# 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 Regu l ations 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Arkansas HB 1592 Introduced February 23, 2009, withdrawn and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.sta te.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 CCS

equipped IGCC technology. http://www.inter west.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 seques tration 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.pdfYellow 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 re quirements 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

- 0009 8-
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 Lan ds 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://e

lobbyist.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, includin g 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 a bove bill, but also creates a task force to identify ways to decrease greenhouse gas emissions, including carbon sequestration (does not specifically mention injection). http://w ww.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_.
htmYellow 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 Energ y 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 h elp 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) Sig ned 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
=29844Yellow 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 0 95

- 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 A ugust 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 sou rce. 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?Doc Name=&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
I llinois 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 (n ow 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, includin g 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 incentive s 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 jurisdict ion 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 01 15 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 SF 2226 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/Cool

ICE/default.asp?Category=BillInfo&Service=Billbook& ga=83&menu=text&hbill=SF2226Yellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 6 State Citation Year and Status Description URL

Iowa SF192 S tatus unknown. Requires the Department of Natural Resources to conduct a study on feasibility of GS, due by January 1, 2009. http://co olice.legis.state.ia.us/Cool

ICE/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/Cool

ICE/default.asp?category=billinfo&service=billbook&GA=8 2&hbill=HF2271ation&fn=default.htm&xhitlist_d=current

legislation

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 Re duction 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 statu s 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.htmYellow 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 sessi on) 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
M arch 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 Sen t 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 comm ittee 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. ht tp://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.htmYellow 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 l ocal 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/HB

661(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 speci fically 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 progr ess 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&2.0Yellow 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
defi nition 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
4/15/0 9 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 Accompanie d 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/legi s/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
S eptember 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

- SB

0708&query=onYellow 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 ca pture machinery or equipment. http://www.legislature.mi.gov/(S(skz1n3eeld4f3v45muwq5s 45))/mileg.aspx?page=getobject&objectname=2007

- SB

0801&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 commod ity 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

- HB

5604&query=on

Michigan SB 1164 Introduced March 4, 2008, referred to Energy Policy
and Public Utilities on March 4, 2008 C reates 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 ma chinery, 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

- HB

4016&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

- SB

0775&query=onYellow shading indicates regulations. Bold blue font signifies final regulations or enacted legislation. 11 State Citation Year and Status Description URL

Michigan HB 5253 Introduce d 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

- HB

5253&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
Po licy committee on May 15, 2009 Exempts GS of CO2 from the greenhouse gas control plan. https://www.revisor.mn.gov/revisor/pages/search_sta tus/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 cap acity 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=2007Yellow 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/HB1459S G.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.stat e.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 o r 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 H B 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
fYellow 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 21 8. 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 t hat 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 inte rest 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/bill pdf/SB0498.pdf

Nebraska LB 957 2000

- bill introduced to review its purpose in 2007, not resolved as of
2008 session Establish es 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 e xhaust 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

gr ants 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 Commit tee 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 CarolinaYellow 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 provide s for unitization. Directs state to accept long

- term liability, establishes fund for regulatory costs, remediation, and long

- term stewardship. http://www.legis.nd.g ov/assembly/61

- 2009/bill

status/senate/index.aspx?ls=61

North Dakota SB 2139 Signed April 8, 2009 Addresses pore space ownership. http://www.legis.nd.gov/assemb ly/61

- 2009/bill

status/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/bill

status/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/bill

status/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 compari son 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 Establish es 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.htmYellow 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 Se questration 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 Environmenta l 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.u s/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. h ttp://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 activ ities, 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
Environm ental 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=0266Yellow 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 ar e 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, energ y 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

Ten nessee

Texas HB 149 Signed May 31, 2006 Directs the Railroad Commission to be responsible for the CO2 from the FutureGen

program. http://www.capitol.sta te.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. h ttp://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=HB1796Yellow 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=SB138 7

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

VermontYellow 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 long

term liability and creates a Carbon Dioxide Storage Facility Trust Fund. http://leg1.state.va.us/cgi

bin/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 pro ject, which may include projects utilizing nuclear power, renewable technologies, carbon capture facilities, combined cycle combustion turbines, and conventional coal
facilities. ht tp://leg1.state.va.us/cgi

bin/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/cgi

bin/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 en ergy 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 /cgi

bin/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=2007Yellow 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 Vir ginia 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 Int roduced 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 f or 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. legisw eb.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.u s/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.pdfYellow 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 acco unt, 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 Qualit y 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.htmA-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 geo logic sequestration

.

**•** A lso applies to owners or operators of permit - or rule

authorized 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

- te rm containment of a gaseous, liquid, or supercritical CO 2 stream in subsurface geologic formations. This term does not apply to CO2 capture or transport.

Ge ologic 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. Thi s 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) mon itoring plugged and abandoned wells.

