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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAboutCO 207 A • •
Index Conservation Order 207A
PRUDHOE BAY FIELD, LISBURNE OIL POOL
1. October 28, 1996 Arco's request to revised CO 207, Rule 7
2. August 31, 2006 Prudhoe Bay Filed — Annual Surveillance Reporting
requirements to AOGCC
3. February 25, 2008 BPXA administrative request for a Lisburne Gas Cap Water
Injection Pilot Project application
4. March 11, 2008 AOGCC staff comments related to BPXA proposed Lisburne
GCWI application
5. April 22, 2008 BPXA clarification letter dated February 25, 2008 regarding
Request
6. May 22, 2008 Letter from BPXA withdrawing their request that their request
For a Lisburne Gas Cap Water Injection Pilot Project be held
Confidential
7. July 23, 2008 E -mail re: SVS for L5 -29 Pilot Project
8. May 23, 2011 BPXA request for GCWI Pilot Project Extension
Request
Conservation Order 207A
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
3001 Porcupine Drive
Anchorage Alaska 99501-3192
Re: THE APPLICATION OF ARCO ALASKA,
INC. for an order eliminating the requirement
for subsurface safety valves in wells drilled to the
Lisburne Oil Pool.
Conservation Order No. 207 A
Prudhoe Bay Field
Lisburne Oil Pool
December 20, 1996
IT APPEARING THAT:
1. ARCO Alaska, Inc., operator of the Lisburne Oil Pool in the Prudhoe Bay Oil Field, submitted an application
dated October 28, 1996 requesting a revision to Rule 7 of Conservation Order No. 207. The revision would
eliminate the requirement for subsurface safety valves in wells drilled to the Lisburne Oil Pool.
2. Notice of opportunity for public hearing was published in the Anchorage Daily News on November 23, 1996
pursuant to 20 AAC 25.540.
3. No protests to the application were received.
FINDINGS:
1. Commission regulation, 20 AAC 25.265 requires surface (SSV) and subsurface safety valves (SSSV) in
offshore wells capable of unassisted flow of hydrocarbons to the surface. Discretion to require SSV's and
SSSV's in other areas is also provided.
2. Wells capable of unassisted How of hydrocarbons to the surface that arc equipped with both a SSV and a SSSV
arc afforded redundant protection from an uncontrolled flow.
3. Conservation Order 207, Rule 7, requires all wells in the Lisburne Oil Pool capable of unassisted How of
hydrocarbons to the surface to be equipped with a SSV and a SSSV.
4. Previous commission policy was to require multiple safety valves in onshore production wells (for permafrost
areas) capable of unassisted flow of hydrocarbons to the surface.
5. The initial requirement for SSSV's was largely related to concern for the loss of well control from casing
collapse due to freeze back of the permafrost. The magnitude and extent of freeze back forces and appropriate
mitigating well construction techniques, had not been shown through experience to be correctly anticipated
and was not well understood when the requirement for SSSV's was imposed.
6. Wells drilled to the Lisburne Oil Pool have been constmcted using cement formulated for permafrost
conditions, and casing grades and annular fluids capable of preventing appreciable deformation of casing due
to permafrost freeze back.
7. The Commission has no record of an SSSV being used in Alaska to prevent uncontrolled flow from a North
Slope onshore production well.
8. ARCO intends to use a risk based management system which wiII include producing rate, potential for
environmental damage, corrosion concerns, proximity to facilities and populated areas, and economics as
factors in evaluating wells for SSSV removal.
9. SSSV's contribute to higher operating costs, and inereased difficulty and risk for some downhole operations.
10. The Commission has eliminated the requirement for SSSV's in onshore wells in other North Slope oil pools.
(
Conscrvation Ordcr No. 207 A '
Decembcr 20, 1996
Page 3
CONCLUSIONS:
1. SSSV's may reduce ultimatc rccoycry by contributing to highcr opcrating costs, and may increase the chance
of an accidental relcase of hydrocarbons when conducting certain downhole operations.
2. Extensive experience indicates the potential for casing failures through the permafrost due to freeze back has
been greatly reduced by use of appropriate construction techniques in North Slope production wells.
3. SSSV's in Lisburne Oil Pool production wells have provided limited benefit to public safety, environmental
protection or resource recovery.
4. Eliminating the requiremcnt for SSSV's in Lisburne Oil Pool production wclls is not likely to contribute to
waste and may improve safcty of certain well operations and greater ultimate recovery.
NOW, THEREFORE, IT IS ORDERED Rulc 7 of Conservation Ordcr 207 is amended to:
Rule 7. Automatic Shut-in Equipment
(a) Each well shall be equipped with a Commission approved fail-safc automatic surface safety valve system
(SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead.
(b) The SVS shall not be deactivated except during repairs, while engaged in active well work, or if the pad is
manned. If thc SVS cannot bc returned to service within 24 hours, the well must be shut in at the wellhead
and at the manifold building.
1) Wells with a deactivated SVS shall be identified by a sign on thc wellhead stating that the SVS has been
deactivated and the date it was deactivated.
2) A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-
activation dates must be maintained current and available for the Commission on request.
(c) A representative of the Commission will witness operation and performance tests at intervals and times as
prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working
order.
DONE a~~nc~~a~:~ Alaska and datcdCc am"", 20, If . ("\ '\
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f' ~ {I 'I '1.»' ,. ., <....-
l ~lIl ~';;,'~, ~ ~\ David W. Johnston, Chain~aTI-- ~
t. ~¡ ~- Alaska il and Gas Conscf\ llion Commission
\~~~\-:~.-: ~' ut{W/¡JO 1>cG~v{;
\~. "\~ß~'~. \",
\' '"""" ~,w '''¥V.., ...'" i!ø, uckerman Babcoc , Commissioner
~~:~=~~ Alaska Oil and Gas Conservation Commission
AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with
the Conullission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date
of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in
whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affècted
person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing,
both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by
nonaction ofthe Commission, the 30-day period for appeal to Superior Court nllls fì'om the date on which the request is deemed denied
(i.e., lOth day after the application for rehearing was filed).
• •
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7 Avenue, Suite 100
Anchorage, Alaska 99501
Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21
existing Conservation Orders relating to ) Other Order No. 66
well safety valve systems. )
) Statewide, Alaska
) January 11, 2011
IT APPEARING THAT:
1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission (AOGCC
or Commission) formally adopted new regulations relating to well safety valve
systems, at 20 AAC 25.265.
2. The newly adopted well safety valve system regulations underwent final review
by the Regulations Section of the Alaska Attorney General's Office and were
forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010.
3. The new regulations were signed by the Lieutenant Governor and took legal effect
on December 3, 2010.
4. To ensure consistency with the new regulations, the AOGCC, on its own motion,
proposed to rescind part or all of the outdated rules within existing Commission
Orders relating to well safety valve systems.
5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in
the Alaska Daily News notice of opportunity for public hearing on December 6,
2010.
6. The Commission received written comments in response to its public notice, and
held a public hearing on December 7, 2010.
7. Oral testimony and written comments were provided at the December 7, 2010
hearing.
FINDINGS:
1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265,
which consolidates the requirements previously established in legacy documents,
policies, and statewide guidelines relating to safety valve systems.
2. Thirty -four existing Commission Orders contain rules governing well safety valve
systems. Twenty of those Orders contain broad regulatory requirements for safety
valve systems that are now covered by the newly- adopted regulations. The
remaining fourteen Orders include field- or pool - specific safety valve system
requirements.
• Other Order 66 • • Page 2
Statewide, AK
January 11, 2011
3. Within existing Commission Orders are rules unrelated to well safety valve
systems; these rules will continue in effect, unmodified.
4. Existing Commission Orders containing individual rules relating to well safety
valve systems are enumerated in the attached Table.
CONCLUSIONS:
1. Eliminating redundant requirements and standardizing wording for those field -
and pool - specific safety valve system requirements deemed appropriate to retain
will improve regulatory clarity.
2. Twenty existing Commission Orders that include rules relating to well safety
valve systems are rendered unnecessary, and can be replaced by newly- adopted
20 AAC 25.265. As more fully set forth in the attached Table, those Orders are
Conservation Orders 98A, 207A, 300, 311B, 317B, 329A, 341E, 345, 402B,
432D, 452, 457B, 471, 477, 484A, 505B, 553, 559, 570, and a Commission
unnumbered Order signed March 30, 1994 (policy dictating SVS performance
testing requirements).
3. Fourteen existing Commission Orders include field- or pool - specific safety valve
system requirements that the Commission considers appropriate for retention.
Wording for the same safety valve system requirements existing in different
Commission Orders has been standardized. As more fully set forth in the attached
Table, those Orders are Conservation Orders 406B, 423, 430A, 435A, 443B, 449,
456A, 458A, 562, 563, 569, 596, 597, and 605.
NOW, THEREFORE, IT IS ORDERED THAT individual rules in thirty-four existing
Commission Orders that relate to well safety valve systems are hereby rescinded or
revised as enumerated in the Table. Remaining rules unrelated to safety valve systems
within affected Commission Orders remain in effect, unmodified.
DONE at Anchorage, Alaska, and dated . ary 11, 2011
ji. ,--
Daniel T. Se. r ou , r., Commissioner, Chair
. • it . a :. s Conservation Commission
OK fireTrman, Coer 4,,,, ,....
CA co 0
Oil - . . a Conserva ion Commission
3 .,,, . ,,. (., 0,-/ ,p,,
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.p. `. - ,G'' Cat y P. oerst r, Commissioner
r "`'�� Alaska it and Gas Conservation Commission
• Other Order 66 • • Page 3
Statewide, AK
January 11, 2011
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the
Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of
the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration
must set out the respect in which the order or decision is believed to be erroneous.
The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to
act on it within 10 -days is a denial of reconsideration. if the Commission denies reconsideration, upon denial, this order or decision
and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after
the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying
reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which
the application for reconsideration was filed.
If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or
decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That
appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise
distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited
to the questions presented to the Commission by the application for reconsideration."
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in
the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00
p.m. on the next day that does not fall on a weekend or state holiday.
• •
Fisher, Samantha J (DOA)
From: Fisher, Samantha J (DOA)
Sent: Tuesday, January 11, 2011 4:08 PM
To: Ballantine, Tab A (LAW); '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)';
'(Von. L. Hutchins @conocophillips.com)'; 'AKDCWeIIIntegrityCoordinator; 'Alan Dennis';
'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill
Penrose'; 'Bill Waiker'; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon';
'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth';
'caunderwood'; 'Chris Gay; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J.
Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber;
'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe,
Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer; 'Fred Steece'; 'Gary Laughlin'; 'Gary
Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin';
'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne
McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner;
'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon
Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly
Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant; 'Marilyn Crockett'; 'Mark
Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester;
'Marguerite kremer; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel
Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK
Problem Well Supv ,Patty Alfaro ,Paul Decker (paul.decker @alaska.gov) ,Paul Figel;
'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; rob.g.dragnich @exxonmobil.com ,
'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott,
David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR);
Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R.
Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple
Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier'; 'Todd Durkee'; 'Tony
Hopfinger; 'trmjr1'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn';
Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR);
caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr; 'Jason Bergerson';
'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi';
Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins';
'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA)
(winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov);
Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA)
(john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster,
Catherine P (DOA) (cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA)
(lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov); Jones,
Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov);
Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA)
(bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov);
Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman,
John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA)
(howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @ alaska.gov);
Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA)
(jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C
(DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov);
Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA)
(dan.seamount @alaska.gov); Shartzer, Christine R (DOA)
Subject: Other 66 Safety Valve Systems
Attachments: other66.pdf
Sa41(LCA,Y1tha/ Fi 4'
AZ a k a Oa/ c 4 d c a4'Cair. twat vCvvYwi iow
(907)793 -1223
(907)276 (fww)
1
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• •
Mary Jones David McCaleb
XTO Energy, Inc. IHS Energy Group George Vaught, Jr.
Cartography GEPS P.O. Box 13557
810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557
Ft. Worth, TX 76102 -6298 Houston, TX 77056
Jerry Hodgden Richard Neahring Mark Wedman
Hodgden Oil Company NRG Associates Halliburton
President
408 18 Street 6900 Arctic Blvd.
Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502
Colorado Springs, CO 80901
Bernie Karl CIRI
K &K Recycling Inc. Land Department Baker Oil Tools
P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct.
Anchorage, AK 99515 -4295
Fairbanks, AK 99711 Anchorage, AK 99503
North Slope Borough Jill Schneider Gordon Severson
P.O. Box 69 US Geological Survey 3201 Westmar Circle
Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336
Anchorage, AK 99508
Jack Hakkila Darwin Waldsmith James Gibbs
P.O. Box 190083 P.O. Box 39309 P.O. Box 1597
Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669
Kenai National Wildlife Refuge
li
Penny Vadla Cliff Burg lin
Refuge Manager y g
P.O. Box 2139 399 West Riverview Avenue 319 Charles Street
Soldotna, AK 99669-2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701
Richard Wagner
P.O. Box 60868
Fairbanks, AK 99706
Orders Establishing Requirements for Well Safety Valve Systems
1/7/2011
Conservation New Regulation Provisions Revised Rule - "Well safety valves stems" (2) Comment
Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Regts from Order y systems" )
fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve
single check valve and SSV; injection
25.265(a); 25.265(b); 25.265(d)(2)(H); arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by
Colville River Unit Qannik 605 5 no (i ) double check valve, or (ii) ng 25.265(h)(5) readopted regulation
valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve."
fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve
25.265(a); 25.2659(b); 25.265(d)(1); Check valve requirements for injectors are not covered by
Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation
valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve."
fail -safe auto SSV and SCSSV; injection wells (except disposal) require
25.265(a); 25.265(b); 25.265(d)(1); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by
Oooguruk Oooguruk - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection .265 h 5 arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or
25 readopted regulation
valve satisfies single check valve requirement; test every 6 months ( )( ) SCSSV satisfies the requirements of a single check valve."
fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with
Prudhoe Bay Unit Raven 570 5 yes sign on wellhead 25.265 m N/ deactivated SVS was replaced with requirement to maintain a
deactivated SVS; si
9 ( ) tag on well when not manned
fail -safe auto SSV and SCSSV; injection wells (except disposal) require
25.265(a); 25.265(b); 2 5. 265 ( d )( 2 )( H ); "I wells (excludin dis injectors) must be equipped with(i) a double check valve
Check valve requirements for injectors are not covered by
Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or
25.265(h)(5) readopted regulation
valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve"
fail -safe auto SSV and SCSSV; injection wells (except disposal) require
25.265(a); 25.265(b); 25.265(d)(2)(H); Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by
Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or
25.265(h)(5) readopted regulation
valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve."
fail -safe auto SSV and SCSSV; injection wells (except disposal) require
25.265(a); 25.265(b); 2 5. 26 5( d )( 2 )( H ); "I w ells (excluding disposal injectors) must be equipped with(i) a double check valve
Check valve requirements for injectors are not covered by
Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or
25265 h readopted regulation
valve satisfies single check valve requirement; test every 6 months )( 5 ) SCSSV satisfies the requirements of a single check valve."
fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay Unit Put River 559 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells
Deep Creek Unit Happy Valley 553 3 yes SSV or SSSV 25.265(a) N/A
fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay Unit Orion 505B 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells
fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay Unit Polaris 484A 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells
Milne Point ted fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI Readopted 25.265
25.265(a); 25.265(b); 25.265(d); p 25.265(d) dictates which wells require SSSV;
Milne Point Unit Schrader Bluff 477 5 yes injection well require SSSV or injection valve below permafrost; test 25.265(h)(5) N/A replaces SSSV nipple requirement for all wells
every 6 months
Prudhoe Ba Unit Borealis 471 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Y Y injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells
fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500- Existing pool rule established a minimum setting depth for the
Northstar Northstar 458A 4 no ft minimum setting depth for SSSV 25.265(a); 25.265(b); 25.265(d)(1) "The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." SSSV
fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay Unit Aurora 457B 3 yes months 25.265(h)(5) replaces SSSV nipple requirement for all wells
fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by
Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include
check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors
fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay Unit Midnight Sun 452 6 yes flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells
fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.265(a); 25.265(b); 25.265(d)(1); "The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth;
Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by
pressure; test every 6 months 25 arrangement." readopted regulation
fail -safe auto SSV and SCSSV (producers and gas injectors); water "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve
Check valve requirements for injectors are not covered by
Colville River Unit Alpine 443B 5 no injection wells require (i) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or
and SSV SCSSV satisfies the requirements of a single check valve." readopted regulation
fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d);
"Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by
Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include
check valve, or (ii) single check valve and SSV; test every 6 months 25.26 SCSSV satisfies the requirements of a single check valve." SSSV requirement for Mt injectors
fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with
deactivated; maintain list of wells w /deactivated SVS; test as 25.265(x); 25.265(b); 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a
Kuparuk River Unit; to on well when not manned; administrative approval CO
25 m
Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP N/A 9 pP
Milne Point Unit may be defeated on W. Sak injectors w /surface pressure <500psi w/ 25.265(m) 432D.009 remains effective [re:defeating the LPS when surface
notice when defeated and placed back in service injection pressure for West Sak water injector is <500psi]
Page 1 of 2
Orders Establishing Requirements for Well Safety Valve Systems
1/7/2011
Conservation New Regulation Provisions Revised Rule - "Well safety valves stems' (2) Comment
Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Regts from Order y systems" ( )
fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by
Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include
check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors
Milne Point - Sag fail -safe auto SSV; injection wells require double check valve; test j q pp 9 Check valve requirements for injectors are not covered by
423 7 n
Milne Point Unit 6 months 25.265(a); a ) ; 25.265 ( b ) ; 25.265(h)(5) h )( 5 ) In ection wells must be ui ed with a double check valve arran ement."
