. The following definitions 

supplement those definitions contained in Section 

35-11-103 of the Wyoming Environmental Quality 

Act.

Geologic sequestration (See section 35-11-103(c) of the Wyoming 

Environmental Quality Act for definitions of geologic 

sequestration, geologic sequestration site, and geologic 

sequestration facilities.)

(GS) means the long-term 

containment of a gaseous, liquid, or supercritical carbon 

dioxide stream in subsurface geologic formations. This 

term does not apply to carbon dioxide capture or 

transport.

Geologic sequestration project “Geologic sequestration project” means an injection well 

or wells used to emplace a carbon dioxide stream into 

an injection zone for geologic sequestration. It includes 

the subsurface three-dimensional extent of the carbon 

dioxide plume, associated pressure front, and displaced 

brine, as well as the surface area above that delineated 

region.

means an injection well or 

wells used to emplace a carbon dioxide stream beneath 

the lowermost formation containing a USDW; or, wells 

used for geologic sequestration of carbon dioxide that 

have been granted a waiver of the injection depth 

requirements pursuant to requirements at §146.95; or, 

wells used for geologic sequestration of carbon dioxide 

that have received an expansion to the areal extent of an 

existing Class II enhanced oil recovery or enhanced gas 

recovery aquifer exemption pursuant to §§146.4 of this 

chapter and 144.7(d). It includes the subsurface threedimensional extent of the carbon dioxide plume, 

associated area of elevated pressure, and displaced 

fluids, as well as the surface area above that delineated 

region.

Site closure “Site closure” means the point/time, as determined by 

the director, at which the owner or operator of a geologic 

sequestration project is released from post-injection site 

care responsibilities.

means the point/time, as determined by the 

Director following the requirements under §146.93, at 

which the owner or operator of a geologic sequestration 

site is released from post-injection site care 

responsibilities.

Post-injection site care “Post-injection site care” means monitoring, 

measurement, verification, and other actions (including 

corrective action) following cessation of injection, as 

required under Section 16 of this chapter.

means appropriate monitoring 

and other actions (including corrective action) needed 

following cessation of injection to ensure that USDWs are 

not endangered, as required under §146.93.

Permit Conditions

§146.82 Required Class VI permit information. Section 5. Permit application.

Prior to the issuance of a construction or conversion The permit application conditions in this state regulation 
E-2

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

permit, the owner or operator must submit the following:

• Information required in 40 CFR 144.31 (e)(1) - (6); 

• Map showing the injection well, the applicable AoR, 

and faults, if known or suspected;

• Information on the geologic structure and 

hydrogeologic properties; 

• Tabulation of all wells within the AoR which penetrate 

the injection or confining zone(s); 

• Maps and stratigraphic cross sections indicating all 

USDWs, water wells and springs within the AoR, their 

positions relative to the injection zone(s), and the 

direction of water movement, where known; 

• Baseline geochemical data on subsurface formations;

• Proposed operating data; 

• Proposed pre-operational formation testing program; 

• Proposed stimulation program; 

• Proposed procedure to conduct injection operation; 

• Schematics of the construction details of the well; 

• Injection well construction procedures; 

• Proposed AoR and corrective action plan; 

• A demonstration of financial responsibility; 

• Proposed testing and monitoring plan; 

• Proposed injection well plugging plan; 

• Proposed post-injection site care and site closure plan; 

• Proposed alternative post-injection site care timeframe;

• Proposed emergency and remedial response plan; 

• A list of contacts identified to be within the AoR; and

• Any other information requested by the Director. 

The Director shall notify, in writing, any States, Tribes, or 

Territories within the AoR of the Class VI project of the 

permit application. 

Prior to granting approval for the operation of a Class VI 

well, the Director shall consider the following: 

• Final AoR based on modeling, using data obtained 

during logging and testing of the well and the 

formation; 

• Any relevant updates to the information on the geologic 

structure and hydrogeologic properties of the proposed 

storage site and overlying formations; 

• Information on the compatibility of the carbon dioxide 

stream with fluids in the injection zone(s) and minerals 

in both the injection and the confining zone(s); 

• Results of the formation testing program;

• Final injection well construction procedures;

• Status of corrective action on wells in the AoR; 

• All available logging and testing program data on the 

well;

• A demonstration of mechanical integrity;

• Any updates to the any of the plans; and

• Any other information requested by the Director.

Owners or operators seeking a waiver of the requirement 

to inject below the lowermost USDW submit a 

supplemental report.

appear to similar elements as the federal rule, with 

greater detail specified in some elements. See below for 

details.

(i) A brief description of the nature of the business and 

the activities to be conducted that require the applicant 

to obtain a permit under this chapter.

(ii) The name, address and telephone number of the 

operator, and the operator's ownership status and status 

as a Federal, State, private, public or other entity.

(iii) Up to four SIC (Standard Industrial Classification) 

codes which best reflect the principal products or 

services provided by the facility.

(iv) The name, address, and telephone number of the 

facility. Additionally, the location of the geologic 

sequestration project shall be identified by section, 

township, range and county, noting which, if any, 

sections include Indian lands.

(v) Within the area of review, a listing and status of all 

permits or construction approvals associated with the 

geologic sequestration project received or applied for by 

the applicant under any of the following programs:

(A) Hazardous Waste Management under the Resource 

Conservation and Recovery Act (RCRA).