Permit Conditions §146.82 Required Class VI permit information. 82 -3- 1101 - 82 -3- 1105

. P ermit 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);

**•** M ap showing the injection well, the applicable AoR,

and faults, if known or suspected; Permit application conditions in this s tate regulation appear similar to the federal rule. An additional requirement of th is state regulation is noted below

.
Each application shall contain the following information: 

### Appendix A
Kansas : Permanent Administrative Regulations
Under Article 3 ( Production and Conservation o f Oil and Gas ) Preliminary Comparison with the Final Class VI RuleA-2 **•** Information on the geologic structure and

hydrogeologic properties ;

**•** T abulation 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 direc tion of water movement, where known ;

**•** Baseline geochemica l data on subsurface formations;

**•** Proposed operating data ;

**•** Proposed pre

- operational formation testing program ;

**•** Proposed stimulation program ;

**•** Proposed procedure to conduct injection operation ;

**•** Schematic s 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 p ost

- 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 Territori es 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:

**•** F in al 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 ) ;

**•** R esults of the formation testing program;

**•** Final injection well construction procedures;

**•** S tatus of co rrect ive 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 b elow 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 regula tory 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 2 2 , 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 2 2 , 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 r equire s 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 one

half 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 fa cility will

be located.

The applicant shall publish notice of the application in the official county newspaper , the Kansas Register, and the Wichita Eagle newspaper.

T he 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 i njection 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 con trol 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

.

P art of the permit application, submit a plan that includes:

**•** M ethod for delineating the AoR ; An AoR and corrective action plan is not in cluded in this Kansas regulation

. However, a n AoR evaluation must be included in the permit application

. Also, the regulation does not require computational modeling or periodic re

evaluations 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 2 2 , 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 m inimum fixed frequ ency, not to

exceed five years, to reevaluate the AoR; m onitoring and operational conditions that would warrant a n earlier reevaluation ; h ow monitoring and operational data will be used to inform a reevaluation; h ow 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.

T o 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

mov ement 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 ;

**•** I dentify 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 ye ars
, 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 r eevaluated 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 demonstrati on 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

**•** Identi fication 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 Fin ancial responsibility.

The demonstrat ion of financial responsibility in this state regulation appears less comprehensive than the federal rule. A d emonstrat ion 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 D irector. Adjustments to the financial respons ibility may The owner or operator must demonstrate and maintain financial responsibility as approved by the Directo r, until t he Director approves the completed post

- injection s ite care and site closure plan and approves site closure. The

owne r or operator may be released from a financial instrument in the certain circumstances.

The financial responsibility instrument(s) used must:

**•** Be f rom the list of qualifying instruments ;

**•** Be sufficient to cover the cost of c orrective action,A-5 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 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, p ost injec tion site care and site closure, and e mergency and remedial response ;

**•** Be s ufficient to address endangerment of USDWs ; and

**•** C omprise protective conditions of coverage , including

at a minimum cancellation, renewal, and continuation
prov isions, 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

.

H ave 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.

N otify the Director by certified mail o f adverse financial conditions that may affect the ability to carry out injection well plugging and post

- injection site care and site closure.

P rovide 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 quali fying financial responsibility instrument(s) that the most recent demonstration is no longer adequate to cover the cost of corrective action, injection well plugging

, post

- inject ion site care and site closure, and emergency and remedial response

.
The Director must approve the use and length of pay

- in

periods for trust funds or escrow accounts. be required by the D irector

. [KAR 82 -3- 11 01 (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. 8 2-3- 1100 through K.A.R. 82 -3- 1119. [KAR 82 -3- 11 20 ]

Construction Requirements §146.86 Injection well construction requirements. 82 -3- 1106. Well construction requirements. All materials (e.g. c as ing and c ementing 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 C onstruction 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. IfA-6 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 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 P acker.

**•** 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.

**•** T he owner or operator must submit the quantitative

information requested in th e 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

e stablishment, 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 t he 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 ot her 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 ma y

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.

T ake 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
samp le information.

Record fluid temperature, pH, conductivity, reservoir Construction requirements in this Kansas regulation state that newly drilled wells sha ll 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 reenter ed, 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 measuri ng 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. A n 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 2 2 , 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).

D etermine or calculate injection and confining zone(s) f racture pressure; physical and chemical characteristics of the inje c tion and confining zone(s) and formation fluids in the injection zone(s).

C onduct pressure fall

- off test and a pump test or injectivity tests u pon completion, but prior to operation , to verify hydrogeologic character istics of the injection zone(s).

P rovi de the Director with the opportunity to witness all logging and testing . S ubmit a schedule of such activities to the Director 30 days prior to conducting the first test

. A ll 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.

E nsure 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.

F ill the annulus between the tubing and the l ong string casing with a non

- corrosive fluid approved by the Director. M aintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines otherwise

.

M aintain mechanical integrity of the injection well at all times , other than during periods of well workover approved by the Director.

I nstall 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 diverg e 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 b e lacking mechanical integrity : O perating requirements are described in the following sections: CO2 storage facility; permit appl ication. [KAR 82 -3- 1101 ], well construction requirements [KAR 82 -3- 1 106], r eport of leak, potential leak, or loss of containment [KAR 82 -3-1 113 ]. 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 demo nstrate 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 s hall 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 beA-8 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 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;

**•** Restor e 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 re port. [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,

u sable water, or p roperty. [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 inst allation 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 D irector 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 w ell has mechanical integrity if t here is no significant leak in the casing, tubing, or packer; and t here 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 owne r 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 mechanic al integrity test, the Director must submit a written request to the Administrator and t he 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

.