e very
River readopted regulation
fail -safe auto SSV; gas /MI injectors require SSV and single check Check valve requirements for injectors are not covered by
valve and SSSV landing nipple; water injection wells require (i) double "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve readopted regulation; readopted 25.265(d)(5) does not include
check valve, or (ii) single check valve and SSV; test every 6 months; 25.265(a); 25.265(b); 25.265(d); arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or SSSV requirement for MI injectors; administrative approval CO
Kuparuk River Unit Kuparuk - West Sak 406B 6 no CO 4068.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve The Low Pressure Pilot may be
406B.001 remains effective [re:defeating the LPS when surface
injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." injection pressure for West Sak water injector is <500psi]
placed back in service
fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible
Badami Badami 402B 6 yes control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A
submit test results electronically within 14days; SVS defeated /removed 25.265(m)
only if well SI or pad continuously manned
fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(x); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with
Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as N/A
25.265(m) deactivated SVS was replaced with requirement to maintain a
prescribed by Commission . 265(m) tag on well when not manned
fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must
Unit Prudhoe 341E 5 yes be maintained and tested as part of SVS; sign on well if SVS 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells
prescribed by Commission
Unit Niakuk 329A 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells
fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay Unit Pt. McIntyre 317B 8 yes routine well ops w/o notice 25.265(1); 25.265(m) replaces SSSV nipple requirement for all wells
Unit West Beach 311 B 6 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wets
West Fork (Sterling
West Fork A &B) 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A
fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with
Prudhoe Bay Unit Lisburne 207A 7 yes N/A deactivated SVS was replaced with requirement to maintain a
Y w /deactivated SVS; test as prescribed by Commission 25.265(m) tag on well when not manned
suitable automatic safety valve installed below base of permafrost to 25.265 d N/A Readopted 25.265(d) dictates which wells require SSSV;
Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes prevent uncontrolled flow ( ) replaces SSSV nipple requirement for all wells
Commission policy dictating SVS performance testing AOGCC Policy - SVS Failures; issued by order of the
Statewide N/A N/A N/A yes 25.265(h); 25.265(n); 25.265(o) N/A Commission 3/30/1994 (signed by Commission Chairman
requirements Dave Johnson)
Footnotes
(1) No SVS rules found in Injection Orders
(2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded
Page 2 of 2
• •
Public Hearing Record
And
Backup Information available in Other 66
•
~ ~~ ~ ~
d ~ 3 i_0..
~ p' ` ~ ~ SARAH PALIN, GOVERNOR
~T L~ilt~~7~L')• ~~ ~``~7sT 333 W 7th AVENUE, SUITE 100
CU"S~RQA-~~i` CO~~-7''-7'`ID„ ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
ADMINISTRATIVE APPROVAL CO 207A.001
ADMINISTRATIVE APPROVAL AIO 4E.029
Ms. Diane Richmond
GPMA Resource Manager
BP Exploration (Alaska), Inc.
PO Box 196612
Anchorage, AK 99519-6612
Re: The application from BP Exploration (Alaska), Inc. to conduct a pilot waterflood test
involving the injection of Beaufort seawater into Well LS-29, within the gas cap of the
Lisburne Oil Pool, Prudhoe Bay Field, Alaska.
Dear Ms Richmond:
By letter dated February 25, 2008, and supplemented on April 22, 2008, BP Exploration
(Alaska), Inc. (BPXA), operator of the Lisburne Oil Pool (Lisburne), requests administrative
approval to conduct a pilot gas cap water injection (GCWI) test using Lisburne well LS-29 (Well
LS-29). By letter dated May 13, 2008, BPXA requested all materials supplied within their
request be held confidential. This request was withdrawn by letter dated May 22, 2008. The
Alaska Oil and Gas Conservation Commission (Commission) hereby grants BPXA's request for
administrative approval to inject water into the Lisburne gas cap as part of an enhanced oil
recovery pilot project using Well LS-29, subject to the rules set out at the end of this order. The
pilot project is referred to as the LS GCWI Pilot Project.
Findings•
Lisburne Oil Pool
The Lisburne Oil Pool is defined in Conservation Order 207 (CO 207) as the accumulations of
oil and gas that occur in stratigraphic sections correlating with the stratigraphic section in the
Atlantic Richfield-Humble Prudhoe Bay State No.l well between 8,790 feet measured depth
(MD) and 10,440 feet MD.
Authority
Area Injection Order 4E (AIO 4E) sets out rules for Class II injection into the Eastern Operating
Area of the Prudhoe Bay Field, including the strata of the Lisburne Oil Pool.
i
ADMINISTRATIVE APPROV~CO 207A.001 and AIO 4E.029
June 4, 2008
Page 2 of 7
Under CO 207, Rule 12, the Commission may administratively approve Lisburne Oil Pool field
pilot projects, well production and injection tests and other field operations necessary for
developing a prudent enhanced recovery method and reservoir depletion program.
LS GCWI Pilot Project Scope, Maximum Injection Rates and Pressures
The LS GCWI Pilot Project involves injecting Beaufort seawater into Well LS-29, which has
been shut-in since 1997, using existing gas cap perforations from 13,585' MD - 13,634' MD,
8,498'-8,525' true vertical depth subsea (TVDSS). The top of the proposed injection zone is at
1,138' FNL, 1,313' FEL, Sec. 34, T12N, R15E, UM.
Beaufort seawater will be piped to the well through a 6" line that will be tied into the nearby
Niakuk Oil Pool (Niakuk) seawater pipeline. Rates of up to 20,000 barrels of water injected per
day (BWIPD) are anticipated in early stages of the proposed pilot project: average injection
rates of 10,000 BWIPD are anticipated over the proposed 3-year pilot period. Injection pressures
will be maintained below the hydraulic fracture gradient (i. e., roughly 0.55 psi/ft). However,
near-wellbore thermal fracturing may occur due to cold water injection.
Pool Description, Geolo~y
The Lisburne Reservoir is a combination structural and stratigraphic trap of carbonate lithology.
It is an anticlinal structure bounded by the Prudhoe Bay-Niakuk fault complex on the north,
Lower Cretaceous Unconformity truncation to the east, and Pre-Echooka Unconformity
truncation to the west. The unitized intervals are Mississippian/Pennsylvanian age and include
the Alapah and Wahoo Formations of the Lisburne Group. The LS GCWI Pilot Project will inject
sea water into only the Wahoo Formation.
Throughout the entire LS GCWI Pilot Project area significant shale intervals are deposited on top
of the Lisburne Wahoo Formation (Wahoo). At Well LS-29, there is an HRZ shale interval
exceeding 200 true vertical depth (TVD) feet thick. Below the pilot project area are several
hundred feet of predominantly non-pay Wahoo and a large shale interval separates the Wahoo
and Alapah Formations.
The Lisburne Reservoir is very complex, with extreme permeability variations. A complex
fracture and faulting system provides a pathway to allow production from tight matrix rock.
Cores taken throughout the Lisburne Reservoir show permeabilities in pay intervals of less than
0.1 millidarcies to over one hundred millidarcies.
Reservoir Production History
The Lisburne Reservoir production history is shown on the following page. Long-term
production testing began in 1985, and sustained full-field production began in 1987.
A pilot waterflood test was conducted at Lisburne Drill Site L2 (L2) from 1987 to 1989. Water
breakthrough was much faster than expected, and the Lisburne owners abandoned further
attempts at waterflood.
Lisburne Reservoir production is limited by the gas handling capacity of the Lisburne Production
Center (LPC). In 1994, the LPC began processing production from the Pt. McIntyre and Niakuk
• •
ADMINISTRATIVE APPROVAL CO 207A.001 and AIO 4E.029
June 4, 2008
Page 3 of 7
Oil Pools, and many Lisburne wells were shut-in due to non-competitive gas oil ratios (GORs).
From 1997 to 2007, fewer than 41 of 79 Lisburne Oil Pool wells have been active during any
month.
In 2007, production averaged 10,222 stock tank barrels per day (STB/D) oil and 1,457 STB/D
natural gas liquids (NGLs), with an average GOR of roughly 21 thousand standard cubit feet
(Mscf)/STB and an average water cut of 39%. The gas injection rate averaged 139 Mscf/D.
Cumulative production through 2007 was 149.7 million STB oil, which, based on an OOIP of 2
billion STB, is less than 8%; 15.2 million STB NGL; 1,647 billion SCF gas; and 42.4 million
barrels water. Injection totaled 1,604 billion SCF gas, and 8.8 million barrels water. The current
average reservoir pressure is about 3,200 pounds-force per square inch absolute (psis).
PRUDHOE BAY, LISBUR~E o1L
Oil ancJ Associated Gas Production
aD
3D
20
u
10000
5D00
1D00
500
100
FQ
10
F
1
1D00
500
00
50
10
ri
1
C ~.
C 1
t=ag Inj Rate ;~.C3) ~; h/IF.•tc(.'cl 7 ~,^:'ater Rate (t::~} (M3,t:lfe3 )
Gas Rate iC•D} { Miiv'cf.!d - .._= v'Vater Inj R,~te (t..E7,1 (riAt>bled )
(]Ft Rate (CD3 (Mt>hl.+d } ~,Ie~L Rate is=C3) t Niht>llh }
. `
S `~
._ ~' ~
1981 83 85 87 89 91 93 95 ~T vy U1 U:3 V^., u+
ADMINISTRATIVE APPROV~CO 207A.001 and AIO 4E.029
June 4, 2008
Page 4 of 7
Project Benefits
A large scale Prudhoe Oil Pool Gas Cap Water Injection Project has been ongoing since 2002.
There have been some early favorable results. Compared to water displacing oil, the gas cap
water injection mechanism of water displacing gas has a more favorable mobility ratio.
Mechanistic model studies performed by BPXA suggest that water injection at Lisburne may act
as a blocking agent within the highly fractured and faulted intervals and inhibit the movement of
injected gas from the west toward the LS producers, thereby allowing wells to be brought on line
which would otherwise remain shut-in due to high GORs. In the model, modest sweep benefits
and increased reservoir pressures also contributed to higher oil recovery, and no unfavorable
water movement was observed.
Incremental oil production during the proposed 3-year LS GCWI Pilot Project may equal 500,000
STB. If the pilot project is successful, BPXA estimates that over 10 million STB of incremental
oil production will result over 20 years. The Niakuk line is adequately sized, and the water needs
at Niakuk have decreased, so a negative impact on Niakuk oil recovery is not expected.
The reservoir model suggests injected water arriving to producers after 2 years. The GOR trends
of nearby wells used as an analogue for injection water movement suggest breakthrough could
happen between 3 months and 2+ years after gas cap water injection begins. In the event of a
rapid breakthrough of water to producers, the producers are at a sufficiently high reservoir
pressure that, with gas lift assist, the water can be produced easily. Oil production at L2
ultimately returned to normal after the L2 waterflood pilot project was completed, and while oil
production decreased during the water injection, the production returned after the waterflood was
shut down.
BPXA has estimated the impact on gas reserves during the LS GCWI Pilot Project. The impact
of water injection on gas reserves is the difference between (A) the additional gas recovered
because of (1) increased reservoir pressure and (2) the displacement of gas from the matrix by
the injected water, and (B) the volume of gas trapped in the matrix because of the higher
abandonment pressure. BPXA does not believe that the ultimate recovery of gas will be
negatively affected by the 3-year pilot project or a 20-year gas cap water injection project.
BPXA's calculations suggest that small increases in ultimate gas reserves could result if either
project is successful.
Fluid Compatibility, H2S, Corrosion
Scaling tendencies were studied with mixtures of Lisburne produced water and seawater at
various ratios. There is insufficient barium in produced water or seawater to cause a barium
sulfate problem. There is a slight increased tendency for calcium carbonate scaling at low
seawater ratios; this tendency decreases as the concentration of brine increases to more than 50%
of the fluid production. Calculations run for CaSO4, BaSO4, SrSO4.2H2O and NaCL show no
scaling tendencies.
At the Commission's request, BPXA reviewed the level of increased hydrogen sulfide (H2S)
concentrations as a result of the impact of the introduced seawater, and whether tubulars and
surface facilities are designed to prevent hydrogen embrittlement from increasing H2S
concentrations. BPXA notes that metallurgy used throughout the Lisburne facilities and
ADMINISTRATIVE APPROV~CO 207A.001 and AIO 4E.029
June 4, 2008
Page 5 of 7
flowlines were originally designed for H2S production in accordance with Piping Materials
Specifications. The highest H2S readings have been recorded in production from Drill Site L4
wells in the southeastern portion of the field, with a peak reading of over 1,500 parts per million
(ppm). The H2S concentrations have steadily declined to less than 400 ppm. There have been
no known well failures as a result of H2S concentrations in this area.
Model calculations indicate a maximum potential H2S concentration of 1,362 ppm, irrespective
of transit time from injector to producer, for the duration of injection. Because of the high
volume of gas in the LS area, the model predicts that dilution will result in H2S levels remaining
within current flowline and facility H2S limits. There is no evidence of H2S-induced failures in
Lisburne wellbore tubulars. When wells are worked over, tubulars are replaced with chrome
tubing to minimize corrosion. Lisburne already has a number of high water producing wells, and
the LS GCWI Pilot Project is not expected to introduce corrosion mechanisms that are different
from those now being addressed in the field.
Infection Pressures and Rates
Injection pressures will be continuously monitored and regulated to reduce the risk of premature
breakthrough in productive wells. Water injection pressure will be kept below the average
Wahoo Formation fracture pressure of 0.55 psi/ft. The maximum injection rate will be less than
20,000 BWIPD.
Underground Sources of Drinking Water
As found in AIO 4, no known sources of drinking water exist in the Eastern Operating Area of
the Prudhoe Bay Unit, including that area overlying the Lisburne Oil Pool.
Mechanical Integrity of Injector LS-29 and Adjacent Producing Wells
Well LS-29 passed mechanical integrity tests on September 2, 2005 and March 18, 2007.
Neither test was witnessed by a Commission Inspector. Recent wellhead pressure data provided
by BPXA confirms the well's sound mechanical integrity: there is no indication of pressure
communication to any of the well's annular spaces. Drilling, casing and cementing records and cement
integrity logs generated during the well's construction confirm that there is no significant flow of injected
fluid behind pipe. Caliper recordings provided by BPXA confirm the 7" tubing is in good condition, with
no significant wall penetrations.
No wells are within a'/4-mile radius of Well LS-29 at the point it penetrates the Lisburne gas cap. BPXA
provided well integrity information for offset wells LS-25, LS-36, LS-33, and LS-21. This information
indicates that none of these wells would serve as a pathway for injected fluids to migrate out of
confinement.
Conclusions:
1. Waterflooding is unproven as a method to increase oil reserves in the Lisburne, and few
analogues exist for gas cap water injection in carbonate reservoirs.
2. AIO 4E permits Class H injection into Lisburne strata.
ADMINISTRATIVE APPROV~CO 207A.OOi and AIO 4E.029
June 4, 2008
Page 6 of 7
3. Under CO 207, Rule 12, the Commission may administratively approve Lisburne Oil Pool
field pilot projects, well production and injection tests and other field operations necessary
for developing a prudent enhanced oil recovery method and reservoir depletion program.
4. Sufficient information exists to authorize the LS GCWI Pilot Project: i. e., water injection
into Lisburne Well LS-29 in existing Zone 6 perforations from 13,5$5' MD -13,634' MD,
8,552' TVDSS -8,585' TVDSS, to evaluate the enhanced oil recovery potential presented by
seawater injection into the Lisburne gas cap.