(B) UIC Program under the Safe Drinking Water Act.

(C) NPDES under the Clean Water Act.

(D) Prevention of Significant Deterioration (PSD) 

program under the Clean Air Act.

(E) National Emissions Standards for Hazardous Air 

Pollutants (NESHAPs) pre-construction approval under 

the Clean Air Act.

(F) Dredge and fill permits under section 404 of the 

Clean Water Act.

(G) Within the area of review, a list of other relevant 

permits, whether federal or state, associated with the 

geologic sequestration project that the applicant has 

been required to obtain, such as construction permits. 

This includes a statement as to whether or not

the facility is within a state approved water quality 

management plan area, a state approved wellhead 

protection area or a state approved source water 

protection area.

(vii) A map delineating the area of review based upon 

modeling, using all available data including data 

available from any logging and testing of wells within 

and adjacent to the area of review;

(A) A Class VI area of review shall never be less than 

the area of potentially affected groundwater.

(B) All areas of review shall be legally described by 

township, range and section to the nearest ten (10) 

acres as described under the general land survey 

system.

(viii) A description of the general geology of the area to 

be affected by the injection of carbon dioxide including 

geochemistry, structure and faulting, fracturing and 

seals, and stratigraphy and lithology including 

petrophysical attributes. The description shall also 

include sufficient information on the geologic structure 
E-3

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

and reservoir properties of the proposed storage site 

and overlying formations, including:

(A) Isopach maps of the proposed injection and 

confining zone(s), a structural contour map aligned with 

the top of the proposed injection zone, and at least two 

geologic cross sections of the area of review reasonably 

perpendicular to each other and showing the geologic 

formations from the surface to total depth;

(B) Location, orientation, and properties of known or 

suspected faults and fractures that may transect the 

confining zone(s) in the area of review and a 

determination that they would not interfere with 

containment;

(C) Information on seismic history that have affected the 

proposed area of review including knowledge of 

previous seismic events and history of these events, the

presence and depth of seismic sources, and a 

determination that the seismicity would not compromise 

containment;

(D) Data sufficient to demonstrate the effectiveness of 

the injection and confining zone(s), including data on the 

depth, areal extent, thickness, mineralogy, porosity, 

vertical permeability and reservoir pressure of the 

injection and confining zone(s) within the area of review, 

and geologic changes based on field data which may 

include geologic cores, outcrop data, seismic surveys, 

well logs, capillary pressure tests and names and 

lithologic descriptions;

(E) Geomechanical information on fractures, stress, 

ductility, rock strength, and in situ fluid pressures within 

the confining zone; and

(F) Geologic and topographic maps and cross sections 

illustrating regional geology, hydrogeology, and the 

geologic structure of the local area.

(ix) A compilation of all wells and other drill holes within, 

and adjacent (within 1 mile) to the area of review. Such 

data must include a description of each well and drill 

hole type, construction, date drilled, location, depth, 

record of plugging and/or completion, and any additional 

information the administrator may require.

(B) Applicants shall perform mapping with sufficient 

resolution as to make a comprehensive effort to identify 

wells that are not in the public record using aerial 

photography, aerial survey, physical traverse, or other 

methods acceptable to the administrator.

(x) Maps and stratigraphic cross sections indicating the 

general vertical and lateral limits of all USDWs, the 

location of water wells and springs within the area of 

review, their positions relative to the injection zone(s), 

and the direction of water movement, where known;

(xi) A characterization of the injection zone and aquifers 

above and below the injection zone which may be 

affected, including applicable pressure and fluid 

chemistry data to describe the projected effects of 

injection activities, and background water quality data 

which will facilitate the classification of any groundwaters 

which may be affected by the proposed discharge. This 

must include information necessary for the division to 
E-4

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

classify the receiver and any secondarily affected 

aquifers under Chapter 8, Wyoming Water Quality Rules 

and Regulations;

(xii) Baseline geochemical data on subsurface 

formations, including all USDWs in the area of review.

(xiii) Proposed operating data:

(A) Average and maximum daily rate and volume of the 

carbon dioxide stream;

(B) Average and maximum surface injection pressure;

(C) The source of the carbon dioxide stream; and

(D) An analysis of the chemical and physical 

characteristics of the carbon dioxide stream and any 

other substance(s) proposed for inclusion in the injectate 

stream; and

(E) Anticipated duration of the proposed injection 

period(s). 

(xiv) The compatibility of the carbon dioxide stream with 

fluids in the injection zone and minerals in both the 

injection and the confining zone(s), based on the results 

of the formation testing program, and with the materials 

used to construct the well;

(xv) An assessment of the impact to fluid resources, on 

subsurface structures and the surface of lands that may 

reasonably be expected to be impacted, and the 

measures required to mitigate such impacts;

(xvi) Proposed formation testing program to obtain an 

analysis of the chemical and physical characteristics of 

the injection zone and confining zone;

(xvii) Proposed stimulation program and a determination 

that stimulation will not compromise containment;

(xviii) The results of the formation testing program as 

required in paragraph (xvi) of this section;

(xix) Proposed procedure to outline steps necessary to 

conduct injection operation;