T he 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 perform ing 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 ap plied

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 me chanical 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 2 2 , 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 physica l 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 e xtent 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 meth ods , 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 o perations, the operator shall file monthly pressure, injection, and withdrawal reports, containing m aximum , minimum, and average wellhead pressure reading, total amount of CO2 injected and withdrawn each week ; and cumulative total of CO2 i n 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 le ak 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 testingA- 10 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 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 8 2-3- 1107 (i) ] Reporting Requirements §146.91 Reporting requirements. 82 -3- 11 08. 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

rel evant 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 ann ulus 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 inj ected 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

ma lfunction 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.

**•** A ny release of CO2 to the atmosphere or bi osphere.

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 fo rmat approved by EPA. Reporting requirements are described in the s torage fa cility monitoring and reporting section [KAR 82 -3-1 108] 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 cumul ative 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 m aximum

, minimum , and average wellhead pressure reading for the month; total amount of CO2 withdraw n 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 repo rt 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 mo nthly 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 ta pes, 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
supe rvisory 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 con servation division within 30 days following the review.A- 11 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 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 concl usion 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

- inje ction site care data,

including data and information used to develop the demo nstration 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- 110 9(d)]

The operator shall maintain a record of l eak detector each inspection, including the inspection results, for at least five years and shall make each record available to the conser vation division upon request. [KAR 82 -3- 11 11 (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 ma de 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,

u sable 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 )]

Addi tional reports may be required by the D irector 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 aban donment of storage facility; 82 -3- 1118. Plugging methods and procedures, plugging report, and plugging fee for CO 2 storage wells. Prior to the well plugging, the owner or operator mus t 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 determ ining

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 offic e at least 30 days before the planned comm encement of plugging operations. [KAR 82 -3- 1118 (a)(1)]

Perform one of the following: s et a mechanical bridge plug or other control device approved by the director immediately above the CO2 storage reservoir or sto rageA- 12 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 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 pluggi ng 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 p lugging 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 cl osure

. 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

o peration, 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 fo r 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 lea st 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 s ite care and site closure. 82 -3- 1117. Postclosure determination

P art of the permit application, includes the following :

**•** P ressure differential between pre

- injection and

predicted post

- injection pressures in injection zone(s);

**•** P redicted position of the CO2 plume and associated

pressure front at site closure;

**•** D escription 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 th e post

- injection site care timeframe

and, if approved by the Director, the demonstration of the alternative post

- in jection site care timeframe

.
Upon cessation of injection, submit an amended plan o r demonstrate to the Director no amendment is needed. M ay 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 non

endangerment 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 trappin g; 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 de monstrate 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)]

I f the application is denied, the closure period activities shall continue as directed by the director. [KAR 82 -3- 1117 (c)]

I n 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 2 2 , 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.

M onitor 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.

**•** C ontinue 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 mus t continue until the project no longer poses an endangerment to USDWs.

N otify the Director in writing at least 120 days before site closure. I f 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 clo sure, plug all monitoring wells in a way which will not allow movement of injection or formation fluids that endangers a USDW.

S ubmit 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 include s:

**•** Documentation of appropriate injection and monitoring

well plugging. Pr ovide a copy of a survey plat ;

**•** Documentation of appropriate notification and

information to such State, local and Tribal authorities that have authority over drilling activi ties ; and

**•** Records reflecting the nature, composition, and volume

of the CO2 stream.

R ecord a notation on the deed to the facility prope rty 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; a nd

**•** V olume of fluid injected, the injection zo ne (s) it was

injected, and the period over which injection occurred.

R etain for 10 years following site closure, records collected during post

- injection site care period. D eliver the records to the Director a t the end of the retention period . Retain r ecords at location chosen by the Director

.A- 14 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 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 emerge ncy and remedial response plan. P rior to re

- commencing injection, demonstrate to the Director non

- endangerment to USDWs.

P eriodically review the emergency and remedial response plan at least once every five years. Amended plans or demonstrations shall be submitted to the Dire ctor w ithin one year of an AoR reevaluation; f ollowing any sign ificant changes to the facility ; or w hen required by the Director. Emergency and remedial response requirements in this state regulation appear similar to federal rule. Exceptions are noted bel ow.

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- 110 9(a )]

Each operator of a CO2 storage facility shall perform an annual safety inspec tion 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 con current with permit application. Details about the possible demonstrations and other requirements are noted in the rule text.

The Director must submit, to the Regional Adm inistrator, 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 info rmation de tailed 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 2 2 , 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 requi rements, 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 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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

.

**•** Al so applies to owners or operators of permit - or rule

authorized 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 faciliti es. 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 sto rage 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 th at delineated region.