5. No wells penetrate the Lisburne Oil Pool within a'/4-mile radius of the Well LS-29 injection
zone. Annuli pressures in offset wells LS-25, LS-21, LS-33 and LS-36 should be monitored
and reported to the Commission to ensure injected fluids remain confined to the injection
zone.
6. There are no potential sources of underground drinking water beneath the permafrost in the
area of the Lisburne Oil Pool.
7. Injection pressure should be monitored to ensure that injection pressures remain below the
estimated fracture pressure of 0.55 psi/ft.
8. Injected fluids will be confined within the appropriate receiving interval by impermeable
lithology, cement isolation of the wellbore and appropriate operating conditions.
9. Well surveillance will help demonstrate the performance of the pilot injection project and
disclose possible problems.
10. Mechanical integrity testing should be performed on the well once injection has commenced,
as outlined in AIO 4E.
Aauroval and Conditions:
In accordance with CO 207A and AIO 4E, the Commission approves BPXA's request to conduct
the LS GCWI Pilot Project: i.e., to inject seawater into the Lisburne gas cap through Well LS-29
to evaluate the potential for enhanced Lisburne oil recovery. BP must comply with all provisions
of AS 31.05, 20 AAC 25, and any other orders or permits of the Commission that are not
inconsistent with this order. This approval is conditioned upon the following:
1. water injection is authorized into Well LS-29 only and is limited to perforations within the
upper Wahoo Formation (Zone 6) between 13,585' MD and 13,634' MD;
2. the Well LS-29 injection rate is limited to 20,000 BWIPD;
3. injection pressures must be maintained below 0.55 psi/ft;
4. by June 15'~ of each year, the operator must provide the Commission a surveillance report,
including the following information:
a. a summary of the LS GCWI Pilot Project and an analysis of injection and production
performance and pressure and GOR response from injection;
b. information concerning reservoir pressure, including reservoir pressure changes since
the injection started;
c. the results, and an analysis of, production and injection log surveys; and
d. a review of any specialized tests performed to gauge the performance and results of
the pilot project;
i
ADMINISTRATIVE APPROVAZ CO 207A.001 and AIO 4E.029
June 4, 2008
Page 7 of 7
5
6.
7.
no later than three months after the pilot project ends, a final report must be submitted to the
Commission; the report must include the information required in Condition 5 above, an
analysis of the hydrocarbon reserve benefits of the pilot project, and a summary of future
plans for enhanced oil recovery in Lisburne; and
annuli pressures in offset wells LS-21, LS-25, LS-33 and LS-36 must be monitored daily and
reported to the Commission monthly.
This pilot project appro`
ENTERED at Anchorage, Ala
Daniel T. Seamount, Jr.
Chair
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such
further time as the Commission grants for good cause shown, a person affected by it may file with the Commission
an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time
shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is
believed to be erroneous.
The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it
is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies
reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be
appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission
mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration,
UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which
the application for reconsideration was filed.
If the Commission grants an application for reconsideration, this order or decision does not become final. Rather,
the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be
appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission
mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided
in AS 31.05.080(b), "[t]he questions reviewed on appeal. are limited to the questions presented to the Commission
by the application for reconsideration."
In computing a period of time above, the date of the event or default after which the designated period begins to run
is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in
which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday.
Mary Jones David McCaleb Cindi Walker
XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co.
Cartography GEPS Supply & Distribution
810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive
Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216
George Vaught, Jr. Jerry Hodgden Richard Neahring
PO Box 13557 Hodgden Oil Company NRG Associates
Denver, CO 80201-3557 408 18th Street President
Golden, CO 80401-2433 PO Box 1655
Colorado Springs, CO 80901
John Levorsen Michael Parks Mark Wedman
200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton
Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd.
Seattle, WA 98119-3960 Anchorage, AK 99502
Baker Oil Tools Schlumberger Ciri
4730 Business Park Blvd., #44 Drilling and Measurements Land Department
Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330
Anchorage, AK 99503 Anchorage, AK 99503
Ivan Gillian Jill Schneider Gordon Severson
9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr.
Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336
Anchorage, AK 99508
Jack Hakkila Darwin Waldsmith James Gibbs
PO Box 190083 PO Box 39309 PO Box 1597
Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669
Kenai National Wildlife Refuge Penny Vadla Richard Wagner
Refuge Manager 399 West Riverview Avenue PO Box 60868
PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706
Soldotna, AK 99669-2139
Cliff Burglin Bernie Karl North Slope Borough
PO Box 70131 K&K Recycling Inc. PO Box 69
Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723
Fairbanks, AK 99711
Williams Thomas
Arctic Slope Regional Corporation
Land Department
PO Box , 29
Barrow, AK 99723 ~ /l/vt~/
~Q ~~
Y
Page 1 of 1
Colombie, Jody J (DOA)
From: Colombie, Jody J (DOA)
Sent: Wednesday, June 04, 2008 2:32 PM
Subject: C0207A.001 Lisburne
Attachments: C0207a.001.pdf
BCC:'Dale Hoffman'; Fridiric Grenier; Joseph Longo; Maurizio Grandi; Tom Gennings; 'Willem
Vollenbrock'; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara
F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock';
'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan';
caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff
Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L
Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric
Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland
Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg
M (DEC); 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr';
'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks';
'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-
slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles';
keelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda
Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton';
'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'Meghan
Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson';
'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty
Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern';
'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert
Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick';
'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj';
'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson';
'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter
Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA);
Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine
M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder,
Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman,
John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg,
James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA);
Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA)
Attachments:C0207a.001.pdf;
Jody Colombie
Special Assistant to the Commission
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
(907) 793-1221 Direct Line
(907) 276-7542 Fax
6/4/2008
• •
STIATIE 0[F ALASKA SEAN PARNELL, GOVERNOR
ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100
CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539
PHONE (907) 279 -1433
FAX (907) 276 -7542
ADMINISTRATIVE APPROVAL CO207A.002
ADMINISTRATIVE APPROVAL AIO4E.038
Mr. David J. Szabo
Head of Reservoir Management
Alaska Resource Team
BP Exploration (Alaska), Inc.
P.O. Box 196612
Anchorage, AK 99519 -6612
RE: Lisburne Gas Cap Water Injection Pilot Project Extension Request
Dear Mr. Szabo:
By letter dated May 23, 2011, BP Exploration (Alaska), Inc. (BPXA) requested that the
Alaska Oil and Gas Conservation Commission (Commission) grant a 5 year extension to
the Lisburne Gas Cap Water Injection (GCWI) Pilot Project initially authorized by the
Commission on June 4, 2008, by CO207A.001 and AIO4E.029. In accordance with with
Rule 12 of Conservation Order (CO) 207A and Rule 9 of Area Injection Order (AIO) 4E
and under the authority of 20 AAC 25.450(b), the Commission hereby grants BPXA's
request for a five -year extension.
On June 4, 2008, the Commission granted BPXA authorization to conduct a pilot GCWI
in the Lisburne Oil Pool. Condition 7 of this approval established July 1, 2011, as the
expiration date of the pilot project. To date approximately 5.5 MMBW have been
injected as part of this pilot project. Although results have thus far been encouraging
additional data needs to be collected and analyzed to determine the viability of expanding
GCWI in the Lisburne Oil Pool from a pilot project to full field development. Data to be
gathered during the extended pilot project include:
1. Observation of matrix bypass,
2. Information necessary to determine incremental oil recovery,
3. Enhanced understanding of the GCWI mechanism at work in the Lisburne Oil
Pool, and
4. Confirmation that pressure responses noted in offset producers is due to the
GCWI pilot project and not due to some other as yet unknown reason.
CO207A.002 •
AIO4E.03 8
June 17, 2011
Page 2 of 2
The Commission's administrative approval to change the expiration date of the Lisburne
Oil Pool GCWI Pilot Project from July 1, 2011, to July 1, 2016, is conditioned upon the
following:
1. BPXA shall continue to comply with all of the conditions in CO207A.001 and
AIO4E.029; and
2. BPXA shall submit interim pilot project reports, which contain all information
required by Condition 5 of the prior authorization, no later than October 1, 2011,
and October 1, 2014. These interim reports shall be based on data obtained
through July 1, 2011, and July 1, 2014, respectively.
Additionally, to correct a typographical error in the prior authorization, Condition 5 of
CO207A.001 and AIO4E.029 is amended to read as follows:
5. no later than three months after the pilot project ends, a final report must be
submitted to the Commission; the report must include the information required in
Condition 4 above, an analysis of the hydrocarbon reserve benefits of the pilot
project, and a summary of future plans for enhanced oil recovery in Lisburne; and
DONE at An or. ge, Alaska and dated June 17, 2011. ou. AND
p h
J 4 .! orman 'athy ' . Foe ster
C% r ql , '�
I
is - r Commissioner °its
ktrioS
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission
grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined
by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the
order or decision is believed to be erroneous.
The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it
within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of
reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the
Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is
by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed.
If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed
within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on
reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission
by the application for reconsideration."
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period;
the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day
that does not fall on a weekend or state holiday.
• •
Fisher, Samantha J (DOA)
From: Fisher, Samantha J (DOA)
Sent: Friday, June 17, 2011 12:54 PM
To: '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)';
'AKDCWelllntegrityCoordinator ; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara
F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brady, Jerry
L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce
Webb'; 'caunderwood'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa';
'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott'; 'David
Steingreaber'; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elizabeth Bluemink'; 'Elowe, Kristin';
'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary
Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov); 'ghammons'; 'Gordon Pospisil'; 'Gorney,
David L.'; 'Greg Duggin; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington
(jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones
(jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner';
'Joe Nicks'; 'John Garing'; 'John Katz (john.katz @alaska.gov)'; 'John S. Haworth; 'John
Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty; 'Kaynell Zeman';
'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant
(laura.gregersen @ alaska.gov); 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley
(mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Marguerite kremer
(meg.kremer @alaska.gov)'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason';
'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover';
'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel';
'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish';
'rob.g.dragnich @e)oonmobil.com; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman';
'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland';
Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert';
'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson';
'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa lmm';
'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger; 'trmjrl'; 'Vicki
Irwin; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron
Gluzman'; 'Ben Greene'; Bruno, Jeff J (PCO); 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich';
'Eric Lidji'; 'Gary Orr'; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Joe Longo'; King,
Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff;
'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Patricia Bettis; 'Richard Garrard';
'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Van
Dyke'; Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Ballantine, Tab A (LAW);
Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA)
(jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen
F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA)
(cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Herrera,
Matt F (DOA); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B
(DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder,
Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA)
(bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov);
Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman,
John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA)
(howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov);
Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA)
(jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C
(DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov);
Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA)
(dan.seamount @alaska.gov)
Subject: co207a -002 & aio4e -038 Lisburne
Attachments: co207a -002 & aio4e- 038.pdf
1
•
Mary Jones David McCaleb
XTO Energy, Inc. IHS Energy Group George Vaught, Jr.
Cartography GEPS P.O. Box 13557
810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557
Ft. Worth, TX 76102 -6298 Houston, TX 77056
Jerry Hodgden Richard Neahring Mark Wedman
Hodgden Oil Company NRG Associates Halliburton
408 18 Street President 6900 Arctic Blvd.
Golden, CO 80401 -2433 P. Box 1655 Anchorage, AK 99502
Colorado Springs, CO 80901
Bernie Karl CIRI
Baker Oil Tools
K &K Recycling Inc. Land Department h
7 E
P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct.
Anchorage, AK 99515 -4295
Fairbanks, AK 99711 Anchorage, AK 99503
North Slope Borough Richard Wagner Gordon Severson
Planning Department P.O. Box 60868 3201 Westmar Circle
P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336
Barrow, AK 99723
Jack Hakkila Darwin Waldsmith James Gibbs
P.O. Box 190083 P.O. Box 39309 P.O. Box 1597
Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669
Kenai National Wildlife Refuge Penny Vadla Cliff Burglin
Refuge Manager 399 West Riverview Avenue 319 Charles Street
P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701
Soldotna, AK 99669 -2139
1 \kCji\' "1 \ \ \*
1 I f
i
b p •
David J. Szabo
BP Exploration (Alaska) Inc.
Head of Reservoir Management
Alaska Resource Team 900 East Benson Boulevard
PO Box 196612
_ Anchorage, AK 99519 -6612
� a (907) 564 -5111
May 23, 2011 ¢ :,
Phone: (907) 564 -4788
r` Fax: (907) 564 -5706
w Email SzaboDJ @bp.com
fit Web: www.bp.com
wa rooms
Daniel T. Seamount, Jr., Chair
Alaska Oil and Gas Conservation Commission
333 W. 7 Ave. #100
Anchorage, Alaska 99501 -3539
RE: Lisburne Gas Cap Water Injection (GCWI) Pilot Project Extension Request
Dear Mr. Seamount:
BP Exploration (Alaska) Inc. (BPXA), acting in its capacity as Operator of the Prudhoe
Bay Unit (PBU) and on behalf of the other PBU Owners: Chevron USA, Inc.,
ConocoPhillips Alaska, Inc., and ExxonMobil Alaska Production Inc., requests
approval of an Alaska Oil and Gas Conservation Commission Administrative Action
under Lisburne Area Injection Order No. 4E (Rules 1 & 9) and Conservation Order No.
207 (Rule 12) to extend the term of the gas cap seawater injection L5 -29 pilot project
in the Lisburne Reservoir (see enclosed plat for well location). The L5 -29 GCWI was
originally approved by the AOGCC on June 4, 2008 for a period of three years. The
pilot approval period expires on July 1, 2011, and BP is requesting an extension for
five years to July 1, 2016 to allow enough time to observe matrix breakthrough,
incremental oil benefits, and obtain a better understanding of the gas cap water
injection mechanism than is possible with our current data. A report summarizing the
L5 -29 pilot results to date will be submitted to AOGCC by October 1 2011, three
months after the original pilot ends, to document our understanding for the first three
years of injection.
Over the three -year pilot period, water injection rates have been systematically
increased, averaging approximately 7,000 BWPD and never exceeding the limit of
20,000 BWPD, per Administrative Approvals CO 207a.001 and AIO 4E.029.
Cumulative seawater injection is 5.5 MMBW.
The L5 -29 pilot injection to date has demonstrated positive results with no water
breakthrough. Observed reservoir pressure increases in offset producers could be
related to the GCWI at L5 -29. Observations over a longer injection period are
necessary to confirm these pressure responses.
Lisburne Gas Ca p Water Iction (GCWI) Pilot Project Extension Request
May 23, 2011
Page 2
For concerns or questions regarding this extension request, please contact David
Lenig at 907 - 564 -5301 or Bob Jennings 907 - 564 -5505.
Best Regards,
,9,_74, X-6
David J. Szabo
cc: John Garing, BPXA
David Lenig, BPXA
RL Skillern, BPXA
Gary Benson, BPXA
Judy Buono, BPXA
Don Ince, ConocoPhillips
Dan Kruse, ConocoPhillips
Cam Cheal, ExxonMobil
Gerry Smith, ExxonMobil
Mark Agnew, ExxonMobil
Phil Ayer, Chevron
Patricia Bettis, DO &G
Cammy Taylor, DO &G
Dave Roby, AOGCC
0 b LISJRNE FIELD, WAHOO R•ERVOIR - DRILL SITE LISBURN•S 1.5 Miles
E T FOR GAS CAP WATER INJECTION PILOT PROJECT EXTENSION
REQU S
700000 705000 710000 715000
i I i ■ ..
•
GULL ISLAND NORTHERN ii
BOUNDIN FA ULT s
o
29 28
(RES LIM177 6 25 30 29 cc
0.
in 7 Z O
II o
0
co
in
I GCWI Injection Well
■
L5 -29 L5 -36 L I S B U R N E PA
r • Al
L5 -28
L5 -33 n
32 33 L5 -25 34 • 35 L5 -28 36 DS N K 31 32
o �� r
co GULL -02
in o
L1 -28
o 1, L5 -26 0
ojr4 L5 -.:AL1 0
�Q�' a L5 -21 �� _ T12N
T11 c L5 -31 ,pri L5 -32 I V T11 N
0 L5-24
7
L5 -09 L5 -19 { -�
o �� L5 -13 � L5 -16AL2
4 L5 -1 . Niakuk Sea Water Line 6 5 ,,,
.,_
N.
L5 -15 C5-1 0
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N.
L5 -17A �', 45-190- ?