(xx) A wellbore schematic of the subsurface construction 

details and surface wellhead construction of the injection 

and monitoring wells;

(xxxi) A site and facilities description, including a 

description of the proposed geologic sequestration 

facilities;

(xxxii) Documentation sufficient to demonstrate that the 

applicant has all legal rights, including but not limited to 

the right to surface use, necessary to sequester carbon 

dioxide and associated constituents;

(xxxiii) Proof of notice to surface owners, mineral 

claimants, mineral owners, lessees and other owners of 

record of subsurface interests as to the contents of such 

notice. Notice requirements shall at a minimum require:

(A) The publishing of notice of the application in a 

newspaper of general circulation in each county of the 

proposed operation at weekly intervals for four (4) 

consecutive weeks; and

(B) A copy of the notice shall also be mailed to all 

surface owners, mineral claimants, mineral owners, 

lessees and other owners of record of subsurface 

interests which are located within one (1) mile of the 

proposed boundary of the geologic sequestration site as 

defined by W.S. 35-11-103(c)(xxi).
E-5

Final Class VI Rule

(pre-publication version signed by the Administrator on 

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

November 22, 2010) of September 17, 2010.)

The state rule appears to have no waiver provisions.

Geologic Site Characterization

§146.83 Minimum criteria for siting. Section 7. Minimum criteria for siting Class VI wells.

A geologic system comprises: 

• An injection zone(s) of sufficient areal extent, 

thickness, porosity, and permeability to receive the 

total anticipated volume of the carbon dioxide stream.

• Confining zone(s) free of transmissive faults or 

fractures and of sufficient areal extent and integrity to 

contain the injected carbon dioxide stream and 

displaced formation fluids and allow injection at 

proposed maximum pressures and volumes without 

initiating or propagating fractures in the confining 

zone(s).

• At the Director’s discretion, additional zones that will 

impede vertical fluid movement, are free of faults and 

fractures that may interfere with containment, allow for 

pressure dissipation, and provide additional 

opportunities for monitoring, mitigation, and 

remediation.

The permit application conditions in this state regulation 

appear to contain similar elements as the federal rule, 

with greater detail specified. See below for details.

(ii) A confining zone(s) that is free of transmissive faults 

or fractures and of sufficient areal extent and integrity to 

contain the injected carbon dioxide stream and 

displaced formation fluids and allow injection at 

proposed maximum pressures and volumes without 

initiating or propagating fractures in the confining 

zone(s) or causing non-transmissive faults to become 

transmissive.

(b) Owners or operators of Class VI wells must identify 

and characterize additional zones, if they exist, that will 

impede vertical fluid movement, allow for pressure 

dissipation, and provide additional opportunities for 

monitoring, mitigation and remediation. Vertical faults 

and fractures that transect these zones must be 

identified.

AoR and Corrective Action

§146.84 AoR and corrective action. Section 8. Area of review delineation and corrective 

action.

The AoR is the region surrounding the geologic 

sequestration project where USDWs may be endangered 

by the injection activity. The AoR is delineated using

computational modeling that accounts for the physical 

and chemical properties of all phases of the injected CO2 

stream and is based on available site characterization, 

monitoring, and operational data. 

Part of the permit application, submit a plan that includes:

• Method for delineating the AoR; 

• Description of the minimum fixed frequency, not to 

exceed five years, to reevaluate the AoR; monitoring 

and operational conditions that would warrant an 

earlier reevaluation; how monitoring and operational 

data will be used to inform a reevaluation; how 

corrective action will be conducted; how corrective 

action will be adjusted if there are changes in the AoR; 

and how site access will be guaranteed for future 

corrective action.

To delineate the AoR and identify all wells that require 

corrective action, perform the following: 

• Predict, using existing site characterization, monitoring 

and operational data, and computational modeling, the 

projected lateral and vertical migration of the CO2 

plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient 

to cause the movement of injected fluids or formation 

fluids into a USDW are no longer present, or until the 

The AoR and Corrective Action conditions in this state 

regulation appear to contain similar elements as the 

federal rule, with greater detail specified. See below for 

details.

 (i) The owner or operator will re-evaluate the area of 

review at least every two (2) years during the operational 

life of the facility, and then no less frequently than every 

five (5) years through the post-injection site care period 

until the geologic sequestration project is closed in 

accordance with department rules and regulations. 

(i) The method for delineating the area of review that 

meets the requirements of paragraph (c) of this section, 

including the name, version and availability of the model 

to be used, assumptions that will be made, and the site 

characterization data on which the model will be based;

(I) What corrective action will be performed prior to 

injection;

(II) What, if any, portions of the area of review will have 

corrective action addressed on a phased basis, and how 

the phasing will be determined;

(III) How corrective action will be adjusted if there are 

changes in the area of review; and

(IV) How site access will be ensured for future corrective 

action.

(B) The pressure differentials, and demonstrate that 

pressure differentials sufficient to cause the movement 

of injected fluids or formation fluids into a USDW

or to otherwise threaten human health, safety, or the 

environment will not be present (or for a fixed time 
E-6

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

end of a fixed time period as determined by the 

Director. The rule further describes the requirements of 

the model; 

• Identify all penetrations, including active and 

abandoned wells and underground mines, in the AoR 

that may penetrate the confining zone(s); and 

• Determine which abandoned wells in the AoR have 

been plugged.