Site closure "Postclo sure period" means that period after th e 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 certifi cate 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 in formation. 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);

**•** M ap showing the injection well, the applicable AoR,

and faults, if known or suspected;

**•** Information on the geologic structure and

hydrogeologic properties ;

**•** T abulation of all wells within the AoR which penetrate

the injection or confining zone(s) ;

**•** M aps and stratigraphic cross sections indicating all

USDWs, water wells and springs within the AoR , their P er mit application conditions in this s tate 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 plansB-2 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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 geochemica l data on subsurface formations;

**•** Prop osed 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 A oR 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 Territori es within the AoR o f 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:

**•** F inal 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 m inerals in both the injection and the confining zone(s ) ;

**•** R esults of the formation testing program;

**•** Final injection well construction procedures;

**•** S tatus of co rrective 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 b elow 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 detai l 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 r equire s 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 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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 ki lometer] 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 fault s 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

. R equirement s 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 reservo ir’s mechanisms of geologic confinement, including rock
prope rties, regional pressure gradients, structural features, and adsorption characteristics with re gard to the ability of that confi nement to prevent migration of carbon dioxide beyond the proposed storage reservoir.” [ 43

- 05

- 01

- 05 (1)(b)(2)]

“ The commission sh all approve limits that, with a

r easonable degree of certainty, will avoid initiating a new fracture or propagating an existing fracture in the confi ning zone or cause the movement of injection or formation fluids into an underground source of drinking wat er .” [ 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

.

P art of the permit appl ication, submit a plan that includes:

**•** M ethod for delineating the AoR ;

**•** Description of the minimum fixed frequency, not to

exceed five years, to reevaluate the AoR; m onitoring and operational conditions that would warrant a n earlier reevaluation ; h ow monito ring and operational data will be used to inform a reevaluation; h ow 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 “area l 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 proceduresB-4 Final Class VI Rule (pre- publication version signed by the Administrator on North Dakota, C h apter 43

- 05: Geo logic Storage of Carbon Dioxide (Final, Effective April 1, 2010) November 2 2 , 2010 )

T o 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
p lume 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 presen t, or until the end of a fixed time period as determined by the Director. The rule further describes the requirements of the model ;

**•** I dentify 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 ye ars
, 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 demonstrati on 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 ma intain financial responsibility as approved by the Directo r, until t he Director approves the completed post

- injection s ite care and site closure plan and approves site closure. The owner or operator may be released from a financial instrument in the certai n circumstances.

The financial responsibility instrument(s) used must:

**•** Be f rom the list of qualifying instruments ;

**•** Be sufficient to cover the cost of c orrective action,

injection well plugging, p ost injec tion site care and site closure, and e mergency and remedial response ;

**•** Be s ufficient to address endangerment of USDWs ; and

**•** C omprise protective conditions of coverage , including

at a minimum cancellation, renewal, and continuation provisions, specifications on when the provider becomes liable in case of c ancellation 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 fulfi ll. If the commiss ion 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 reg ulation including the delineation of specific regula tory 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 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic Storage of Carbon Dioxide (Final, Effective April 1, 2010) minimum rating, minimum capitalization, and ability to pass the bond rating when applicable

.

H ave 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

sepa rately 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.

N otify the Director by certified mail o f adverse financial conditions that may affect the ability to carry out injection well plugging and post

- injection site care and site

c losure.

P rovide 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

- inject ion site care and site closure, and emergency and remedial response

.
The Director must approve the use and length of pay

- in

periods for trust funds or escrow accounts. Construction Requirements §146.86 Injecti on well construction requirements. 43

- 05

- 01

- 11. Well operational standards. All materials (e.g. c as ing and c ementing 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 t he

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 ci rculating 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 P acker. C onstruction requirements in this state regulation appear similar to but less specific than the federal rule. However, note that many of the requ i rements 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 w ater 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)]

**•** Th e packer must be set at a depth at which the packerB-6 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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.

**•** T he 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. W ell 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 ot her 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.

T ake 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).

D etermine or calculate injection and confining zone(s) f racture pressure; physical and chemical characteristics of the injection and confining zone(s) and formation fluids in the injection zone(s).

C onduct pressure fall

- off test and a pump test or injectivity tests u pon completion, but prior to operation , to verify hydrogeologic character istics 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 activitie s, 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 con fi ning strata above the storage reservoir and the reservoir ’ s s tratigraphic 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 af fi davit 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

con fi ned to the storage reservoirs. Such proof must b e provided in the form of a cement bond log or the results of a fluid movement study or such other method speci fi ed by the commission; and

**•** The results of a mechanical

- integrity test, if appli cable

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 speci fi ed by the commission . All other wells to be used as injection wells must demonstra te mechanical integrity as specifi ed 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 perforationB-7 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic Storage of Carbon Dioxide (Final, Effective April 1, 2010) zone(s).

P rovide the Director with the opportunity to witness all logging and testing . S ubmit a schedule of such activities to t he Director 30 days prior to conducting the first test

. or open hole for the storage reservoirs; and

**•** The commission may require additional t esting, 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 integ rity. [43

- 05

- 01

- 11(13) ] Operating Requirements §146.88 Injection well operating requirements.

E nsure 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 initi ate 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 th e well bore is prohibited.

F ill the annulus between the tubing and the long string casing with a non

- corrosive fluid approved by the Director. M aintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines otherwise

.

M aintain mechanical integrity of the injection well at all times , other than during periods of well workover approved by the Director.

I nstall 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
sy stems (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 b e 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 continuo u s recording

devices are discussed under §146.90 (“Testing and Monitoring Re quirements ”).

**•** Automated leak detection devices and alarms are

requ i red. [43

- 05

- 01 -14(1)]

**•** All injection wells must be equipped with shutoff

syst ems 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 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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 w ell has mechanical integrity if t here is no significant leak in the casing, tubing, or packer; and t here 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 t he Administrator may approve the request

. Any alternate met hod approved by the Administrator will be published in the Federal Register and may be used in all States

.