PRUDHOE BAY O �G, /�y
lak
k I - _, - DSL5 E. C `,v
0 / 0 - - I/
L2 -32 L3 -01 0 ,L5 -16A
L5 -05
� L5 -12
o O _ L5 -01 V
o 8 9 _ 10 c ,, 12 /t 7 ��
7 G
L3 02 /
L3 -05 o
or L4 -12 N
L5 -01 TOTAL DEPTH WELL LOCATION 0 G 5 -08 i L5 -0 m m
C p m m
/r . i
700000 ` 705C 710000 715000 720000 725000 MS15592.mxd
~7
Regg, James B (DOA)
From: GPB, Ops Supt [GPBOpsSupt@bp.com]
Sent: Wednesday, July 23, 2008 11:00 AM
To: Regg, James B (DOA)
Cc: Bill, Michael L (Natchiq); Bisch, Jeff D.; GPB, GPMA Fac Engr
Subject: SVS for L5-29 Pilot Project
Mr. Regg,
This e-mail is to inform you that the Lisburne's well L5-29 (Pilot Project - Gas
Cap Water Injection) SVS has been defeated since we are unable to maintain SVS in
open condition because the well is on vacuum. We will notify you when conditions
change.
If you have any questions, please call me at (907) 659-5224. Thanks.
Sohrab Tafreshi
~~ ~~~
,* ~
Sohrab Tafreshi (Alt Joel Krueger)
GPB Ops Supt
BPXA
(907) 659-5224 office
(907) 240-8231 cell
7/23/2008
#6
by
May 22, 2008
Diane Richmond
GPMA Resource Manager
Greater Point McIntyre Area
Greater Prudhoe Bay Unit
BP Exploration Alaska
PO Box 196612
Anchorage, AK 99519-6612
Phone +1 (907) 564-4136
John Norman, Commission Chair
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave #100
Anchorage, Alaska, 99501-3539
~/'
~1AY ~ ~ ~'QOg
A~eska Oil ~
Gas Cons. Commissiar~
Anchorage
RE: Lisburne Gas Cap Water Injection Pilot Project Administrative Action Application.
Dear Mr. Norman:
BP Exploration (Alaska), Inc.. (BPXA), operator of the Prudhoe Bay Unit .(PBU), on behalf of
itself and the other PBU Working Interest Owners, in a letter dated May 5, 2008, requested
confidentiality on the Lisburne .Gas Cap Water Injection Pilot Project Application for
Administrative Action submitted to the Commission on February 25, 2008, and the
supplementary material submitted on April 22, 2008.
Revisions to Title 31 of the Alaska Statutes, amended under Senate Bill 109, and signed into
law on .July 13, 2007 reduced our rights to hold information contained in the Lisburne Gas Cap
Water Injection Pilot Application confidential. Based on this new understanding BPXA, on
behalf of itself and the other PBU Working Interest Owners, withdraws this request for
confidentiality on the application documents mentioned above. The documents as submitted
should be used to prepare the administrative approval of the Lisburne Gas Cap Water Injection
Pilof Project.
Please contact me if you have questions or require additional information.
Sincerely, ,®
Diane Richmond
GPMA Resource Manager
cc: Sam French, BPXA
Jim Briggs, BPXA
Justin Nash, BPXA
Sherri Gould, BPXA
Cammy Taylor, DNR
Don Ince, CPAI
Cameron Cheal, EM
#s
•
{',~ _~~
APR ~ ~~ ~i)OS
.~Iza Oil i~ Gas Cons. Con~rnission
~; Anchorage
22 April 2008
John Norman, Commission Chair
Alaska Oil and Gas Conservation Commission
333 W .7th Ave # 100
Anchorage, Alaska, 99501-3539
•
Diane Richmond
GPMA Resource Manager
Greater Point McIntyre Area
Greater Prudhoe Bay Unit
BP Exploration Alaska
PO Box 196612
Anchorage, AK 99519-6612
Phone +1 (907) 564-4136
RE: Lisburne Gas Cap Water Injection Piiot Project Administrative Action Application.
Dear Mr. Norman:
This cover letter provides clarification to the original letter dated February 25, 2008 which was
attached to the Lisburne Gas Cap Water Injection Pilot Project Application for Administrative
Action under Area Injection Order No. 4E (Rule 9) and Conservation Order No. 207 (Rule 12).
The application was also prepared in accordance with 20 AAC 25.402 (Enhanced Recovery
Operations) and 20 AAC 25.450 (Underground Injection Control Variances). BP Exploration
Alaska, Inc. ("BPXA") in its capacity as Operator of the Greater Prudhoe Bay Unit and the
Lisburne Participating Area seeks Alaska Oil and Gas Conservation Commission endorsement
and authorization for the proposed project. BPXA requests administrative approval for:
1) A single well pilot gas cap water injection project using L5-29 as the injection well,
2) A pilot period of three years,
3) Water injection rates of up to 20,000 barrels per day.
Injection rates significantly greater than 10,000 bwpd should be temporary. Injection rates are
expected to average approximately 10,000 bwpd during the 3 year pilot time period.
Supplementary material is attached in response to the AOGCC's March 11, 2008 request for
additional information.
Please contact Sam French (564-4168) if you have questions or require additional information.
Sincerely,
,___~
Diane Richmond
GPMA Resource Manager
cc: Sam French
Sherri Gould
C
•
~.~'
`,
LISBURNE
GAS CAP
WATER INJECTION
PILOT PROJECT
AT LS PAD
RESPONSE TO 3/11/08 AOGCC MEMO
SUPPLEMENT TO APPLICATION FOR
ADMINISTRATIVE ACTION
FOR INJECTION OF
WATER
April 16, 2008
• •
SECTION A -SEAWATER INJECTION LINE TO NIAKUK
As we discussed on the phone, the capacity of the water injection pipeline to
Niakuk is sufficient to allow for injection at L5 with no impact upon Niakuk
waterflood. Correct?
That is correct. Niakuk seawater injection should not be impacted by the additional L5 GCWI
water flowing through the Niakuk line. To ensure the project does not significantly affect Heald
Point drillsite injection pressure, a pipeline hydraulic model was created. At the current Heald Point
seawater rate of 43,000 bwipd and the expected LS seawater injection rate of 10,000 bwipd, the
model predicted the maximum wellhead injection pressure (WHIP) at Heald Point would drop by 45
psi. Currently only one key well, the NK-65A in the Raven PA, is injecting at maximum WHIP of
approximately 2200 psig. Most Heald Point injection wells are choked. Well nodal analysis modeling
of the NK-65A well using PROSPER software estimated a reduction in water injection rate of less
than 100 bwipd due to this reduction of 45 psi wellhead pressure. This is not a significant impact to
injection rate, and will not impact production rates or recovery from the Niakuk PA or Raven PA.
A scenario was also evaluated for an assumed short term peak L5 flowrate of 20,000 bwipd and
the current Heald Point injection rate of 43,000 bwipd. For this case, the model estimated a
reduction of surface injection pressure of 97 psi. The PROSPER well model predicted a
corresponding reduction in injection rate of approximately 200 bwipd for the NK-65A well. This
reduction in injection rate is not significant. If injection rates as high as 20,000 bwpd occur, they are
expected to be for short periods of time.
-2-
•
SECTION B - L5-29 CALIPER LOG
Please provide a copy of the caliper log mentioned on Page 9, Section F, 2"d
Paragraph. (You mentioned on the phone there is a new caliper -Could you
send that?)
Please find the caliper attached in pdf file tided: "L5-29 Caliper Log 03-29-07".
-3-
•
SECTION C -WATER SOURCE
We are assuming from Section G that you are only requesting injection of
Beaufort seawater, correct? There is a reference fo "produced water" in first
paragraph of page 12, Section H that should say "seawater': If you do wish LPC
produced water to be allowed during fhe pilot we will need composition and fluid
compatibility (see question 4). Are there other fluids you are requesting (i.e.
hydrotest water, water from well cellars.)
Yes, we are requesting approval to inject only Beaufort seawater. The reference to produced
water was an error.
-4-
• •
SECTION D -FLUID COMPATIBILITY
In addition to Exhibit F-1, do you have laboratory calculation of
scaling/precipitation tendencies of injected water with formation water? Note,
there is a lab analysis of the Lisburne produced water in the AIO 4 submittal.
Is it sufficiently current? Scaling tendencies not included.
The Production Chemistry Group of BP's Corrosion, Inspection and Chemicals group
performed scale tendency calculations for a mixture of Lisburne produced water and winter seawater
at ratios of 1:0, 80:20, 60:40, 40:60, 20:80, and 0:1. The temperature selected was 180oF with 1000psi
as a representative pressure in the wellbore. The water analysis used was from L4-36 in May 1995
and a seawater analysis from the winter of 1987. These analyses have proven to be representative of
these fluid streams over time. The calculations were performed using OLI ScaleChem software
version 3.1.
Conclusions from this analysis are summarized below:
• There isn't enough barium in either of these waters to cause a barium sulfate problem.
As Lisburne is a carbonate formation, the produced water from the reservoir is going to
be in equilibrium with calcium carbonate. As the pressure drops coming up the
wellbore, there will always be some thermodynamic tendency to precipitate carbonate
scales. What is analyzed in these situations is the change in tendency with the mixixzgof
the two brines. The ratio of scaling tendency is 39, 42, 38, 29, 17, and 3 for the ratios of
Lisburne produced water to seawater listed above. This suggests there will be a slight
increase in the tendency for calcium carbonate scaling at low seawater ratios, and then it
will decrease as the brine becomes more than 50% seawater.
• Calculations were run for CaSO4, BaSO4, CaC03, SrSO4, CaSO4.2H2O, and NaCI.
None of the others indicated a scaling potential.
-5-
• •
SECTION E -FRACTURE INFORMATION
Based upon the information in your application, you will not be exceeding the
fracture gradient of the Lisburne reservoir. There appears to be a good data
set of fracture information based on your stimulation work. If you do see
potential that you will want to exceed the frac gradient, further data supporting
the frac pressure, frac propagation and frac length should be provided for our
records.
All injection is planned to be conducted below the fracture pressure based on initial reservoir
conditions as described in the application. A reduction in confining stresses within the reservoir
under the conditions of gas cap water injection may lower the fracture pressure from initial
conditions resulting in fracture propagation known as `thermal fracturing'. This is caused by two
effects that lower the fracture gradient below the initial level:
o Cold seawater entering the reservoir rocks and cooling them.
o Reduced reservoir pressure.
This process is normal and occurs in the vast majority of fields injecting cold water. In Lisburne the
effect is expected to lead to higher injectiviry and may also lead to better sweep as the small natural
fractures in the reservoir expand creating more reservoir contact and more effective imbibition.
The process can be controlled by choking the injector to limit the rate of water injection. To ensure
full control is maintained through all possible injector performance, special chokes will be installed
that are capable of operating with full injection header pressure upstream, and 0 psi wellhead
pressure downstream. Similar chokes are used successfully elsewhere on North Slope fields.
-6-
• •
SECTION F -RESERVES BENEFITS/RISES
Could you supply the estimated incremental production by year from the water
injection? (Dii~cult to read from the graphs)
The incremental oil production by year associated with the gas cap water injection pilot is shown
in the table below. This assumes water injection for 20 years giving cumulative injection of 67.7
MMbbl. The GCWI Lisburne column is the incremental Lisbume oil production. This is then
adjusted for the impact of reduced injection into the Prudhoe Bay gas cap (Prudhoe Impact) to give
the overall GCWI Increment. The Lisbume incremental production comes directly from the
simulator and is therefore unrisked.
GCWI
Lisburne
MBOPD Prudhoe
Impact
MBOPD GCWI
Increment
MBOPD
2008 0.13 -0.019 0.11
2009 0.78 -0.061 0.72
2010 0.74 -0.101 0.64
2011 1.65 -0.133 1.51
201 Z 1.56 -0.159 1.40
2013 1.83 -0.179 1.65
2014 2.13 -0.195 1.94
2015 2.00 -0.206 1.79
2016 2.31 -0.214 2.10
2017 2.45 -0.219 2.23
2018 2.30 -0.221 2.08
2019 2.27 -0.221 2.05
2020 2.47 -0.219 2.25
2021 2.20 -0.216 1.98
2022 2.23 -0.212 2.02
2023 2.08 -0.207 1.87
2024 2.03 -0.201 1.83
2025 2.02 -0.195 1.83
2026 2.81 -0.188 2.62
2027 1.78 -0.181 1.60
2028 -0.173 -0.17
2029 -0.161 -0.16
2030 -0.145 -0.14
2031 -0.130 -0.13
-7-
• •
Could you please address the risk to future gas reserves during the pilot stage
of the project (rough estimates)?
The impact on future gas resource has been calculated using an approach based on the schematic
pore volume diagram shown below:
Gas Cap
After Gas
~lowclown:
IVo GCWI
Gas Cap
After Gas
~lowclown:
With GCWI
iitia~ swl GCWI water Trapped gas saturation
=0.i5 =0.35 =0.50
Abandonment pressure
= 2000 psia
Without gas cap water injection the Lisbume gas cap has connate water saturation of 0.15 and
it has been estimated that the average abandonment pressure in the Lisburne gas cap after gas
blowdown would be 1500 psia. With gas cap water injection, some of the gas will be displaced by
the injected water that remains in the matrix leading to residual gas saturation. Analogue data for
limestones and dolomites shows a range of residual gas saturations from 0.4 - 0.6 pore volume for
rock of similar quality to Lisbume, so a value of 0.5 has been assumed. Therefore the water will
displace up to 0.35 pore volume of gas. The presence of a second phase, which is also the wetting
phase, is expected to reduce the effective permeability of the matrix leading to a higher
abandonment pressure after blowdown. The abandonment pressure in these circumstances is
uncertain but is expected to be 500 psi higher than the case with no water injection.
-8-
• •
The impact of water injection on gas resource is the difference between the additional gas
recovered because it is displaced from the matrix by the water, and the extra volume of gas that is
left in the matrix because of the higher abandonment pressure. The impact on gas resource and on
the overall project hydrocarbon recovery is summarized in the following table. This assumes the full
20 year injection period.
Impact of GCWI on Lisburne Gas Resource
Case Incr Gas Resource
BCF Overall GCW(
Increment MMboe
Incremental Li uids - 12.3
Base case GCWI Ab Pres 2000 si 11.8 14.3
Low GCWI Area Ab Pres 1500 si 25.0 16.6
Hi h GCWI Area Ab Pres 2500 psi 1.2 12.5
The analysis shows that GCWI provides a small increase in gas resources because of the
replacement of gas by water in the matrix.
Fora 3 year injection period the impact on Lisburne gas resource is positive (added resources) as
illustrated in the table below.
Impact of 3 Years of GCWI on Lisburne Gas Resource
Case Incr Gas Resource
BCF
Base case GCWI Ab Pres 2000 si 3.0
Low GCWI Area Ab Pres 1500 si 6.4
Hi h GCWI Area Ab Pres 2500 si 0.3
The presence of water in some gas reservoirs can have a detrimental impact on gas resources
because the movement of water to producing wells leads to higher bottomhole pressures resulting in
higher reservoir abandonment pressure. A loss of producers due to this effect is unlikely to happen
as a result of the Lisburne GCWI pilot for two reasons:
• The injection volume will only reach a limited number of producing wells.
• The presence of high permeability pathways and fractures in the reservoir will allow gas to
flow to the wells once water injection is stopped, even if they are filled with water during
injection. This has been shown to be the case following the. L2 pilot waterflood in 1987 -
89 when the injectors and producers all returned to healthy production within a few
months following the cessation of injection.
-9-
• •
In obtaining the rate estimate, we assume the gas handling remained constant
over the life, correct?
The gas cap water injection project does assume the facility gas handling limits remain constant
throughout the project.
Do you have any estimates of timing of water breakthrough and volumes? Don't
make any new model runs for this.
The gas cap water injection modeling showed water arriving at producers after 2 years. There is a
large uncertainty in water arrival times as the understanding of the fractures and high permeability
pathways is limited. Using the GOR trends of nearby wells as an analogue for injection water
movement suggests breakthrough could happen at anytime between 3 months and 2+ years.
The predicted water production rates from the sector model used to justify the gas cap water
injection pilot project are shown in the plot below. As the sector model covered a different area of
the field, and in view of the uncertainty in breakthrough times mentioned above, this data can only
be regarded as indicative. In the case shown below, water injection started 2Q 2008 and the water
injection rate averaged 9300 bbl/d during the 20 year simulation period.
7,0^^
~ 6,000
as ~•~
ca
~ ~,~
0
r
3,000
0
L
a 2,000
a~
r
~o
~ '8 ,000
21
Qa~~O ~~tor Model Vllater Production 6~ates ~
• •
SECTION G - H2S & CORROSION TENDENCIES
Wellbore schematics indicate H2S concentrations ranging up to 200 ppm in
L5-29. Introduction of seawater may tend to increase the H2S concentration in
production fluids. Please verify that operations will operate outside of the critical
conditions for sulfide stress cracking and hydrogen embrittlement of wellbore
tubulars and surface production equipment. Do you anticipate increased
potential for corrosion as the injected water mixes with the high C02 formation
gas?