At the minimum fixed frequency, not to exceed five years, 

or when monitoring and operational conditions warrant: 

• Reevaluate the AoR; 

• Identify all wells in the reevaluated AoR that require 

corrective action; 

• Perform corrective action on wells requiring corrective 

action in the reevaluated AoR; and

• Submit an amended AoR and corrective action plan or 

demonstrate to the Director through monitoring data 

and modeling results that no amendment to the AoR 

and corrective action plan is needed. 

The emergency and remedial response plan and the 

demonstration of financial responsibility must account for 

the AoR delineated, regardless of whether or not 

corrective action in the AoR is phased.

All modeling inputs and data used to support AoR 

reevaluations shall be retained for 10 years.

period as determined by the administrator);

(C) The potential need for brine removal, and;

(D) The long-term effects of pressure buildup if brine is 

not removed.

(ii) The modeling must:

(A) Be based on:

(I) Detailed geologic data available or collected to 

characterize the injection zone, confining zone and any 

additional zones; and

(II) Anticipated operating data, including injection 

pressures, rates and total volumes over the proposed 

operational life of the facility.

(B) Take into account any relevant geologic 

heterogeneities, data quality, and their possible impact 

on model predictions; and

(C) Consider potential migration through faults, 

fractures, and artificial penetrations.

(iii) Using methods approved by the administrator, 

identify all penetrations, including active and abandoned 

wells and underground mines, in the area of review that 

may penetrate the confining zone. Provide a description 

of each well’s type, construction, date drilled, location, 

depth, record of plugging and/or completion, and any 

additional information the administrator may require; and

(iv) Determine which abandoned wells in the area of 

review have been plugged in a manner that prevents the 

movement of:

(A) Carbon dioxide that may endanger USDWs or 

otherwise threaten human health, safety, or the 

environment, or;

(B) Displaced formation fluids that may endanger 

USDWs or otherwise threaten human health, safety, or 

the environment.

(d) Owners or operators of Class VI wells must perform 

corrective action on all wells in the area of review that 

are determined to need corrective action using methods 

necessary to prevent the movement of fluid into or 

between USDWs including use of corrosion resistant 

materials, where appropriate.

(e) At a fixed frequency, not to exceed two (2) years 

during the operational life of the facility, or five (5) years 

during the post-injection site care period (until the 

geologic sequestration project is closed) as specified in 

the area of review and corrective action plan, or when 

monitoring and operational conditions warrant, owners 

or operators must:

(iii) Perform corrective action on wells requiring 

corrective action in the reevaluated area of review in the 

same manner specified in paragraph (d) of this section; 

and

(iv) Submit an amended area of review and corrective 

action plan or demonstrate to the administrator through 

monitoring data and modeling results that no change to 

the area of review and corrective action plan is needed.

(f) The emergency and remedial response plan (as 

required by Section 17) and a demonstration of financial 

responsibility (as described by Section 18) must account 

for the entire area of review [as modified], regardless of 
E-7

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

whether or not corrective action in the area of review is 

phased.

Financial Responsibility

§146.85 Financial responsibility. Section 18. Financial responsibility.

The owner or operator must demonstrate and maintain 

financial responsibility as approved by the Director, until 

the Director approves the completed post-injection site 

care and site closure plan and approves site closure. The 

owner or operator may be released from a financial 

instrument in the certain circumstances.

The financial responsibility instrument(s) used must: 

• Be from the list of qualifying instruments; 

• Be sufficient to cover the cost of corrective action, 

injection well plugging, post injection site care and site 

closure, and emergency and remedial response; 

• Be sufficient to address endangerment of USDWs; and 

• Comprise protective conditions of coverage, including 

at a minimum cancellation, renewal, and continuation 

provisions, specifications on when the provider 

becomes liable in case of cancellation if there is a 

failure to renew with a new qualifying financial 

instrument, and requirements for the provider to meet a 

minimum rating, minimum capitalization, and ability to 

pass the bond rating when applicable.

Have a detailed written estimate, in current dollars, of the 

cost of performing corrective action on wells in the AoR, 

plugging the injection well(s), post-injection site care and 

site closure, and emergency and remedial response. 

• The cost estimate must be performed for each phase 

separately and must be based on the costs to the 

regulatory agency of hiring a third party. 

• During the active life of the geologic sequestration 

project, the owner or operator must adjust the cost 

estimate for inflation within 60 days prior to the 

anniversary date of the establishment of the financial 

instrument. The Director must approve this change. 

• Whenever the current cost estimate increases/ 

decreases, the face amount of the financial assurance 

instrument may be increased/reduced to the amount of 

the current cost estimate only after the receipt of 

written approval from the Director. 

Notify the Director by certified mail of adverse financial 

conditions that may affect the ability to carry out injection 

well plugging and post-injection site care and site 

closure. 

Provide an adjustment of the cost estimate to the Director 

within 60 days of notification by the Director, if the 

Director determines during the annual evaluation of the 

qualifying financial responsibility instrument(s) that the 

most recent demonstration is no longer adequate to 

cover the cost of corrective action, injection well plugging, 

post-injection site care and site closure, and emergency 

and remedial response.

The financial responsibility conditions in this state 

regulation cover the same activities but appear to be 

less specific regarding instruments than the federal rule. 