T he owner or operator and the Director must apply methods and standards generally accepted in the industry. When the owner or operator reports the r esults 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. T he 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 inte grity as specifi ed by the commission and demonstrate continued mechanical integrity through periodic testing a s determined by the commission. All other wells to be used as injection wells must demonstrat e mechanical integrity as specifi ed 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 sufficie nt 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 strin g 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 inB-9 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic Storage of Carbon Dioxide (Final, Effective April 1, 2010)

Director.

**•** Periodic monitoring of the ground water quality and

geochemical changes above the confini ng 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 meth ods , 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 yea rs. 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 moni toring 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 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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 ca use 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.

**•** A ny 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 compositio n 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

- inje ction 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. F acility 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 incl ude 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 requ i rements 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 we lls.

**•** The well casing must be cut off at a depth of five feetB- 11 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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 oper ator 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 operat or 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

observatio n 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

. P art of the permit application, includes the follow ing:

**•** P ressure differential between pre

- injection and

predicted post

- injection pressures in injection zone(s);

**•** P redicted po sition o f t he CO2 plume and a ssociated

pressure front at site closure;

**•** D escription 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

- in jection site care timeframe

.
Upon cessation of injection, submit an a mended plan o r demonstrate to the Director no amendment is needed. M ay 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 non

endangerment 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 closu re 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

c onducted 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 b e 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.

**•** T he 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’sB- 12 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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 an y 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.

M onitor the site following the cess ation of injection to show the position of the CO2 plume and pressure front and demonstrate that USDWs are not being endangered.

**•** C ontinue to conduct monitoring as specified in the

Director

- approved plan for at least 50 years following the cessation of inj ection 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.

N otify the Director in writing a t least 120 days before site closure. I f 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 clo sure, plug al l monitoring wells in a way which will not allow movement of injection or formation fluids that endangers a USDW.

S ubmit 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 include s:

**•** Documentation of appropriate injection and monitoring

well plugging. Pr ovide a copy of a survey plat ;

**•** Documentation of appropriate notification and

information to such State, local and Tribal authorities that have authority over drilling activi ties ; and

**•** Records reflecting the nature, composition, and volume

of the CO2 stream.

R ecord 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 sequeste r CO2 ;

**•** The name of the agency or authority with w hich the

survey plat was filed and the address of the EPA Regional Office to which it was submitted; and

**•** V olume of fluid injected, the injection zo ne (s) it was

injected, and the period over which injection occurred.

R etain for 10 years following site closure, records collected during post

- injection site care period. D eliver the records to the Director at the end of the retention period . Retain r ecords 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 f or PISC (nor an alternate timeframe).

Emergency and Remedial Resp onse §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 pla n 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 theB- 13 Final Class VI Rule (pre- publication version signed by the Administrator on November 2 2 , 2010 ) North Dakota, C h apter 43

- 05: Geo logic 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 emerge ncy and remedial response plan. P rior to re

- commencing injection, demonstrate to the Director non

- endangerment to USDWs.

P eriodi cally review the emergency and remedial response plan at least once every five years. Amended plans or demonstrations shall be submitted to the Director w ithin one year of an AoR reevaluation; following any sign ificant changes to the facility ; or w hen requ ired 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 e mergency response procedures must include contingency plans for carbon dioxide leakage from any well, fl ow lines, or other facility and identify specif ic 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 s urface 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 Administrato r on November 2 2 , 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 sequestrati on

.

**•** Also applies to owners or operators of permit - or rule

authorized 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 sub chapter 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 gaseo us, liquid, or supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply to carbon dioxide capture or transport. Geologic s equestration 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 re nder 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 de pth 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 p ursuant to §§146.4 of this chapter and 144.7(d). It includes the subsurface three

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.

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 ca re responsibilities.

Post- injection site care Post- injection facility care: Monitoring and other actions (including corrective action) needed following cessation of injectio n 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 (includin g 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 RuleC-2 Final Class VI Rule (pre- publication version signed by the Administrato r on November 2 2 , 2010 ) Texas Proposed Rule ( October 15, 2010 )

Permit Conditions §146.82 Required Class VI permit information. §5.202 Permit Requir ed; §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,

an d 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, wate r 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 res ponsibility;

**•** 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 li st 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 gra nting 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 geol ogic

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. P ermit application conditions in this proposed state

r egulation appea r similar to the federal rul e 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 mod eling. 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:

**•** F ive years after initiation of injection;

**•** F rom initiation of injection to the end of the injection

period proposed by the applicant; and

**•** F rom initiatio n 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 Administrato r on November 2 2 , 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 volu me of the carbon dioxide stream.

**•** Confining zone(s) free of transmissive faults or

fractures and of sufficient areal extent and int egrity 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 a nd 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

.

P art of the permit application, submit a plan that includes:

**•** Method for delineatin g 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 reevalua tion; 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.

T o 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

commen cement 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 i n this proposed state regulation appear s similar to the federal proposed rule

.C-4 Final Class VI Rule (pre- publication version signed by the Administrato r on November 2 2 , 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 th e 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 a ction 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 n eeded.