All Lisburne facilities, pads, and flowlines were originally designed for H2S production in
accordance with Piping Materials Specifications. The highest concentrations of H2S have been
produced from wells in the south eastern portion of the field in the L4 area. Since 1993, when the
highest recorded HZS concentration at a well peaked at over 1500 ppm, field H2S concentrations
have declined steadily with the highest recorded HZS concentration on a producing well in 2007
being less than 400 ppm. Despite relatively high levels of H2S production from L4 wells, there
appears to be no correlation between high H2S concentrations and well failures in this area.
The high H2S concentrations that were experienced in the L4 area provide a field analog to the
worst-case H2S scenario at L5 as a result of the GCWI pilot. Modeling of the worst-case H2S
production was completed using in-house proprietary software that showed a maximum expected
H2S concentration of 1342 ppm irrespective of transit time from injector to producer. This is also
the maximum H2S concentration expected for the duration of injection. This worst-case scenario is
less than the H2S concentrations already experienced by Lisburne wells and facilities in the L4 area.
Due to the laxge volume of gas produced from L5, any H2S generated from this area will be heavily
diluted and remain within current flowline and facility H2S limits. The model predicts that a well
concentration of 1342 ppm would only increase H2S concentrations at the LPC by 4 ppm for 300
mmscfd of gas production and 3 ppm for 400 mmscfd. Total LPC inlet gas rate is typically between
400 to 500 mmscfd. The L4 area has not shown any H2S induced well or facility integrity failures.
This demonstrates it is unlikely that wells and facilities in the L5 area would approach critical
conditions for H2S failure due to sulfide stress cracking.
The L2 waterflood pilot from 1988 to late 1989 is considered a reasonable injection project
analog to the GCWI pilot. The L2 waterflood injected 9 million barrels of seawater into the Wahoo
over this time-frame, which compares to a proposed injection volume of 11 million barrels of
seawater over three years in the Wahoo formation for the GCWI pilot. Although no well H2S
concentrations are available for the period of injection of the L2 waterflood, data one year after this
pilot demonstrated no sustained elevation in H2S concentrations. The highest recorded
concentration of H2S in the L2 area has been 500 ppm on L2-24 during the early 1990s. The
average H2S concentration for L2 wells in 1991 was 24 ppm, and last year averaged 29 ppm. As
observed in the L4 area, there is no direct correlation between high H2S producing wells and well
integrity failures.
The BP Corrosion, Inspection and Chemicals (CIC) team also notes no evidence of HZS induced
failures in Lisburne wellbore tubulars. The L2-06 and L1-31 Lisburne wells that were worked-over
this year had chrome tubing installed to minimize C02 corrosion and extend well life. This practice
of replacing carbon-steel with chrome tubing will continue as wells are worked-over in the Lisburne
field. The Lisburne field already has a number of high water producing wells and it is not expected
-11-
r •
that the GCWI pilot will introduce different corrosion mechanisms that are not already being
addressed in the field.
The BP Corrosion, Inspection and Chemicals (CIC) team does not see any reason for the C02
corrosion rate in the reservoir to change significantly due to sea water injection.
-12-
• •
SECTION H -SURVEILLANCE
a. Reservoir Pressure -You indicated on the phone that you are
currently getting reservoir pressures throughout L5. Could you
send any additional SBHPs you've acquired beyond those listed in
Section H?
Update March 2008
Well Datum
(PSIG}
Date.
-Type
Confitlence
Shut in Days
L5-23 3,246 27-Aug-07 SBHP Moderate 15
L5-21 3,547 3-Nov-04 SBHP Moderate 16
L5-33 3,388 1-Mar-08 SBHP High 43
L5-36 3,567 15-Sep-04 SBHP Moderate 7
L5-32 3,060 26-Aug-07 SBHP Moderate 15
L5-28 3,510 14-Dec-05 SBHP High 32
L5-12 2,796 4-Mar-08 SBHP High 35
LS-13 3,212 2-Mar-08 SBHP High 43
b. Mechanical integrity - In your surveillance planning, please ensure
you include logs (wate-flow, other) to verify the mechanical integrity
of L5-29. We do have a copy of the 3/18/2007 MIT in our fries.
AOGCC will require another MIT before commencing injection, and
another (witnessed by AOGCC) when wellbore conditions thermally
stabilize after commencing injection. Could you please supply
current pressure plots for tubing, inner annulus and outer annulus
for L5-21, L5-25, L5-29 and L5-33? We will want periodic
monitoring of TIO pressures during the test phase.
The attached file "L5 TIO DATA 03-2008.x1s" contains the requested pressure
data.
-13-
• •
c. L5-29 Static Bottom Hole Pressure Data: pre-infection
Datum
Well (PSIG) Date Type Co~idence Shut in Days
L5-29 3,451 5-Apr-2008 SBHP High 3779
-14-
Company: BP ~xploratioe~ ~AlaslCa) Bnc. Well: L5-21
Log Da#e: March 29, 2®07 Field: Lisburne
Log No.: 9003 State: Alaska
Run No.: 1 API iVo.: 50-029-21724-00
Pipet Desc.: 7' 26th L-80 IPC Top Log Intvll.: Surface (MD)
Pipet Use: Tubing Bot_ Log IntvlL: 13,206 Ft. (MD) ,
pnspecto®n Type o ~®rr®sl~e ~ JMechanical ®arnage Inspec~®®n
C®MMENTS
'his caliper data is tied into the 7"%5-1/2")(Over @ 13,206' (®rillers ®epth),
This log was run to assess the condition of the tubing with respect to internal corrosive and mechanical
damage. The caliper recordings indicate that the 7° tubing logged is in good condition. There are no
significant wall penetrations, areas of significant Cross Sectional Wall loss or I.D. restrictions recorded
throughout the tubing.
The distribution of maximum recorded penetrations is illustrated in the Body Region Analysis Page of this
report.
MA3CIMUM RECORDE® m9/ALL PEIVET TlOINS :
No significant wall penetrations (>11 %) are recorded.
MAXIMl1M RECOR®E® CROSS-SECTION~4L METAL LOSS
No areas of significant cross-sectional wall loss (>3%) are recorded.
MAXIMt1M RECOR®E®1® RESTRtC'r1OPIS
No significant I.D. restrictions are recorded.
Field Engineer: N. Kesseru/M. Lawrence Analyst: J. Thompson Witness: K. Bullock
-'~,;-._. ~__ ~ ~=' ___-~.~_ =~a.a`(%_ ;s-3.3b~ =-aa~~al: ~~S`~l~r-C~'Fv3}3;..:~~~^l:
• •
P®~ ~~~®~-r ®~~rvievv
~, -_ ~®~y ~~~o®~ ~~~~ysis
Well: L5-29 Survey Date: March 29, 2007
Field: Lisburne Tool Type: UW MFC 40 No 210357
Company: BP Exploration Alaska Inc Tool Size: 2.75
Country: USA No. of Fingers: 40
Anal st: ). Thom son
Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. Lower len.
7 ins Z6 ppf L-80 1PC __ 6.276 ins 7 ins 1.2 ins 1.2 ins
Penetration and Metal Loss (% wall)
~ penetration body ~ metal loss body
400 -
300
200
100
0 A
0 to 1 to 10 to 20 to 40 to over
1% 10% 20% 40% 85% 85%
Number of ~oints anal sed total = 336
pene. 1 334 1 0 0 0
loss 312 24 0 0 0 0
I
Damage Configuration (body )
10
0'
isolated general line ring hole / poss
pitting corrosion corrosion corrosion ible hole
Number of joints damaged (total = 1) ~
n ~ n 0 0
95
195
295
Bottom of Survey = 330.1
100
Damage profile (% wall)
~ penetration body ~ metal loss body
0 50
1
Analysis Overview page 2
~ •
PDS REPORT JOINT TABULATION SHEET
Pipe: 7. in 26.0 ppf L-80 IPC Well: L5-29
Body Wall: 0.362 in Field: Lisburne
Upset Wall: 0.362 in Company: BP Exploration Alaska Inc
Nominal I.D.: 6.276 in Country: USA
Survey Date: March 29, 2007
Joint
No. It. Depth
(Ft.) Pen.
Upset
(ins.) Pen.
Body
(Ins.) Pen.
% Meta!
Loss
% Min.
I.D. Comments
(Ins.) _ _ Damage Profile
(% wall)
0 50 100
1 41 0 0.01 4 2 6.22 Lt. De osits.
1.1 80 0 0.03 8 1 6.26 PUP
1.2 82 0 0.00 1 i 6.22 PUP
1.3 92 0.12 0.01 4 1 6.22 PUP Pittin
1.4 102 0.13 0.01 4 1 6.23 PUP Pittin .
2 112 G.06 0.02 1 6.26 Shallow ittin .
3 152 0 0.01 1 6.25
4 191 0 0.02 7 1 6.23
5 230 0 0.01 2 1 6.27
6 270 0 0.01 3 1 6.28
7 309 0 0.01 3 1 6.27
8 349 0 0.02 4 1 6.26
9 389 0 0.01 3 1 6.27
10 428 0 0.01 3 1 6.24
11 467 0 0.01 2 1 6.26
12 506 0 0.01 1 6.27
13 546 0 0.01 1 6.27
14 585 0 0.02 5 1 6.28
15 625 0 0.01 3 1 6.27
16 665 0 0.01 3 1 6.28
17 704 0 0.02 6 1 6.2 7
18 744 0.12 0.01 1 6.22 Pittin .
19 781 0 0.01 4 1 6.24
20 820 0 0.02 6 1 6.25
21 860 0 0.01 1 6.25
22 900 0.09 0.02 4 1 6.26 Pittin .
23 939 0 0.01 4 1 6.26
24 979 0 0.01 4 1 6.28
25 1018 0 0.01 4 1 6.24
26 1059 0.11 0.01 4 1 6.27 Pittin .
27 1098 0.06 0.02 6 1 6.27 Shallow ittin .
28 1138 0 0.01 3 1 6.26
29 1177 0 0.01 4 1 6.27
30 1216 0 0.01 1 6.26
31 1255 0 0.02 5 1 6.27
32 1295 0.10 0.01 2 1 6.25 Pittin .
33 1334 0 0.01 4 1 6.27
34 1374 0 0.01 4 1 6.27
35 1413 0 0.02 5 1 6.27
36 1453 0 0.01 4 1 6.26 Pittin .
37 1493 0 0.01 4 1 6.24
38 1532 0 0.01 4 1 6.26
39 1570 0 0.01 2 1 6.25
40 1610 0 0.01 1 ~ 6.26
41 1649 0 0.01 1 6.25
42 1680 0 0.01 4 1 6.26
43 1714 0 0.01 4 1 6.22
44 1753 0 0.01 t 6.26
45 1792 0 0.02 1 6.26
~ 46 ~ 1831 0.05 0.02 6 1 6.26 Shallow ittin .
Penetration Body
Metal Loss Body
Page 1
P~~~ ~FPflI~T ~~li~l~ T~~~JL~~T~~~I ~.~-]~~7
Pipe: 7. in 26.0 ppf L-80 IPC Well: L5-29
Body Wall: 0.362 in Field: Lisburne
Upset Wall: 0.362 in Company: BP Exploration Alaska Inc
Nominal I.D.: 6.276 in Country: USA
Survey Date: March 29, 2007
Joint
No. Jt. Depth
(Ft.) Pen.
Upset
{fns.) Pen.
Body
{lns.) Pen.
% Metal Min.
Loss LD.
% {lns.) 'Damage Profile
Comments (% wall)
~0 50 10(
47
48 1876
1919 0
0 0.01
0.02 4
7 1
1 6.27
6.24
49 1959 0 0.01 3 1 6.25
50 1999 0 0.02 7 2 6.23
51 2038 0.06 0.03 8 1 6.19 Shallow aittina. _ i
52 2079 0 0.03 8 1 6.20
53 2121 0 0.02 4 1 6.24 ~
54
54.1 2160
2198 0.09
0 0.02
0.01 6
3 1
0 6.27
6.25 Pittin ~
PUP
54.2
54.3 2208
2223 0
0 0
0.01 0
3 0
1 5.94
6.22 SSSV
PUP
55 2233 0 0.01 3 1 6.25
56
57 !
58 2273
2313
2353 0
0.06
0 0.01
0.02
0.01 4
6
3 1
1
1 6.25
6.25
6.26 ~
Shallow ittin . ~
59 2392 0 0.01 2 1 6.25
60 2432 0 0.02 5 1 6.25 De osits.
61 I 2472 0 0.02 5 1 6.25
62 ~
63 2511
2550 0.13
0 0.02
0.01 6
3 1
1 6.25
6.27 Pittin ~
~
64
2590
0.09
0.02
6
1
6.25
Pittin . ~
65 i
66 ~ 2630
2670 0
0 0.01
0.03 4
7 1
1 6.24
6.24 ~
~
67 2710 0 0.01 2 1 6.25
68 2749 0 0.02 4 1 6.21
69 2788 0 0.02 5 1 6.25
70 2828 0.09 0.02 6 1 6.23 Pittin
71 2868 0 0.01 1 6.26
72 2907 O.i3 0.02 6 1 6.24 Pittin
73 2947 0 0.02 6 1 6.25 __
74 2987 0 0.01 2 1 6.22
75 3026 0 0.01 4 1 6.25 ~
76
77
78 3066
3106
3145 0
0
0 0.02
0.01
0.01 4
4
4 1
1
1 6.24
6.21
6.26 ~
~
~
79
80
81
82
83 3184
3224
3264
3304
3343 0
0
0
0.11
0 0.01
0.01
0.01
0.02
0.01 2
4
6
3 1
1
1
1
1 6.26
6.22
6.27
6.25
6.25 i~
~
~
Pittin ~
84 3382 0 0.02 4 1 6.24 _
85 3422 0 0.01 3 1 6.26
86 3462 0 0.01 4 1 6.25 ~
87
88
89
90 3501
3541
3581
~ 3620 0
0
0
0 0.01
0.01
0.01
0.01 4
3
4
3 1
1
1
1 6.23
6.24
6.23
6.25 ~
~
~~
~
91 3659 0 0.01 4 1 6.26
92
93 I 3699
3739 0.14
0 0.01
0.02 4
7 1
1 6.24
6.25 Pitting i
~
Penetration Body
Metal Loss Body
Page 2
P®S REP®RT 1®INT TAIL
Pipe: 7. in 26.0 ppf L-80 IPC Well:
Body Wall: 0.362 in Field:
Upset Wall: 0.362 in Company:
Nominal I.D.: 6.276 in Country:
Survey Date:
ILATI®N SHEET
L5-29
Lisburne
BP Exploration Alaska Inc
USA
March 29, 2007
Joint
No. It. Depth
(Ft.) Pen.
Upset
(Ins.) Pen.
Body
(Ins.) Pen.
% Metal
Loss
% Min.
I.D. I Comments
(Ins.)
~ Damage Profile
(% wall)
0 50 100
94
3778
0
0.01
3
1 -
6.25 I -----
95 3818 0.05 0.02 5 1 6.24 Shallow ittin ~
96 3858 0 0.01 3 1 6.23
97 3897 0.12 0.01 4 1 6.26 Pittin .
98 3937 0 0.01 3 1 6.25
99 3977 0 0.01 3 1 6.25
100 4015 0 0.01 3 1 6.24
101 4055 0.07 0.02 6 1 6.25 Shallow ittin .
102 4094 0 0.01 2 1 6.25 Pittin .
103 4133 0 0.03 7 1 6.23 __
104 4173 0 0.01 4 1 6.25
105 4212 0.06 0.01 4 1 6.25 Shallow ittin .
106 4251 0 0.01 3 1 6.25
107 4291 0 0.02 6 1 6.23
108 4330 0 0.01 3 1 6.26
109 4370 0.10 0.02 6 1 6.26 Pittin .
110 4410 0 0.02 1 6.25
111 4449 0 0.01 3 1 6.26
112 4489 0 0.01 4 1 6.26
113 4529 0 0.01 3 1 6.22
114 4568 0.06 0.02 4 1 6.25 Shallow ittin .
115 4607 0 0.02 7 1 6.23
116 4646 0 0.01 4 1 6.26
117 4685 0 0.01 3 1 6.25
118 4725 0.11 0.02 6 1 6.23 Pittin .
119 4765 0.08 0.02 6 1 6.27 Pittin .
120 4804 0 0.02 1 6.25
121 4843 0 0.01 4 1 6.25
122 4883 0.05 0.02 4 1 6.22 Shallow ittin .
123
124
125 4922
4961
5001 0
0
0 0.01
0.01
0.02 3
4
7 1 I
1
1 6.23
6.25
6.25
~
126 5041 0 0.02 7 1 6.25
127 5081 0 0.02 6 1 6.24
128 5120 0.05 0.01 3 1 6.23 Shallow ittin .