See below for details.

(a) The owner or operator must demonstrate and 

maintain financial responsibility and resources for 

corrective action (that meets the requirements of Section 

8), injection well plugging (that meets the requirements 

of Section 15), post-injection site care and site closure 

(that meets the requirements of Section 16), and 

emergency and remedial response (that meets the 

requirements of Section 17) in a manner prescribed by 

the Director until:

(i) The administrator receives the well plugging report 

identified in Section 15(d), or the post-injection site care 

and site closure plan requirements are met, as 

appropriate; or

(ii) The Director authorizes site closure.

(b) The owner or operator must provide to the 

Administrator annual written updates of adjustments to 

the cost estimate to account for any amendments to the 

area of review and corrective action plan (Section 8), the 

injection well plugging plan (Section 15), and the postinjection site care and site closure plan (Section 16).

(c) The owner or operator must notify the administrator 

of adverse financial conditions that may affect the ability 

to carry out injection well plugging and post-injection site 

care and site closure.

(d) The operator must provide an adjustment of the cost 

estimate to the administrator if the administrator has 

reason to believe that the most recent demonstration is 

no longer adequate to cover the cost of injection well 

plugging (as required by Section 15) and post-injection 

site care and site closure (as required by Section 16).
E-8

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

The Director must approve the use and length of pay-inperiods for trust funds or escrow accounts. 

Construction Requirements

§146.86 Injection well construction requirements. Section 9. Construction and operation standards for 

Class VI wells

All materials (e.g. casing and cementing materials, tubing 

and packer materials, cement and cement additives) 

used in construction must be compatible with fluids with 

which the materials may be expected to come into 

contact and must meet or exceed standards.

Casing and Cementing of Class VI Wells.

• The owner or operator must provide the quantitative 

information requested in the rule.

• Surface casing must extend through the base of the 

lowermost USDW and be cemented to the surface 

through the use of a single or multiple strings of casing 

and cement. 

• At least one long string casing, using a sufficient 

number of centralizers, must extend to the injection 

zone and must be cemented by circulating cement to 

the surface in one or more stages. 

• Circulation of cement may be accomplished by staging. 

The Director may approve an alternative method.

Tubing and Packer.

• All owners or operators must inject fluids through 

tubing with a packer set at a depth opposite a 

cemented interval at the location approved by the 

Director. 

• The owner or operator must submit the quantitative 

information requested in the rule.

The injection well construction requirements in this state 

regulation appear to contain similar elements as the 

federal rule. 

Logging, Sampling and Testing

§146.87 Logging, sampling, and testing prior to 

injection well operation.

Section 10. Logging, sampling, and testing prior to 

injection well operation.

During drilling and construction, the owner or operator 

must run appropriate logs, surveys and tests to 

determine or verify the depth, thickness, porosity, 

permeability, and lithology of, and the salinity of any 

formation fluids in all relevant geologic formations and 

then submit a descriptive report prepared by a 

knowledgeable log analyst that includes an interpretation 

of the results of such logs and tests.

At a minimum, such logs and tests must include:

• Deviation checks. 

• Before and upon installation of the surface casing:

- Resistivity, spontaneous potential, and caliper logs 

before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• Before and upon installation of the long string casing:

- Resistivity, spontaneous potential, porosity, caliper,

gamma ray, fracture finder logs, and any other logs 

The logging, sampling, and testing conditions in this 

state regulation appear to contain similar elements as 

the federal rule. 

 
E-9

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

the Director requires before the casing is installed; 

- A cement bond and variable density log, and a 

temperature log after the casing is set and 

cemented.

• A series of mechanical integrity tests, which may 

include:

- A pressure test with liquid or gas;

- A tracer survey such as oxygen-activation logging;

- A temperature or noise log;

- A casing inspection log; 

• Any alternative methods that are required by and/or 

approved of by the Director. 

Take whole cores or sidewall cores of the injection zone 

and confining system and formation fluid samples from 

the injection zone(s), and submit to the Director a 

detailed report prepared by a log analyst that includes: 

well log analyses, core analyses, and formation fluid 

sample information. 

Record fluid temperature, pH, conductivity, reservoir 

pressure, and static fluid level of the injection zone(s).

Determine or calculate injection and confining zone(s) 

fracture pressure; physical and chemical characteristics 

of the injection and confining zone(s) and formation fluids 

in the injection zone(s).

Conduct pressure fall-off test and a pump test or 

injectivity tests upon completion, but prior to operation, to 

verify hydrogeologic characteristics of the injection 

zone(s).

Provide the Director with the opportunity to witness all 

logging and testing. Submit a schedule of such activities 

to the Director 30 days prior to conducting the first test.

Operating Requirements

§146.88 Injection well operating requirements. Section 11. Injection well operating requirements.

Ensure that injection pressure does not exceed 90 

percent of the fracture pressure of the injection zone(s) 

so as to ensure that the injection does not initiate new 

fractures or propagate existing fractures in the injection 

zone(s). All stimulation must be approved by the Director 

as part of the permit application and incorporated into the 

permit.

Injection between the outermost casing protecting 

USDWs and the well bore is prohibited.