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 cancella tion, 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, mi nimum 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 demonstrat ion and maintenance of financial responsibility in this proposed state regulation appears

s imilar to the federal r ule 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 b ase application fee

, injection fee, and post -i njection care fee must be remitted to the Co mmission 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, emergencyC-5 Final Class VI Rule (pre- publication version signed by the Administrato r on November 2 2 , 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/

decrease s, 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 conditio ns 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 emerge ncy and remedial response.

The Director must approve the use and length of pay

- in

periods 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 r equirement s: 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 w ith 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 C onstruction requirements in this proposed state regulation appear simila r 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 Administrato r on November 2 2 , 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.

Durin g 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

ce mented.

**•** 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:

w ell 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 testin g requirements in this proposed state regulation appear similar to federal rule.C-7 Final Class VI Rule (pre- publication version signed by the Administrato r on November 2 2 , 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 hydro geologic 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

E nsure 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.

F ill the annulus between the tubing and the long string casing with a non

- corrosive fluid approved by th e Director. M aintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines otherwise

.

M aintain mechanical integrity of the injection well at all times , other than during periods of well workover approved by the Director.

I nstall 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 i n this proposed state regulation appear similar to federal proposed rule including the requirements for alarms and automatic shut

- of f 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 individua l well meter. [5.20 6(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 non

transmissive 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 mu st 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 Administrato r on November 2 2 , 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 chann els 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 casi ng; 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 w ritten 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 appl y 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 in tegrity

. 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 requirement s 

### i n 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 Administrato r on November 2 2 , 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 elevate d 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. A fter initiatio n of injection, the performance on a semi

annual 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 cha nges, including:

**•** P eriodic 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 t o and above the top confining zone;

**•** P eriodic 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;

**•** T he location and number of monitoring well justified

on the basis of the area of review, injection rate and volume, geology, and the presence of artifi cial penetrations and other factors specific to the geologic storage facility; and

**•** T he 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.

T racking the extent of the CO 2 plume and the position of the pressure front by using indirect, geo p hysical techniques

, which may include seismic, electrical, gravity, or electromagnetic surveys and/or dow n- hole CO 2 detection tools.

A dditional 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 t he requirements that the injection activity n ot 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 Reportin g 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 th e testing. [5.207(a )(1)]C- 10 Final Class VI Rule (pre- publication version signed by the Administrato r on Texas Proposed Rule ( October 15, 2010 ) November 2 2 , 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 t he 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 b y 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 injectio n 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 conducte d

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.

Re cords 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
pres sure as specified in the p ermit.

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 cumulative ly over the life of the project;

**•** Monthly annulus fluid volume added

. [§ 146.91(a)(5) & (6)]

The operator must retain all wellhea d pressure records, metering records, a nd integrity t est r esults f or at l east five years. [5.20 7(c) ]C- 11 Final Class VI Rule (pre- publication version signed by the Administrato r on November 2 2 , 2010 ) Texas Proposed Rule ( October 15, 2010 )

records to the Director at the conclusion of the retention pe riod.

**•** Monitoring data collected pursuant to §146.90(b)

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

**•** Well plugging reports, post

- inje ction site care data,

including data and information used to develop the demonstration of the alternat ive 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 a fter site closure. Well Plugging §146.92 In jection 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 exter nal

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
p lugging 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 per mit, 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 t he 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 m onitoring wells that penetrate the base of usable quality water and all inje ction wells upon abandonment. Well plugging requirements in this proposed state regulation appear similar to the federal rule but also address monitoring wells

. Exceptions are note d 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 Administrato r on November 2 2 , 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

. P art of the permit application, includes the fol lowing:

**•** P ressure differen tial between pre

- injection and

predicted post

- injection pressures in injection zone(s);

**•** P redicted position of the CO2 plume and associated

pressure front at site closure;

**•** D escription 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

- in jection site care timef rame

.
Upon cessation of injection, submit an amended plan or demonstrate to the Director no amendment is needed. M ay modify and resubmit within 30 days of such change.

At the Director's discretion, demonstrate during the permitting process that an alter native post

- injection site care timeframe is appropriate and ensures non

endangerment of USDWs. The demonstration must be based on site

- specific information, including the results of site

- specific computational modeling; the predicted timeframe for pressur e 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 factor s 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.

M onitor 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.

**•** C ontinue 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 timefram e , 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.

N otify the Director in writing at least 120 days before site clos ure. I f 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 propos ed 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:

**•** T he estimated magnitude and extent of the facility

plume and the area of elevated pressure);

**•** F ootprint (the CO 2 or displaced formation fluids that

will endanger underground sources of drinking water;

**•** T hat 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;

**•** T hat 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

**•** A ny 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.

.

Th e 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 specifi ed 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 Administrato r on November 2 2 , 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.

S ubmit 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 include s:

**•** Docume ntation of appropriate injection and monitoring

well plugging. Pr ovide 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.

R ecord 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

**•** V olume of fluid injected, the injection zone (s) it was

injected, and the period over which injection occurred.

R etain for 10 years f ollowing site closure, records collected during post

- injection site care period. D eliver the records to the Director at the end of the retention period . Retain r ecords 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 re sponse 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.