129 5160 0 0.01 4 1 6.24
130 5199 0 0.02 5 1 6.25
131 5239 0.06 0.02 6 1 6.23 Shallow ittin .
132 5279 0 0.02 5 1 6.26
133 5318 0 0.01 4 1 6.25
134 5358 0 0.03 7 1 6.19
135 5398 0 0.01 3 1 6.24
136 5438 0 0.01 1 6.26
137 5477 0 0.01 3 1 6.23
138
139 5517
5556 0
0 0.02
0.01 5
3 1
1 6.25
6.21
140 5595 0.07 0.02 6 1 _ 6.23 Pittin .
141
142 5635
5675 0
0 0.02
0.02
6 1
1 6.25
6.23
143 5714 0 0.03 8 1 6.21
Penetration Body
Metal Loss Body
Page 3
• •
~'~~ ,~'~PC~~~ B~al~l~ T~°a~~J~f~~9®i~ ~~~~ IT
Pipe: 7. in 26.0 ppf L-80 IPC Well: L5-29
Body Wall: 0.362 in Field: Lisburne
Upset Wall: 0.362 in Company: BP Exploration Alaska Inc
Nominal I.D.: 6.276 in Country: USA
Survey Date: March 29, 2007
Comments Damage Profile
(% wall)
0 50 100
Shallow ittin .
Shallow ittin .
Pittin
^
1
Pittin r I
^
ittin ~
1
Shallow ittin ~
Pittin ~
Piton
Pittin
Shallow ittin . r
Pittin .
Pittin
Penetration Body
Metal Loss Body
Page 4
~~)~ ~~~~R~ ~~~~~J~ ~A61
Pipe: 7. in 26.0 ppf L-80 IPC Well:
Body Wall: 0.362 in Field:
Upset Wall: 0.362 in Company:
Nominal I.D.: 6.276 in Country:
Survey Date,
J~A~~~I~ SH~~~~
L5-29
Lisburne
BP Exploration Alaska Inc
USA
March 29, 2007
Joint
No. Jt. Depth
(Ft.) Pen.
Upset
(Ins.} Pen.
Body
(Ins.) Pen.
% Metal
Loss
% Min.
LD. ' Comments
! (Ins.) i Damage Profile
(% wall)
0 50 100
194 7728 0.08 0.02 6 1 6.23 Pittin .
195 7766 0.13 0.02 6 1 6.24 Pittin .
196 7810 0 0.01 4 1 6.20
197 7855 0 0.01 3 1 6.23
198 7894 0 0.01 _ 4 1 6.24
199 7939 0 0.02 4 1 6.24
200 7980 0 0.02 6 1 6.21
201 8022 0 0.02 6 1 6.21
202 8067 0 0.02 5 2 6.25
203 8113 0 0.02 6 2 6.19
204 8158 0 0.02 6 1 6.23
205 8197 0 0.01 2 1 6.21
I 206 8236 0 0.01 3 1 6.25
207 8276 0 0.02 b 1 6.23
208 8315 0 0.03 8 1 6.20
209 8360 0 0.02 5 1 6.20
210 8398 0 0.01 4 1 6.24
211 8439 0 0.02 6 1 6.24
212 8478 0 0.01 3 2 6.12
213 8513 0.08 0.02 6 1 6.21 Pittin .
214 8553 0.10 0.01 4 1 6.25 Pittin .
215 8593 0.10 0.02 6 1 6.22 Pittin .
216 I 8632 0 0.01 4 1 6.23
217 i 8672 0 0.01 3 1 6.23
218 ! 8712 0.10 0.02 6 1 6.23 Pittin .
219 8750 0 0.02 6 1 6.23
220 8790 0.12 0.01 4 1 6.23 Pittin .
221 8830 0 0.02 7 1 6.23
222 ~ 8869 0.12 0.01 4 1 6.23 Pittin .
223 8910 0.18 0.02 6 1 6.22 Pittin .
224 8949 0 0.01 3 1 6.19
225 8990 0.07 0.02 4 1 6.24 Pittin .
226 9029 0.16 0.02 6 1 6.24 Pittin .
227 9069 0 0.01 3 1 6.23
228 9108 0 0.02 6 1 6.22
229 9147 0 0.01 4 1 6.23
230 9188 0 0.01 2 1 6.19
231 9227 0 0.02 6 1 6.23
232 9266 0 0.01 3 1 6.19
233 9305 0 0.01 4 1 6.24
234 9345 0 0.01 2 1 6.22
235 9384 0 0.01 3 1 6.23
236 9423 0.08 0.02 6 1 6.18 Pittin .
237 9463 0.06 0.02 6 2 6.20 Shallow ittin
238 I 9502 0.11 0.02 4 1 6.21 Pittin .
239 9542 0 0.02 6 1 6.22
240 9581 0 0.02 4 1 6.18 Li ht de osits
241 9619 0 0.03 1 6.19
242 9665 0.10 0.02 6 1 i 6.21 Pittin ~ i
243 9709 0 0.02 6 1 6.20
'Penetration Body
Metal Loss Body
Page 5
F' IC~'~ !~ ~ ~~~ ~T ~ ~ II I`~J T '~~ ~ ~J ~.~~8 ~ ~ ~ ~-~ ~ ~ IT
Pipe: 7. in 26.0 ppf L-80 IPC Well: L5-29
Body Wall: 0.362 in Field: Lisburne
Upset Wall: 0.362 in Company: BP Exploration Alaska Inc
Nominal I.D.: 6.276 in Country: USA
Survey Date: March 29, 2007
Joint )t. Depth
No. (Ft.) Pen.
Upset
(arts.) Pen.
Body
(Ins.) Pen.
% Metal
Loss i
% Min. ~ Damage Profile
LD. I Comments (% wall)
(Ins.) I 0 50 100
244 9749 O.O~b 0.02 1 6.22 Shallow ittin .
245 9787 0 0.01 4 1 6.23 I
246 ~ 9827 0 0.02 6 1 6.19 I
247 ~ 9867 0 0.01 3 2 ~ 6.23
248 9909 0 0.02 6 1 6.19
249 9952 0 0.01 1 6.19
250 ~ 9995 0 0.03 8 1 6.23
I 251 ~ 10036 0 0.01 3 1 6.22
I 252 10076 0 0.02 6 2 6.15
253 10120 0 0.04 11 2 6.16 Shallow corrosion. Lt. De osits.
254 10163 0 0.02 6 1 6.21
255 10204 0 0.01 4 1 6.23
256 10241 0 0.01 3 1 6.22
257 10282 0 0.01 3 2 6.22
258 10324 0 0.02 6 1 6.18
259 10366 0 0.01 3 1 6.18
260
261 10407
10446 0
0 0.01
0.02 3
4 1
1 6.22
6.22 i
~
262 10484 0 0.02 4 1 6.21
263 10525 0 0.02 5 1 _6.23
264 10564 0.12 0.02 5 1 6.21 Pittin
265 10603 0 0.01 4 I 1 6.21
266 10642 0 0.02 6 1 6.21
267 10683 0.12 0.02 6 1 6.22 Pittin .
268 10722 0 0.02 6 1 6.21
269 10761 0 0.02 5 1 6.23
270 10801 0 0.01 4 1 6.20
271
272
273 10840
10879
10918 0.16
0
0 0.02
0.02
0.01 4
4
3 1
1
1 6.22
6.22
6.20 Pittin .
~
~
274 10958 0 0.01 2 2 6.19
275 10998 0 0.01 4 1 6.22
276 11037 0 0.01 2 2 6.22
277 11077 0 0.01 2 1 6.18
278 11118 0 0.01 4 1 6.20
279 11157 0 0.01 1 6.22
280 11196 0 0.01 4 1 6.21
281 11235 0 0.02 1 6.20
282 11276 G 0.01 3 1 6.21
283
284
285 11316
11355
11395 0.10
0
0.14 0.02
0.02
0.02 6
4
6 1
1
1 6.22
6.21
6.20 Pittin .
Pittin
~
•
286 11434 0 0.01 4 2 6.21 `
287
288
289
290
291
292
293 11474
11513
11552
11590
11631
11670
11710 0
0
0
0
0.06
0
0 0.02
0.01
0.01
0.01
0.02
0.01
0.01 6
3
3
6
3 1
1
1
2
1
2
1 6.19
6.22
6.19
6.19
6.18
6.22
6.22
_
Shallow ittin
I
j
I
Penetration Body
Metal Loss Body
Page 6
• •
PDS REPORT )DINT TABULATION SHEET
Pipe: 7. in 26.0 ppf L-80 IPC Well: L5-29
Body Wall: 0.362 in Field: Lisburne
Upset Wall: 0.362 in Company: BP Exploration Alaska Inc
Nominal I.D.: 6.276 in Country: USA
Survey Date: March 29, 2007
Joint
No. Jt. Depth
~(Ft.) Pen.
Upset
(Ins.) Pen.
Body
(Ins.) Pen.
% Meta!
Loss
% Min.
LD.
(Ins.)
Comments Damage Profile
(%wall)
0 50 100
294 11750 0 0.01 4 ~ 1 6.19 ~
295 11790 0 0.02 7 1 6.19
296 11828 0 0.02 5 1 6.20
297 11868 0 0.01 4 1 6.20
298 11906 0 0.01 4 1 6.20
299 11946 0.14 0.02 6 1 6.20 Pittin .
300 11986 0 0.02 4 1 6.22
301 12026 0 0.02 6 1 6.21
302 12064 0 0.01 3 1 6.21
303 12104 0.7 4 0.02 6 1 6.21 Pittin .
304 12144 0 0.01 2 1 6.20
305 12183 0.11 0.02 5 1 6.17 i Pittin .
306 12224 0.11 0.02 6 2 6.20 Pittin .
307 12262 0 0.02 6 1 6.21
308 _
12303 0 0.01 3 2 6.19
309 12341 0 0.01 4 1 6.20
310 12382 0 0.02 5 1 6.22
311 12421 0 0.02 5 1 6.20
312 12461 0.70 0.02 6 1 6.20 Pittin .
313 12500 0 0.02 6 1 6.17
314 12541 0 0.01 3 1 6.19
315 12580 0 0.01 4 1 6.21
316 12619 0 0.02 6 1 6.19 i
317 12657 0 0.01 2 1 6.20
318 12696 0.06 0.01 3 1 6.15 Shallow ittin .
319 12737 0 0.01 3 1 6.19
320 12775 0 0.01 4 1 6.18
321 12814 0 0.01 3 2 6.16
322 12855 0 0.01 4 2 6.19
323 12894 0 0.02 6 1 6.22
324 12934 0 0.01 1 6.18
325 12973 0 0.01 3 2 6.20
326 13012 0 0.01 4 1 6.20
327 13051 0 0.02 5 2 6.19
328 13091 0 0.01 3 1 6.18
329 13130 0 0.01 4 2 6.18
330 13169 0 0.02 5 1 6.17
330.1 1.3206 0 0 0 0 N A X OVER
Penetration Body
Metal Loss Body
Page 7
TRF~= 6" McE/OY
W~LhEAD = FMC
ACTUATOR = AXELSON
KB. ELEV = 60.0'
BF. ELEV = NA
KOP= 1200'
Max Angle = 63 @ 8500'
DahimMD= 14216'
DahamTVD= 8900'SS
13-318" CSG, 72#, L-80, ID= 12.347" H 5308'
Minimum m = 2.197" @ 13660'
2-718" AVA BNG NO GO NIPPLE
TBG-IPC, 26#, L-80, .0383 bpf, ID = 6.276" 13205
1/2" TBG, 17#, L-80, .0232 bpf, D = 4.892" I-I 1
1/2" TBG, 12.6#, L-80, .0152 bpf, ID =
PERFORATION SUMMARY
R~ LOG: DA Z DENSITY LOG OF 06/10/87
ANGLEATTOPPERF:48 @13585'
e,..~... a.ce. 1.. D...rln r4inn rua fnr hicfnrral nP_rf ~~a
SQE SPF ItJT92VAL Opn/Sqz DATE
4" 1 13585-13634 C 03/21/99
1-11/16" 1 13815,18,25,35, C 01/30/90
1-11/16" 1 41,54,64,92,96 C 01/30/90
1-11/16" 1 13903,09,15,19, C 01/30190
1-11/16" 1 36,41,49,63,76, C 01/30/90
1-11/16" 1 85,94 C 01/30/90
1-11/16" 1 14002,12,20,22, C 01/30V90
1-11/16" 1 46,52,56 C 01/30/90
2-7I8" TBG, 6S#, L-~, .0058 bpF, ID=2.441" 13663'
7" LNR, 29# ~ 80 0 0371 bpf D = 6 184"
14624'
,.r' aex-1
SAFETY NOTES: CAT 1 SSSV H2S (PPAA)
L 5 2 9 2~' PXN PLUG IN XN NIP @ 13328' ~ BNP
~ PLUG IN BNG NP @ 13660'.
® 2225' T' C4MC0 BAL-O SSSV N, ID = 5.937"
1 1 1
1320G H7" x5-1/2" xo,10= a.as2" I
13212' BKRGBH-22 LOC. SEALASSY, ID= 4.875"
13216' 9-5/8"X5-1/2"BKRFB-1 F'Kf2, ID=6.00"
13236' 5-12" X 4-1 /2" XO, ID = 3.958"
~-5/8" X 7" TNV HYDRO LNR M
4-1/2" OTIS XN NIP, ID= 3.725"
" PXN PLUG SET ON 0321/99
4-12" WL~a~
13506' 9-5/8° CSG, 47#, L-80, ID= 8.681"
13552' TW07"MARKERJTS (44'TOTAL)
13646' 7"X2-7/8" BOT 1-B PKR (FEND), ID=4.00"
13660' 2-7/8"AVA BNG NIP, ID = 2.197" I
" BNP PLUG SET ON 01/30/90
13664' 2-7/8" TBG TAB, D = 2.568"
13664' ELMD Tf LOGGED 1
13865' 7" CTC EXT CSG PKR
~ - ----
DATE REV BY COMMENTS DATE REV BY COMMEN'l5 LISDURNEUNIT
10/05/87 ORIGINAL OOMPLETION 03l03i07 ~L ~-~
0450
187
N
'
02124/90 WORK OV 8~ -
o:
ff2MfT
F
21724-00
029
50
119/2001 SIS-CS OONVERTEDTOCANVAS .
-
APINa
R15E
T11 N
02
' FEE
S
'
NAL ,
,
ec.
,
FSL & 145
2183
32/2001 SIS-LG F ka)
Al
4
as
on (
BP Explora
12/30/01 giIKAK CORRECTIONS
• •
SECTION H -INJECTION PRESSURES
The injection pressures and injection rates for the L5 GCWI pilot project will be monitored and
regulated to reduce the risk of premature breakthrough in production wells. Water injection pressure
will be limited to below the average fracture pressure of 0.55 psi/ft in the Wahoo formation in the
L5 Lisburne area. Surface injection pressures at the planned rate of 10,000 BWIPD are expected to
be less than 300 psig, which corresponds to a pressure gradient of 0.47 psi/ft. Further discussion on
fracture gradients is contained in Section I.
The estimated maximum and average wellhead injection pressures for the GCWI Pilot Project
are listed in the following table.
Estimated Maximum Estimated Average
Injection Pressure PSIG Injection Pressure PSIG
Injection Type Wellhead Bottom-hole Wellhead Bottom-hole
Seawater Injection - 900 _ 4,600 - 300 -- 4,000
The most recent reservoir pressures for offset wells in the GCWI pilot area are listed in the
following table. Pressures are at the datum depth of 8,900-ft TVDss.
Well SBHP ~ Datum
(PSIG) Date Type Confidence
L5-23 3,246 27Aug07 SBHP Moderate
L5-21 3,547 3Nov04 SBHP Moderate
L5-33 3,575 14Dec05 SBHP Moderate
L5-36 3,567 15Sep04 SBHP Moderate
L5-32 3,060 26Aug07 SBHP Moderate
L5-28 3,510 14Dec05 SBHP High
#4
•
MEMORANDUM
•
State of Alaska
Department of Administration
Alaska Oil & Gas Conservation Commission
TO: Sam French - BPXA Lisburne DATE: March 11, 2008
FROM: Jane Williamson - AOGCC Sr. Reservoir SUBJECT: AOGCC Staff
Engineer Comments/Questions related
~~ ~, ~'.~~~~..~ ,3/ a.v/ ~-°~ ~ to BPXA Proposed Lisburne
~ GCWI application
l ~ "` ..~ '
~( e,., _ r~. c;. ~ ( ~ ~ S ~ 2 ~ U ~t S i ~vte~~ 3~i/l2yy ~
~~ -
Dear Sam,
The AOGCC staff has a few questions and comments upon the proposed pilot Lisburne Gas
Cap Injection Project. I understand you are working on getting a new cover letter concerning
the scope of the project (per our phone conversations and a-mail to you on March 6 and phone
conversations). E-mail answers/verification for the following would be fine.