Fill the annulus between the tubing and the long string 

casing with a non-corrosive fluid approved by the 

Director. Maintain on the annulus a pressure that

exceeds the operating injection pressure, unless the 

Director determines otherwise. 

Maintain mechanical integrity of the injection well at all 

The injection well operating requirements in this state 

regulation appear to contain similar elements as the 

federal rule however the rule does not prescribe a 

specific maximum injection pressure (e.g. 90%). 

 
E-10

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

times, other than during periods of well workover 

approved by the Director.

Install and use: 

• Continuous recording devices to monitor: the injection 

pressure; the rate, volume and/or mass, and 

temperature of the CO2 stream; and the pressure on 

the annulus between the tubing and the long string 

casing and annulus fluid volume; and

• Alarms and automatic surface shut-off systems or, at 

the discretion of the Director, down-hole shut-off 

systems (e.g., automatic shut-off check valves) for 

onshore wells or, other mechanical devices that 

provide equivalent protection; and

• Alarms and automatic down-hole shut-off systems for 

wells located offshore but within State territorial waters, 

designed to alert the operator and shut-in the well 

when operating parameters diverge beyond permitted 

ranges. 

If a shutdown is triggered or a loss of mechanical integrity 

is discovered, immediately investigate and identify as 

expeditiously as possible the cause of the shutoff. If, 

upon such investigation, the well appears to be lacking 

mechanical integrity: 

• Immediately cease injection;

• Take all steps reasonably necessary to determine 

whether there may have been a release of the injected 

CO2 stream or formation fluids into any unauthorized 

zone;

• Notify the Director within 24 hours;

• Restore and demonstrate mechanical integrity to the 

satisfaction of the Director prior to resuming injection; 

• Notify Director when injection is expected to resume.

Mechanical Integrity

§146.89 Mechanical integrity. Section 12. Mechanical integrity.

A Class VI well has mechanical integrity if there is no 

significant leak in the casing, tubing, or packer; and there 

is no significant fluid movement into a USDW through 

channels adjacent to the injection well bore.

To evaluate the absence of significant leaks, following an 

initial annulus pressure test, continuously monitor 

injection pressure, rate, injected volumes; pressure on 

the annulus between tubing and long-string casing; and 

annulus fluid volume.

 

At least once per year, use an approved tracer survey or 

temperature or noise log to determine the absence of 

significant fluid movement.

 

If required by the Director, the owner or operator must 

run a casing inspection log to determine the presence or 

absence of corrosion in the long-string casing. 

The Director may require additional or alternative tests to 

evaluate mechanical integrity. 

The mechanical integrity conditions in this state 

regulation appear to contain similar elements as the 

federal rule. 
E-11

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

To obtain approval for a new mechanical integrity test, 

the Director must submit a written request to the 

Administrator and the Administrator may approve the 

request. Any alternate method approved by the 

Administrator will be published in the Federal Register

and may be used in all States. 

The owner or operator and the Director must apply 

methods and standards generally accepted in the 

industry. When the owner or operator reports the results 

of mechanical integrity tests to the Director, he/she shall 

include a description of the test(s) and the method(s) 

used. In making his/her evaluation, the Director must 

review monitoring and other test data submitted since the 

previous evaluation.

Testing and Monitoring Requirements

§146.90 Testing and monitoring requirements. Section 13. Testing and monitoring requirements.

Testing and monitoring must, at a minimum, include:

• Analysis of CO2 stream with sufficient frequency to 

yield data representative of its chemical and physical 

characteristics; 

• Installation and use of continuous recording devices to 

monitor injection pressure, rate, and volume; the 

pressure on the annulus between the tubing and the 

long string casing; and the annulus fluid volume added;

• Corrosion monitoring of the well materials for loss of 

mass, thickness, cracking, pitting, and other signs of 

corrosion must be performed on a quarterly basis to 

ensure that the well components meet the minimum 

standards for material strength and performance by 

analyzing coupons, routing the CO2 stream through a 

loop; or using an alternative method approved by the 

Director.

• Periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s) 

through the confining zone(s) or additional zones.

• A demonstration of external mechanical integrity at 

least once per year until the injection well is plugged; 

and, if required by the Director, a casing inspection log; 

• A pressure fall-off test at least once every five years;

• Testing and monitoring to track the extent of the CO2

plume and the presence or absence of elevated 

pressure (e.g., the pressure front) by using:

- Direct methods in the injection zone(s); and,

- Indirect methods, unless the Director determines that 

such methods are not appropriate;

• The Director may require surface air monitoring and/or 

soil gas monitoring. 

• Any additional monitoring, as required by the Director 

• Review the testing and monitoring plan at least once 

every five years. Amended plans or demonstrations 

shall be submitted to the Director within one year of an 

AoR reevaluation, after any significant changes to the 

facility, or when required by the Director.

• A quality assurance and surveillance plan. 

The testing and monitoring requirements in this state 

regulation appear to be less detailed and specific: they 

do not specifically address injectate monitoring, 

corrosion monitoring of the well, or specifically require 

indirect CO2 tracking methods. See below for details.

 

(i) Plans and procedures for environmental surveillance 

and excursion detection, prevention and control 

programs, including a monitoring plan to:

(A) Assess the migration of the injected carbon dioxide; 

and

(B) Insure the retention of the carbon dioxide in the 

geologic sequestration site.