**•** P eriodically review the emergency and remedial

response plan at least once every five years. Amended plans or demonstrations shall be submitted to the Director w ithin one year of an AoR reevaluation; following any significant changes to the facility ; or

w hen 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 perso nnel 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 Administrato r on November 2 2 , 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 Administrat or, 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

c onsultation.

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 ru le 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 additiona l 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 sp ecific to Class V wells used to inject carbon dioxide for permanent geologic sequestration. There are additional requi rements 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 Rule 1 (Chapter 173-218-030 and 173-218-115 Washington

Administrative Code. Last updated June 19, 2008)

A pplicability §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: De finitions 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 r equirements 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 surfac e area above that delineated region.

Permit Conditions §146.82 Required Class VI permit informa tion. 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 injectio n 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 Rule 1 (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 construc tion 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 bo rders, 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 wr iting, 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 absorpt ion 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 inject ion wells or releases from the geologic containment system. These emergency response procedures shall be updated as necessary throughout the operational li fe 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, event s 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 Rule 1 (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 info rmation on the predicted contain the injected carb on dioxide stream and extent of the injected CO 2 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.

A oR and Corrective Action §146.84 AoR and corrective action. 173-218- 11 5 (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 t here 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 co mputational modeling, the projected lateral and vertic al migration of the CO2 plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, until pressu re 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 de scribes 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 injecti on 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 Rule 1 (Chapter 173-218-030 and 173-218-115 Washington

Administrative Code. Last updated June 19, 2008) that may penetrate the c onfining 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 r eevaluated 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, regardl ess 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, specificatio ns 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 bas ed on the costs to the regulatory agency of hiring a third party.

**** During the active life of the geologic sequestration

project, the owner or operat or must adjust the cost estimate for inflation within 60 days prior to the anniversary date of the est ablishment 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 andpost-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 Rule 1 (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 increase d/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 co st estimate to the Director within 60 days of notificatio n 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 ac tion, 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 requiremen ts. 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 Rule 1 (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 su ch 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 po tential, 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 wi th 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 leve l of the injection zone(s).

Determine or calculate inje ction 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 requir ements. 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 pressu re 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 Rule 1 (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, vo lume and/or mass, and temperature of the CO2 st ream; 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 with in 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 contam inants, 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, mini mum 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, inje cted 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 leastD-8 Final Class VI Rule (pre-publication version signed by the Administrator on November 22, 2010) Washington Final Rule 1 (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 t he test(s) and the method(s) used. In making his/her evaluation, the Director must review monitoring and other te st 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; identific ation 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, event s 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 Direct or, a casing inspection log; environment is required.

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

**** Testing and monitoring to tr ack 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 Rule 1 (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. 173-218-11 5 (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 inje ction well conducted by the

permittee if required by the Director.

Report, within 24 hours of:

**** Any evidence that the in jected CO2 stream or

associated pressure front may cause an endangerment to a USDW;

**** Any noncompliance with a permit condition, or

malfunction of the injectio n 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 not ify 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 dist ribution 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 submi tted to the department that include:

**** A summary of the data collected throughout the year,

including any trends, observations, predictions as well as calculated spatial dist ribution 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 geol ogic 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 documentationD-10 Final Class VI Rule (pre-publication version signed by the Administrator on November 22, 2010) Washington Final Rule 1 (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 Stat e has primary enforcement calculated cost. responsibility, owners or operators must submit all [WAC 173-218-115 (4)] required reports, submitta ls, 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 alternativ e 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 mechanic al 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 plac ement 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 toD-11 Final Class VI Rule (pre-publication version signed by the Administrator on November 22, 2010) Washington Final Rule 1 (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 operat or.) 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 t he 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 resu lts 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 discretio n, demonstrate during the permitting process that an alternative post-injection sitecare 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 m eet 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 Dir ector’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 req uest 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 cl osure 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 sh all 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 c ontainment system and related trapping mechanisms. The postclosure period shall be complete only after the operator has received writtenD-12 Final Class VI Rule (pre-publication version signed by the Administrator on November 22, 2010) Washington Final Rule 1 (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 appropr iate 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 followi ng 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 applicat ion, 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 pl an 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 t he 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 throughD-13 Final Class VI Rule (pre-publication version signed by the Administrator on November 22, 2010) Washington Final Rule 1 (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 t he 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

.

**•** A lso applies to owners or operators of permit - or r ul e

authorized 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 r eg ulations 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 Ac t. Geologic sequestration ( See s ection 35

- 11

- 103(c) of th e 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 ben eath 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 o f 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 three

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.

Site closure “Site closure” means the point/time, as d etermined by the director, at which the owner or operator of a geologic sequestration project is released from post

- injection site care responsibilities. mea ns 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 inje ction, 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 regulationE

- 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 follo wing:

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

**•** M ap showing the injection well, the applicable AoR,

and faults, if known or suspected;

**•** Information on the geologic structure and

hydrogeologic properties ;

**•** T abulation of all wells within the AoR whic h 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 ;

**•** Baselin e geochemica l 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 ;

**•** I njection 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 pla n;

**•** 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, an y States, Tribes, or Territori es 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:

**•** F inal AoR based on modeling, using data obtaine d

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 ) ;

**•** R esults of the formation testing program;

**•** Final injection well construction procedures;

**•** S tatus of co rrective 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 injec t b elow the lowermost USDW submit a supplemental report. appear to sim i lar elements as the federal rule , with greater detail specified in some elements

. See below for details.