1. Seawater Line to Niakuk - As we discussed on the phone, the capacity of the water
injection pipeline to Niakuk is sufficient to allow for injection at L5 with no impact upon
Niakuk waterFlood. Correct?
2. L5-29 Caliper Log 3/29/07 -Please provide a copy of the caliper log mentioned on Page
9, Section F, 2" Paragraph. (You mentioned on the phone there is a new caliper -Could
you send that?)
3. Water source - We are assuming from Section G that you are only requesting injection
of Beaufort seawater, correct? There is a reference to "produced water" in first paragraph
of page 12, Section H that should say "seawater". If you do wish LPC produced water to
be allowed during the pilot we will need composition and fluid compatibility (see question
4). Are there other fluids you are requesting (i.e, hydrotest water, water from well cellars.)
4. Fluid Compatibility - In addition to Exhibit F-1, do you have laboratory calculation of
scaling/precipitation tendencies of injected water with formation water? Note, there is a
lab analysis of the Lisburne produced water in the AIO 4 submittal. Is it sufficiently
current? Scaling tendencies not included.
5. Fracture Information -Based upon the information in your application, you will not be
exceeding the fracture gradient of the Lisburne reservoir. There appears to be a good
data set of fracture information based on your stimulation work. If you do see potential
that you will want to exceed the frac gradient, further data supporting the frac pressure,
frac propagation and frac length should be provided for our records.
6. Reserves Benefits/Risks -Could you supply the estimated incremental production by
year from the water injection? (Difficult to read from the graphs.) Could you please
address the risk to future gas reserves during the pilot stage of the project (rough
_ estimates)? In obtaining the rate estimate, we assume the gas handling remained
----- - •
MEMORANDUM State of Alaska
Department of Adlministration
Alaska Oil ~ Gas Conservation Commission
constant over the life, correct? Do you have any estimates of timing of water
breakthrough and volumes? Don't make any new model runs for this.
7. H2S. Corrosion tendencies - Wellbore schematics indicate H2S concentrations ranging
up to 200 ppm in L5-29. Introduction of seawater may tend to increase the HZS
concentration in production fluids. Please verify that operations will operate outside of
the critical conditions for sulfide stress cracking and hydrogen embrittlement of wellbore
tubulars and surface production equipment. Do you anticipate increased potential for
corrosion as the injected water mixes with the high C02 formation gas?
8. Surveillance
a. Reservoir Pressure -You indicated on the phone that you are currently getting
reservoir pressures throughout L5. Could you send any additional SBHPs you've
acquired beyond those listed in Section H?
b. Mechanical integrity - In your surveillance planning, please ensure you include
logs (waterflow, other) to verify the mechanical integrity of L5-29. We do have a
copy of the 3/18/2007 MIT in our files. AOGCC will require another MIT before
commencing injection, and another (witnessed by AOGCC) when wellbore
conditions thermally stabilize after commencing injection. Could you please
supply current pressure plots for tubing, inner annulus and outer annulus for L5-
21, L5-25, L5-29 and L5-33? We will want periodic monitoring of TIO pressures
during the test phase.
• ~ Page 1 of 2
Colombie, Jody J (DOA)
From: French, Samuel W [Samuel.French@bp.com]
Sent: Monday, March 10, 2008 6:34 PM
To: Williamson, Mary J (DOA)
Cc: Foerster, Catherine P (DOA); Regg, James B (DOA); Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA);
Colombie, Jody J (DOA); Birnbaum, Alan J (LAW); Richmond, Diane M; Ince, Don; Reinbold, Eric W; Cheal,
Cameron (Exxon Mobil); hank.d.bensmiller@exxonmobil.com; Gould, Sherri L; Nash, Justin; Briggs, Jim M
Subject: RE: Lisburne GCWI Pilot Project Scope
Jane,
In response to your request, this email is to confirm that BP is requesting administrative approval for
1) Only a single well pilot gas cap water injection project with the L5-29 well being the water injection well
2) Injection rates of up to 20,000 barrels of water per day
Please note that the water injection rates over the 3 year pilot period are expected to average on the order of 10,000 barrels of
water per day. The maximum requested allowable water injection rate of 20,000 barrels per day is a possible short term injection
rate at project startup that may last for days or weeks without the bottom hole injection pressure exceeding the fracture gradient.
This injection rate of 20,000 barrels per day is an approximation and was estimated based on recorded lost circulation rates and
estimated bottom hole and reservoir pressures at the time the well was drilled in 1987. As explained in the application, the key
control will be well head injection pressure, which will be limited with the CCI choke to avoid exceeding the Wahoo fracture
gradient. If the well is initially on a vacuum (WHIP = 0 psig), corresponding intial injection rates could be on the high side.
3) A pilot period of up to 3 years.
I will need to get co-owner approval of a revised cover letter, but will work this as soon as possible. Please cc Diane Richmond on
all Lisburne correspondence.
Regards,
Sam
Sam W. French
Lisburne Subsurface Team Leader
GPMA
BP Exploration (Alaska) Inc.
( 907) 564-4168 Office
( 907) 440-4182 Cell
Mail Stop MB 3-7
From: Williamson, Mary J (DOA) [mailto:jane.williamson@alaska.gov]
Sent: Thursday, March 06, 2008 7:36 PM
To: French, Samuel W
Cc: Foerster, Catherine P (DOA); Regg, James B (DOA); Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA); Colombie, Jody J
(DOA); Birnbaum, Alan J (LAW)
Subject: Lisburne GCWI Pilot Project Scope
Sam,
I am writing to follow up on our phone conversation today concerning the project scope for which BP is requesting administrative approval.
3/20/2008
Page 2 of 2
Based upon our disussion, I understand that BP is only, at this time, seeking administrative action for
1) a single well LS-29 pilot gas cap water injection project with
2) up to 20,000 barrels water injection per day
3) for a period of up to 3 years.
Could you please follow up with an a-mail response and revised cover letter to the application verifying this is BPs request?
As we discussed by phone, if BP seeks to obtain approval now for an undefined expansion beyond LS-29 injection, I will be recommending
that the commission notice for opportunity for hearing and the staff will need significantly more information on the project scope and reservoir
engineering justification for the expansion.
As we discussed we have concerns about open ended expansion to other areas within LS without notice for hearing, better definition of the
scope of the expansion, and more information supporting the recovery benefits and risks. Waterflood is unproven as an appropriate enhanced
recovery technique in Lisburne (the L2 pilot water injection project did not yield encouraging results), and the GCWI process, while
encouraging at Prudhoe, has few analogues, particularly in a formation as complex as Lisburne. I'm concerned that such an open ended
approval would not be in the spirit of Rule 12 of the Lisburne Pool Rules (C0207) which allows the Commission to administratively approve
field pilot projects, well production and injection tests and other field operations necessary for the purpose of developing a prudent enhanced
recovery method and reservoir depletion program.
We have a few additional questions on the pilot that I will send by separate a-mail, but I would appreciate written clarification of the project
scope as soon as possible so that we don't hold up your application. Hearing dates must be set a minimum of 30 days after public notice.
Please call if you have any questions.
Jane
Jane Williamson, PE
Senior Reservoir Engineer
AOGCC
793-1226
3/20/2008
#3
by
25 February 2008
~~4r~ V
.Alaska Qil ~ G~~ CO(13, Gpmrnssio~
Artchalra~+~
John Norman, Commission Chair
Alaska Oil and Gas Conservation Commission
333 W . 7th Ave # 100
Anchorage, Alaska, 99501-3539
Diane Richmond
GPMA Resource Manager
Greater Point McIntyre Area
Greater Prudhoe Bay Unit
BP Exploration Alaska
PO Box 196612
Anchorage, AK 99519-6612
Phone +1 (907) 564-4136
RE: Lisburne Gas Cap Water Injection Pilot Project Administrative Action Application.
Dear Mr. Norman:
Enclosed is the Lisburne Gas Cap Water Injection Pilot Project Application for Administrative
Action under Area Injection Order No. 4E (Rule 9) and Conservation Order No. 207 (Rule 12).
The application was also prepared in accordance with 20 AAC 25.402 (Enhanced Recovery
Operations) and 20 AAC 25.450 (Underground Injection Control Variances). BP Exploration
Alaska, Inc. in its capacity as Operator of the Greater Prudhoe Bay Unit and the Lisburne
Participating Area seeks Alaska Oil and Gas Conservation Commission endorsement and
authorization for the proposed project. BP proposes a pilot period of three years.
Please contact Sam French (564-4168) if you have questions or require additional information.
Sincerely,
~m~
Diane Richmond
GPMA Resource Manager
cc: Sam French
Jim Briggs
Justin Nash
Sherri Gould
• •
LISBURNE
GAS CAY
WATER INJECTION
PILOT PROJECT
AT L5 PAD
APPLICATION FOR
ADMINISTRATIVE ACTION
FOR INJECTION OF
WATER
• •
SECTION A -INTRODUCTION
BP Exploration (Alaska) Inc. ("BPXA"), in its capacity as Operator of the Prudhoe Bay
Unit and the Lisburne Participating Area, hereby applies for Alaska Oil and Gas
Conservation Commission ("Commission") administrative action, under Area Injection
Order No. 4E (Rule 9) and Conservation Order No. 207 (Rule 12), to inject sea water in
the Wahoo formation of the Lisburne Oil Pool at Lisburne Drillsite LS Pad ("L5 Pad") for
the purposes of demonstrating the viability of a Gas Cap Water Injection enhanced oil
recovery project in the Lisburne Oil Pool. This project is referred to herein as the Lisburne
Gas Cap Water Injection ("LS GCWI") Pilot Project. This application has been prepared in
accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.450
(Underground Injection Control Variances).
Rule 1 of Area Injection Order No. 4 authorized the injection of non-hazardous fluids
for purposes of pressure maintenance and enhanced oil recovery in the Lisburne Oil Pool
into strata inclusive of the Wahoo and Alapah formations.
Primary development of the Lisburne Wahoo formation is gas cap gas injection with
irregular production well spacing averaging approximately 320 acres. The reservoir
recovery mechanisms are solution gas drive, gas cap expansion, gravity drainage and gas
cycling. Pressure support is provided by re-injection of a portion of the produced gas into
the gas cap. As of November 2007 there were 33 active producers located on 7
development pads, 3 active gas injectors located on one gas injection pad, and one
central processing facility located on a facility pad. Two Lisburne wells are located on the
Niakuk Heald Point Pad and one Lisburne well is located on the Prudhoe Bay K-Pad. A
high percentage of active Lisburne wells are cycled wells which trend to a high produced
gas/oil ratio ("GOR") over time and are shut in when their GOR reaches the marginal
GOR of the Lisburne Production Center ("LPC"). After being shut in to allow pressure. to
build, the cycled well is brought back online at a lower GOR to repeat the process. A
portion of produced gas from the Lisburne reservoir is used for field operations in the
Point McIntyre reservoir, including gas lift gas and gas cap gas injection for pressure
maintenance.
Produced water from the LPC is currently used for the Point McIntyre waterflood.
The Lisburne Field is the only producing carbonate field in Alaska. It is located
approximately 250 miles north of the Arctic Circle at a latitude of 71° N. The Lisburne Oil
Pool encompasses some 39,200 acres (61 square miles). A significant portion of the
Lisburne Oil Pool underlies the Prudhoe Bay Permo-Triassic reservoirs, separated by shale
sequences. The Lisburne field was discovered in early 1968 with the drilling of the
Prudhoe Bay State #1 well by ARCO and Exxon.
Sustained production from Lisburne began in 1985, ramping up production by 1987 to
approximately 45 MBO/D. This plateau rate was not sustainable due to the unforeseen
complexity of matrix porosity and fracture permeability throughout the carbonate
reservoir. As other fields (Pt. McIntyre &Niakuk) started producing, many Lisburne wells
were shut in or cycled to prevent their elevated GOR's from backing out lower GOR oil.
Drilling activity and wellwork from 1998-2006 has helped to stabilize production. Because
the field is limited by gas handling capacity, oil production varies seasonably due to the
• •
effect of ambient temperature on gas compression. In November 2007 the Lisburne Field
was producing approximately 11 MBO/D.
The LS GCWI pilot project scope includes converting the LS-29 gas injection well to
water injection to enable seawater injection into the Lisburne gas cap. There is currently
no water injection at Lisburne. The existing seawater pipeline to the Niakuk pad is located
adjacent to the LS pad. The Niakuk seawater line will be hot tapped and a new seawater
flowline constructed on to the L5 pad. The LS-29 water injection rate is expected to be
10,000 BWPD. Current plans are to perform the LS GCWI construction work in the first
quarter of 2008, and begin water injection in the LS-29 well in the second quarter of 2008.
The L5 GCWI pilot project has the following objectives.
• Increase Lisburne oil production rates (primarily from LS pad wells)
• Provide pressure support to the Lisburne Reservoir, primarily in the L5 pad area
• Reduce produced gas /oil ratios of LS pad wells
• Determine water injectiviry for Lisburne wells
• Evaluate gas cap water injection as a process that has potential to be expanded to
other areas of the Lisburne gas cap to recover additional Lisburne oil
Incremental oil recovery from the LS GCWI pilot project is expected to range from 1
MMSTBO to 12 MMSTBO assuming the pilot project is successful and subsequent
approval to continue injection is obtained, resulting in water injection for a total of 20
years. Gas cap water injection has not previously been tested in the Lisburne reservoir, is
not a conventional water injection project, and has few analogues in carbonate reservoirs.
As a result, there is significant uncertainty involved in the estimate of the project
incremental benefit. This GCWI project is a pilot project that will be used to obtain
reservoir performance data to reduce the uncertainty in the estimate of the project
benefits. The results of this project will be used to evaluate the benefit of additional GCWI
projects in the Lisburne Wahoo reservoir. Data obtained from this pilot project should
result in reduced uncertainty in the benefits of additional GCWI projects in the Lisburne
Wahoo reservoir.
The Lisburne Wahoo reservoir has approximately 2 Billion STB of original oil in place.
Cumulative liquid production through year end 2007 is expected to be approximately 160
MMSTB, or 8% of the OOIP. The successful implementation of pressure support projects
has potential to increase recovery from the Lisburne Wahoo reservoir. Gas cap water
injection has the potential to be one of these projects.
Original Lisburne reservoir pressure was 4,490 psia. The current average reservoir
pressure is approximately 3,200 psia.
Additional LS GCWI Pilot Project details are addressed in Section B through Section M.
3
• ~
SECTION. B -PLATS OF PROJECT AREA
Exhibit B-1 is a plat showing the locations of all existing injection wells, production
wells, abandoned wells, dry holes, and any other wellbores that penetrate the injection
zone within the LS GCWI Pilot Project area in the Lisburne Oil Pool. Exhibit B-2 is a plat
showing the locations of all existing injection wells, production wells, abandoned wells,
dry holes, and any other wellbores in the project area regardless of whether they
penetrated the Wahoo injection zone or not. There are no wells located within 1/ mile of
the bottom hole location for the LS-29 injection well.
The bottom hole location for the LS-29 well (at top Lisburne Wahoo) is tabulated in
Exhibit B-3. Specific approvals for any new injection wells or existing wells to be
converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and
25.507.
The project will benefit the local LS area more than other areas of the reservoir. Most
of the LS GCWI project benefit is expected to occur in the L5 pad area. However,
pressure support provided by the L5 GCWI project could benefit the entire Wahoo
reservoir.
Area Injection Order 4 for the Eastern Operating Area of the Prudhoe Bay Unit
encompasses all of the Lisburne Oil Pool. The affected area defined in AIO 4 specifically
includes all of the area expected to be influenced by the LS GCWI Pilot project, which
includes Sections 26, 27, 28, 33, 34, 35 and 36 in T12N, R15E, as well as Sections 1, 2, 3, 4,
5, 10, 11 and 12 of T11N, R15E. The bottom hole injection location of the LS-29 well is
located in Section 34 of T12N, R15E. AIO 4 is on file with the AOGCC and is not included
as an attachment.
4
~ •
SECTION C -PROJECT DESCRIPTION -SURFACE
The L5 GCWI Pilot Project is the first application of water injection to the Lisburne
reservoir from the LS pad. The Lisburne LS pad has production facilities in place, in
support of existing Lisburne and Niakuk wells. These facilities have the ability to provide
reliable well testing.
The Lisburne LS pad currently has no seawater or produced water injection facilities
available on the pad. The existing seawater pipeline to the Niakuk pad is located adjacent
to the LS pad as shown on Exhibit C-l, "Surface Pipeline and Pad Work". The LS GCWI
pilot project involves hot tapping the Niakuk seawater line and constructing a new 6"
seawater flowline on to the LS pad. The planned water injection rate is 10,000 BWIPD.