(C) For purposes of this section, “excursion” shall mean 

the detection of migrating carbon dioxide at or beyond 

the boundary of the geologic sequestration site as 

defined in W.S. 35-11-103(c). 

(vi) Periodic monitoring of the reservoir fluid quality in a 

permeable and porous formation as near as practicable 

to the confining zone(s) for geochemical changes that 

may be a result of carbon dioxide or displaced formation 

fluid movement.
E-12

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

Reporting Requirements 

§146.91 Reporting requirements. Section 14. Reporting requirements.

The owner or operator must, at a minimum, provide the 

following reports to the Director, for each permitted Class 

VI well:

Semi-annual reports containing:

• Any changes to the physical, chemical, and other 

relevant characteristics of the CO2 stream from the 

proposed operating data;

• Monthly average, maximum, and minimum values for 

injection pressure, flow rate and volume, and annular 

pressure; 

• A description of any event that exceeds operating 

parameters for annulus pressure or injection pressure 

specified in the permit;

• A description of any event which triggers a shut-off 

device required and the response taken;

• The monthly volume and/or mass of the CO2 stream 

injected over the reporting period and the volume 

injected cumulatively over the life of the project;

• Monthly annulus fluid volume added; and 

• The results of monitoring prescribed.

Report, within 30 days, the results of:

• Periodic tests of mechanical integrity;

• Any well workover; and,

• Any other test of the injection well conducted by the 

permittee if required by the Director.

Report, within 24 hours of:

• Any evidence that the injected CO2 stream or 

associated pressure front may cause an endangerment 

to a USDW; 

• Any noncompliance with a permit condition, or 

malfunction of the injection system, which may cause 

fluid migration into or between USDWs;

• Any triggering of a shut-off system (i.e., down-hole or 

at the surface); 

• Any failure to maintain mechanical integrity; or.

• Any release of CO2 to the atmosphere or biosphere. 

Owners or operators must notify the Director in writing 30 

days in advance of:

• Any planned well workover; 

• Any planned stimulation activities, other than 

stimulation for formation testing conducted under 

§146.82; and

• Any other planned test of the injection well conducted 

by the permittee. 

Regardless of whether a State has primary enforcement 

responsibility, owners or operators must submit all 

required reports, submittals, and notifications under 

subpart H of this part to EPA in an electronic format 

approved by EPA.

The reporting requirements in this state regulation 

appear to contain similar elements as the federal rule. 
E-13

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

Records shall be retained by the owner or operator as 

follows: 

• All data collected under §146.82 for Class VI permit 

applications shall be retained throughout the life of the 

geologic sequestration project and for 10 years 

following site closure.

• Data on the nature and composition of all injected 

fluids collected pursuant to §146.90(a) shall be 

retained until 10 years after site closure. The Director 

may require the owner or operator to deliver the 

records to the Director at the conclusion of the 

retention period. 

• Monitoring data collected pursuant to §146.90(b) 

through (i) shall be retained for 10 years after it is 

collected.

• Well plugging reports, post-injection site care data, 

including data and information used to develop the 

demonstration of the alternative post-injection site care 

timeframe, and the site closure report shall be retained 

for 10 years following site closure.

• The Director has authority to require the owner or 

operator to retain any records required in this subpart 

for longer than 10 years after site closure.

Well Plugging

§146.92 Injection well plugging. Section 15. Injection well plugging.

Prior to the well plugging, the owner or operator must 

flush each Class VI injection well with a buffer fluid, 

determine bottomhole reservoir pressure, and perform a 

final external mechanical integrity test. 

Well Plugging Plan must include the following 

information:

• Appropriate tests or measures for determining 

bottomhole reservoir pressure;

• Appropriate testing methods to ensure external 

mechanical integrity;

• The type and number of plugs to be used;

• The placement of each plug, including the elevation of 

the top and bottom of each plug;

• The type, grade, and quantity of material to be used in 

plugging. The material must be compatible with the 

CO2 stream; and

• The method of placement of the plugs.

Notice of intent to plug. 

The owner or operator must notify the Director in writing 

at least 60 days before plugging of a well. At this time, if 

any changes have been made to the original well 

plugging plan, the owner or operator must also provide 

the revised well plugging plan. The Director may allow for 

a shorter notice period. Any amendments to the injection 

well plugging plan must be approved by the Director, 

must be incorporated into the permit, and are subject to 

the permit modification requirements. 

Plugging report. 

Within 60 days after plugging, the owner or operator must 

The injection well plugging requirements in this state 

regulation appear to contain similar elements as the 

federal rule. 
E-14

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

submit a plugging report to the Director. The report must 

be certified as accurate by the owner or operator and by 

the person who performed the plugging operation (if 

other than the owner or operator.) The owner or operator 

shall retain the well plugging report for 10 years following 

site closure.

Post-injection Site Care

§146.93 Post-injection site care and site closure. Section 16. Post-injection site care and site closure.

Part of the permit application, includes the following:

• Pressure differential between pre-injection and 

predicted post-injection pressures in injection zone(s);

• Predicted position of the CO2 plume and associated 

pressure front at site closure; 

• Description of post-injection monitoring location, 

methods, and proposed frequency; and

• A proposed schedule for submitting post-injection site 

care monitoring results to the Director. 