(i) A brie f descripti on 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. Additional ly, 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 appro vals 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 Dri nking 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 A ct. (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. (vi i) 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 affec t ed 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 geol ogic structureE

- 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 confi ni ng 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 m ay 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 th e 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 topographi c 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
ge neral 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 an d aq uifers 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 class ification of any groundwaters which may be affected by the proposed discharge. This must include information necessary for the division toE

- 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 Regulati ons; (xii) Baseline geochemical data on subsurface form at ions, 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 mater ials 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 const ruction 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, in cluding 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 interest s 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 surf a ce 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 s tate 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 co mprises:

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

thickness, porosity, and permeability to receive the total anticipated volu me 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, a d ditional 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 appl ication conditions in this state regulation appear to contain sim ilar 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 f aults to become transmissive. (b) Owners or operators of Class VI wells must identify and chara cterize additional zones, if they exist, that will impede vertical fluid movement, allow for pressure dissipation, and provide additional opportunities for monit oring, 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 regi on 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 an d is based on available site characterization, monitoring, and operational data

.

P art 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.

T o delineate the AoR and identify all wells that require corrective action , perform the following :

**•** Predict, using existing site characterization, monitoring

a nd oper at ional 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 differential s 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 th is 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 th e 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 corre ctive 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 timeE

- 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 pen et rations, 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 bri ne 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, r ates 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, fract ures, 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 mann er 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 envir onment. (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 o f 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 c orrective action plan is needed. (f) The emergency and remedial response plan (as requir ed bySection 17) and a demonstration of financial responsibility (as described by Section 18) must account for the entire area of review [as modified], regardless ofE

- 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.)

w hether 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 b y the Directo r, 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.

H ave 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 i nstrument. 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

w ritten approval from the Director.

N otify 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.

P rovide an adjustment of the cost estimate to the Director wit hi n 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 responsibi lity 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 me t, 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 post

injection 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 c arry 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

- in

periods for trust funds or escrow accounts. Construction Requirements §146.86 Injection well construction requirements. Section 9

. Construct ion 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 co me 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 ceme nted 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 federa l 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 k nowledgeable 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 l ogging, sampling, and testing conditions in this state regulation appear to con tain 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 m ay

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

sa mple 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 inj ection 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).

Pro vide the Director with the opportunity to witness all loggi ng 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.

E nsure 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 th e permit.

Inje c tion between the outermost casing protecting USDWs and the well bore is prohibited.

F ill the annulus between the tubing and the long string casing with a non

- corrosive fluid approved by the Director. M aintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines otherwise

.

M aintain 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.

I nsta l l 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 fo r

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, immedi ately investigate and identify as expeditiously as possible the cause of the shutoff. If, upon such investigation, the well appears to b e 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;

**•** Notif y 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 t here is no significant leak in the casing, tubing, or packer; and t here is no significant fluid movement into a USDW t hrough 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 Direct or mus t 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/he r 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 m onitoring 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 analy zing 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 zo nes.

**•** 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 meth ods , unless the Director determines that

such methods are not appropriate;

**•** T he 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 a ssurance 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 meth o ds

. See below for details.

(i) Plans and procedures for environmental surveillance

a nd 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 dis placed 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
pr oposed 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;

**•** Mo nthly 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.

Rega rdless 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

appli c ations 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 col lected 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 ca re 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 P l ugging Plan must include the following information:

**•** Appropriate tests or measures for determining

bottomho le 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 inj ection 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 repo rt 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.

P ar t of the permit application , includes the following :

**•** P ressure differential between pre

- injection and

predicted post

- injection pressures in injection zone(s);

**•** P redicted position of the CO2 plume and associated

pressure front at site closure;

**•** D escription 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 Directo r , 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. M ay 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 non

endangerment of USDWs. The demonstration must be based on site

- specific information, including the results of sit e- 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 an d/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.

M onitor 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.

**•** C ontinue 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 USDW s.

N otify 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.

**•** T he st at e does not specify a period of least 50 years following the cessation of injection

.

**•** T he 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 re te ntion 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. I f 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 th e 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.

S ubmit 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 include s:

**•** Documentation of appropriate injection and monitoring

well plugging. Pr ovide 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.

R ecord 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

**•** V olume of fluid injected, the injection zone (s) it was

injected, and the period over which injection occurred.

R etain for 10 years following site closure, records col l ected during post

- injection site care period. D eliver the records to the Director at the end of the retention period . Retain r ecords 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 r esponse 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 ev i dence 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.

**•** P eriodically review the emergency and remedial

response plan at least once every five years. Amended plans or demonstrations shall be submitted to the Director w ithin one year of an AoR reevaluation; following any significant changes to the facility ; or

w hen 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 t hat described amendments is included in Section 8 of the Wyoming rule, under the AoR delineation conditions, as referenced here. See below for details.

( a) A s part of the permit application, the owner or operator must provide the administrator with an

eme rgency 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, clos ure 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 injec tion 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 environmentE

- 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.