• The duration of the post-injection site care timeframe

and, if approved by the Director, the demonstration of 

the alternative post-injection site care timeframe.

Upon cessation of injection, submit an amended plan or 

demonstrate to the Director no amendment is needed. 

May modify and resubmit within 30 days of such change. 

At the Director's discretion, demonstrate during the 

permitting process that an alternative post-injection site 

care timeframe is appropriate and ensures nonendangerment of USDWs. The demonstration must be 

based on site-specific information, including the results of 

site-specific computational modeling; the predicted 

timeframe for pressure decline; the predicted rate of CO2 

plume migration; site-specific chemical processes that 

will result in CO2 trapping; the predicted rate of CO2 

trapping; characterization of the confining zone(s); 

laboratory analyses or studies to verify the information on 

trapping; the presence of potential conduits for fluid 

movement and the quality of abandoned well plugs within 

the AoR; the distance between the injection zone and the 

USDWs above and/or below the injection zone; and any 

additional site-specific factors determined by the Director. 

The demonstration must meet the criteria at 

§146.93(c)(2) for ensuring the quality and accuracy of the 

data and models on which the demonstration is based.

Monitor the site following the cessation of injection to 

show the position of the CO2 plume and pressure front 

and demonstrate that USDWs are not being endangered. 

• Continue to conduct monitoring as specified in the 

Director-approved plan for at least 50 years following 

the cessation of injection or for the duration of the 

approved alternative timeframe, unless he/she makes 

a demonstration. At the Director’s discretion, the 

monitoring must continue until the project no longer 

poses an endangerment to USDWs. 

Notify the Director in writing at least 120 days before site 

The site-care and site-closure requirements in this state 

regulation appear to contain similar elements as the 

federal rule. The exceptions are noted below.

• The state does not specify a period of least 50 

years following the cessation of injection. 

• The state requires owner or operators to retain 

records for three years following site closure and 

post-injection care. Upon the close of the owner or 

operator retention period the records will be 

delivered to the Director who will thereafter retain 

the records.
E-15

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

closure. If any changes have been made to the original 

plan, the owner or operator must also provide the revised 

plan. The Director may allow for a shorter notice period.

After the Director has authorized site closure, plug all 

monitoring wells in a way which will not allow movement 

of injection or formation fluids that endangers a USDW.

Submit a site closure report to the Director within 90 days 

of site closure, which must be retained at a location 

chosen by the Director for 10 years. Report includes: 

• Documentation of appropriate injection and monitoring 

well plugging. Provide a copy of a survey plat;

• Documentation of appropriate notification and 

information to such State, local and Tribal authorities 

that have authority over drilling activities; and

• Records reflecting the nature, composition, and volume 

of the CO2 stream.

Record a notation on the deed to the facility property that 

will in perpetuity provide any potential purchaser:

• The fact that land has been used to sequester CO2; 

• The name of the agency or authority with which the 

survey plat was filed and the address of the EPA 

Regional Office to which it was submitted; and

• Volume of fluid injected, the injection zone (s) it was 

injected, and the period over which injection occurred. 

Retain for 10 years following site closure, records 

collected during post-injection site care period. Deliver 

the records to the Director at the end of the retention 

period. Retain records at location chosen by the Director.

Emergency and Remedial Response

§146.94 Emergency and remedial response. Section 17. Emergency and remedial response.

As part of the permit application, the owner or operator 

must provide the Director with an emergency and 

remedial response plan that describes actions the owner 

or operator must take to address movement of the 

injection or formation fluids that may cause an 

endangerment to a USDW during construction, operation, 

and post-injection site care periods. 

If evidence shows potential endangerment of USDWs, 

the owner or operator should cease injection; notify the 

Director within 24 hours; implement the emergency and 

remedial response plan. Prior to re-commencing 

injection, demonstrate to the Director non-endangerment 

to USDWs. 

 

• Periodically review the emergency and remedial 

response plan at least once every five years. Amended 

plans or demonstrations shall be submitted to the 

Director within one year of an AoR reevaluation; 

following any significant changes to the facility; or 

when required by the Director.

The emergency and remedial response conditions in this 

state regulation appear mostly similar to the federal rule. 

The Wyoming rule refers to the “administrator” rather 

than “the Director.” The portion of the Federal rule that 

described amendments is included in Section 8 of the 

Wyoming rule, under the AoR delineation conditions, as 

referenced here. See below for details.

(a) As part of the permit application, the owner or 

operator must provide the administrator with an 

emergency and remedial response plan that describes 

actions to be taken to address movement of the injectate 

or formation fluids that may cause an endangerment to a 

USDW or threaten human health, safety, or the 

environment during construction, operation, closure and 

post-closure periods.

(iv) Implement the emergency and remedial response 

plan approved by the administrator.

(c) The administrator may allow the operator to resume 

injection prior to remediation if the owner or operator 

demonstrates that the injection operation will not 

endanger USDWs or otherwise threaten human health, 

safety, or the environment
E-16

Final Class VI Rule

(pre-publication version signed by the Administrator on 

November 22, 2010)

Wyoming Final Rule

(W.S. 35-11-101 through 1904, specifically 313. Final as 

of September 17, 2010.)

(d) The owner or operator must notify the administrator 

or the designated representative prior to conducting any 

well workover.