An ice road will be constructed during the 2007/2008 winter season to perform the off-
pad work required for the hot tap. Exhibit C-1 illustrates the location of the hot tap on the
Niakuk water injection line, the planned location of the 6" water injection line on the LS
pad, and the proposed location of the ice road for the off pad work.
The new 6" seawater flowline will be approximately 3000' in length from the Niakuk
seawater pipeline to the L5-29 well. Existing vertical support members ("VSMs") will be
used to support the line; however, some VSM cross members may be extended to
accommodate the new line. Various surface facilities (e.g. process piping and well pad
tie-in at LS-29) will be required to accommodate the new line, which will also include up
to 3 connections for future additional on-pad injection tie-ins.
Off-road activity and preparation of material storage areas will be conducted during
the 2007/08 winter construction season from ice roads and ice pads. Water for ice
road/pad construction will be taken from existing BPXA permitted sources in the project
area. No new water sources will be needed for this project.
The following construction work is planned:
• Run new 6" line from Niakuk line hot tap to tie-in point at LS-29 well.
o Install double block isolation at pad accessible location;
o Install platform access to hot tap valve location;
o Run heat trace on the entire 6" seawater pipeline;
o Install casing for on-pad road crossing;
o Provide up to three additional tie-in points on 6" (future water injection
flowline connections);
o Install new heated wellhouse;
o Install well control panel to control. both surface and sub-surface safety valves;
o Provide flowmeter to measure seawater injection rates;
5
• •
o Provide new injection choke at the wellhouse;
o Upgrade instrumentation and electrical infrastructure to allow installation of
wellhouse heater and heat trace.
• Hydrotesting
Hydrotesting will be required for the new pipeline. If a winter hydrotest is conducted,
hydrotest fluid may consist of a glycol/water mix and will be collected for recycling
and/or disposal at approved facilities. No tundra discharge will occur. If the hydrotest is
conducted during the late spring or summer, the procedure may involve water or other
products as the test fluid and will also be collected for recycling and/or disposal at
approved facilities.
The LS GCWI water injection choke valve to be installed is manufactured by Control
Components Inc (CCI), an industry leader in severe service control valves. CCI valves
have proven to be the most reliable design used at the East Dock Prudhoe Bay GCWI
wells. The L5-29 choke valve was sized to allow flow control with differential pressures
as high as 2190 psi, utilizing CCI's patented Drag Multi-Path Multi-Stage valve trim. The
valve trim is versatile, containing a caged section to allow higher flow rates if the
differential pressures are not as high as expected. The valve components exposed to the
harsh cavitation prone conditions will be constructed utilizing Tungsten Carbide,
providing a very abrasive resistant and long lasting valve design.
Pipeline routing was chosen to simplify the design, and alleviate concern of blocking
the only access road to Niakuk during the construction phase. The pipeline routing
selected will follow a diagonal route across a portion of the LS pad (refer to pipeline
routing on Exhibit C-1).
Seawater flow rate measurement will be achieved using a strap on ultrasonic flow
meter located at the flowline tie-in for well LS-29. The sensor for the strap on flow meter
can be placed on the flow line prior to the well, allowing sufficient straight pipe upstream
of the meter to provide an accurate reading. The flow transmitter will be located inside
the new heated well house.
The shutdown system on the LS-29 well will mimic others at Lisburne drill sites. This
design includes a low pressure pilot that shuts both the SSV (surface safety valve) and the
SSSV (sub-surface safety valve). Anew hydraulic panel will be provided for the well by
the project.
Schedule
The field construction portion of the project is scheduled to start in February of 2008
and be completed by April of 2008. Hydrotesting of the pipeline may occur later, but will
be completed before the line is put in service. The pipeline may commence operation as
early as the Spring of 2008. There is a possibility that higher priority work by construction
crews on oil transit line replacements will delay the on-pad construction phase of the L5
GCWI Pilot project.
6
• •
SECTION D -PROJECT DESCRIPTION -SUBSURFACE
The project scope includes converting the LS-29 gas injection well, currently
authorized to inject under Area Injection Order (AIO) 4E, to water injection to provide
seawater injection into the Lisburne gas cap.
The LS-29 is currently shut in. This well currently has 7" IPC tubing with a 135' tail of
4.5" tubing which will support water injection. All integrity testing required to return the
well to injection is complete, as explained below. Prior to injection the PXN tubing plug
currently set in an XN nipple at 13,328 ft measured depth ("MD") will be pulled, a caliper
log will be run and a small 15% hydrochloric acid ("HCL") stimulation job will be
performed. A wellbore schematic for the LS-29 well is shown on Exhibit E-1. Exhibit D-1
illustrates how the well completion corresponds to proposed injection intervals.
On March 18th, 2007 the LS-29 well successfully passed a mechanical integrity test
(MIT) of the inner annulus (IA) to 2500 psi. Under AIO 4E, all injection wells must pass
an AOGCC witnessed MIT-IA every four years. The last AOGCC witnessed MIT-IA on L5-
29 was performed on September 2nd, 2005, thereby demonstrating injection integrity
according to AOGCC regulations.
The LS-29 bottom hole location is shown on Exhibit B-1, B-2 and B-3. The area on
Exhibit B-1 bounded by the original gas-oil contact (OGOC) depth of -8600 ft true vertical
depth ("TVD") subsea ("ss") and bounded by the northern bounding fault represents the
original gas cap area of the Lisburne reservoir. The L5-29 well was drilled through the gas
cap. From March 1990 through May 1998 the L5-29 well injected 169 Bscf of gas at gas
injection rates typically in the range of 60 mmscfd to 80 mmscfd. The Lisburne gas cap
water injection pilot plans to initially inject water into Wahoo Zone 6 reservoir rock that is
above the gas-oil contact. The pore volume of this rock is filled primarily with gas, which
is much more mobile than the more viscous water that will be displacing the gas. This
should result in a more favorable mobility ratio than for water injection into rock below
the gas-oil contact.
Exhibit D-1 illustrates the well logs and the wellbore schematic for the LS-29. The
exhibit illustrates the reservoir pay in the well, highlighted in green on the porosity curve,
that exists above the OGOC at -8600 ft TVD ss. The plan for the L5 GCWI pilot is to
initially inject in the Wahoo Zone 6 rock above the BNP plug set in the wellbore at 13,660
ft MD. This BNP plug may eventually be removed to allow seawater injection into the rest
of the Wahoo pay in zones 6, 5 and 4 located both above and below the OGOC depth.
7
•
SECTION E -POOL DESCRIPTION AND FORMATION GEOLOGY
The Lisburne Oil Pool is defined by Rule 2 of Conservation Order No. 207. It is the
accumulation of oil and gas found within stratigraphic sections that correlate with the
stratigraphic section occurring in the Atlantic Richfield-Humble Prudhoe Bay State No. 1
well between the depths of 8,790 feet measured depth and 10,440 feet measured depth.
The Lisburne Reservoir is a combination structural and stratigraphic trap of carbonate
lithology. It is an anticlinal structure that is bounded on the north by the Prudhoe Bay-
Niakuk fault complex, by the Lower Cretaceous Unconformity truncation to the east, and
by the Pre-Echooka Unconformity truncation to the west. The unitized intervals are of
Mississippian /Pennsylvanian age and include the Alapah and Wahoo formations of the
Lisburne Group. The LS GCWI Pilot Project will inject sea. water into only the Wahoo
formation. Only the Wahoo formation will be affected by the LS GCWI Pilot Project.
8
• •
SECTION F -INJECTION AND PRODUCTION WELL CASING DESCRIPTION
Currently, no water injectors are in service in the Lisburne Oil Pool. API casing
specifications are included on each drilling permit application. All casing is cemented in
accordance with 20 AAC 25.030 (a)-(d) and tested in accordance with 20 AAC 25.030(e)-(f)
when completed. The casing annulus pressure are monitored on a daily basis in
accordance with AIO 4E, Rule 4 and are recorded by the pad operator. No new wells
within a 1/4 mile of LS-29 injector have been completed. As described in Section D, the
L5-29 has a current pass for an AOGCC witnessed MIT-IA in September 2005, and more
recently a pass for a BPXA required MIT-IA in March 2007.
The injection well tubing size in the Lisburne well L5-29, is a tapered string from 7-in
to 5.5-in to 4.5-in. A caliper log was run on March 29~', 2007, covering 13,206 feet of the
7" tubing string, demonstrating good mechanical integrity of the production tubing.
Producing wells within the Lisburne Gas Cap Water Injection (GCWI) Pilot Project area
utilize casing designs detailed below.
Exhibit E-1 shows the current LS-29 wellbore schematic, and exhibits E-2, E-3, E-4, and
E-5 show the wellbore schematics for the offset producers in the GCWI pilot area.
The casing program for the LS-29 injection well within the Lisburne GCWI is as
follows:
LS-29 Deviated Injector (see Exhibit E-1)
1. 20.0-in, 91.5-1b/ft H-40 conductor from surface to 119-ft measured depth (MD);
2. 13.375-in, 72-1b/ft L-80 BTC casing from surface to 5,308-ft MD;
3. 9.625-in, 47-1b/ft L-80 BTC casing from surface to 13,506-ft MD;
4. 7-in, 29-1b/ft L-80 BTC liner from 14,653-ft MD to 13,280-ft MD;
5. 7-in, 26-1b/ft L-80 BTC internal plastic coating (IPC) tubing from surface to
13,206-ft MD;
6. 5.5-in, 17-1b/ft L-80 LTC internal plastic coating (IPC) tubing from 13,206-ft MD
to 13,235-ft MD;
7. 4.5-in, 12.6-1b/ft L-80 BTC internal plastic coating (IPC) tubing from 13,235-ft
MD to 13,341' MD.
9
• •
The casing program for the surrounding producing wells within the Lisburne GCWI
Pilot area is as follows:
L5-25 Deviated Producer (see Exhibit E-2)
1. 20.0-in, 91.5-1b/ft H-40 conductor from surface to 115-ft measured depth (MD);
2. 13.375-in, 72-1b/ft L-80 BTC casing from surface to 6,608-ft MD;
3. 9.625-in, 47-1b/ft L-80 BTC casing from surface to 14,816-ft MD;
4. 7-in, 29-1b/ft L-80 BTC liner from 14,496-ft MD to 15,945-ft MD;
5. 2.875-in, 6.5-1b/ft L-80 8rd EUE tubing from surface to 14,546-ft MD.
IS-33 Deviated Producer (see Exhibit E-3)
1. 20.0-in, 91.5-1b/ft H-40 conductor from surface to 115-ft measured depth (MD);
2. 10.75-in, 45.5-1b/ft L-80 BTC casing from surface to 3,962-ft MD;
3. 7.625-in, 29.7-1b/ft L-80 BTC casing from surface to 10,730-ft MD;
4. 5.5-in, 17-1b/ft L-80 BTC liner from 10,516-ft MD to 11,516-ft MD;
5. 2.875-in, 6.5-1b/ft L-80 8rd EUE tubing from surface to 11,058-ft MD.
LS-36 Deviated Producer (see Exhibit E-4)
1. 20.0-in, 91.5-1b/ft H-40 conductor from surface to 115-ft measured depth (MD);
2. 10.75-in, 45.5-1b/ft L-80 BTC casing from surface to 4,953-ft MD;
3. 7.625-in, 29.7-1b/ft L-80 BTC casing from surface to 11,650-ft MD;
4. 5.5-in, 17-1b/ft L-80 BTC liner from 11,416-ft MD to 12,172-ft MD;
5. 2.875-in, 6.5-1b/ft L-80 Srd EUE tubing from surface to 11,636-ft MD.
LS-27 Deviated Producer (see Exhibit E-5)
1. 20.0-in, 91.5-1b/ft H-40 conductor from surface to 90-ft measured depth (MD);
2. 13.375-in, 68/72-1b/ft L-80 BTC casing from surface to 4,457-ft MD;
3. 9.625-in, 47-Ib/ft L-80 BTC casing from surface to 12,063-ft MD;
4. 7-in, 29-1b/ft L-80 BTC liner from 11,835-ft MD to 12,827-ft MD;
5. 2.875-in, 6.5-1b/ft L-80 8rd EUE IPC tubing from surface to 11,972-ft MD & from
12,392-ft MD to 12,408-ft MD.
10
• •
SECTION G -INJECTION FLUIDS
The Lisburne LS GCWI Pilot Project will use seawater from the existing Niakuk
injection water pipeline. This seawater is sourced from the Seawater Treatment Plant (STP)
at West Dock and sent to the Eastern Seawater Injection Plant (ESIP) where the injection
fluid is pressured to approximately 2200 psi. The expected seawater injection
composition is shown in Exhibit F-1. The planned injection rate is 10,000 bwipd,
depending on injection pressures which will be controlled to ensure that the fracture
gradient of the Lisburne Wahoo formation and confining zones is not exceeded. Fracture
gradients are discussed in Section I.
Injection fluid information pertaining to the LS GCWI Pilot Project is given below.
ape of Fluid: Seawater
Composition Of Fluid: See Exhibit F-1.
Source Of Fluid: Beaufort Sea, via the Seawater Treatment Plant (STP) at West Dock
to the Eastern Seawater Injection Plant (ESIP), then via the existing Niakuk seawater
injection line to the LS pad.
Estimated Maximum Amount To Be Injected Daily The well will be controlled by
wellhead injection pressure using a choke to avoid exceeding the Wahoo fracture
gradient. The injection rate will be determined by the wellhead injection pressure.
Maximum injection rates of up to 20,000 BWPD could be possible without exceeding
the fracture gradient.
Compatibility with Formation and Confining Zones: Lisburne produced water has a
low concentration of barium and therefore the barium sulfate scaling tendency is low.
No other compatibility issues are expecting with confining zones.
11
•
•
SECTION H -INJECTION PRESSURES
The injection pressures and injection rates for the L5 GCWI pilot project will be
monitored and regulated to reduce the risk of premature breakthrough in production
wells. Produced water injection pressure will be limited to below the average fracture
pressure of 0.55 psi/ft in the Wahoo formation in the LS Lisburne area. Surface injection
pressures at the planned rate of 10,000 BWIPD are expected to be less than 300 psig,
which corresponds to a pressure gradient of 0.47 psi/ft. Further discussion on fracture
gradients is contained in Section I.
The estimated maximum and average wellhead injection pressures for the GCWI Pilot
Project are listed in the following table.
Estimated Maximum
Injection Pressure PSIG ;Estimated Average
Injection Pressure PSIG
Jnjection Type Wellhead Bottom-hole Wellhead Bottom-hole
Seawater Injection - 900 ~ 4,600 ~ 300 ~ 4,000
The most recent reservoir pressures for offset wells in the GCWI pilot area are listed in
the following table. Pressures are at the datum depth of 8,900-ft TVDss.
Well SBHP ~-Datum
(PSIG)
Date
Type
Confidence
L5-23 3,246 27Aug07 SBHP Moderate
L5-21 3,547 3Nov04 SBHP Moderate
L5-33 3,575 14Dec05 SBHP Moderate
L5-36 3,567 15Sep04 SBHP Moderate
L5-32 3,060 26Aug07 SBHP Moderate
L5-28 3,510 14Dec05 SBHP High
12
• •
SECTION I -FRACTURE INFORMATION
The estimated maximum injection rates for the L5-29 in the LS GCWI Pilot Project will
not initiate or propagate fractures through the confining strata and, therefore, will not
allow injection or formation fluid to enter any freshwater strata.
Area Injection Order 4, including Section N (formation water salinity values across the
Eastern Operating Area), provides a freshwater exemption for the LS GCWI Pilot Project.
Finding 5 of AIO 4 states
"Within the Project Area, injection into, through, or above a fresh water aquifer or
underground source of drinking water will not occur."
Finding 4 of AIO 4 states the Project Area encompasses all of the Lisburne Oil Pool. The
affected area defined in AIO 4 specifically includes Section 34 of T12N, R15E which
includes the bottom hole injection location of the LS-29 well. AIO 4 and Section N are on
file with the AOGCC and are not included as attachments.
The entire L5 GCWI Pilot area has significant shale intervals deposited on top of the
Lisburne Wahoo. These shales form a seal over the entire project area. The Highly
Radioactive Zone (HRZ) shale serves as the upper seal for the Lisburne field immediately
above the LS-29 bottom hole location and over the rest of the Lisburne Wahoo to the
E/NE/SE of the LS-29. In the area of the L5-29 water injection well there is an HRZ shale
thickness of greater than 200 TVD feet. To the W/NW/SW of the LS-29 bottom hole
location the Kavik shale overlays the Wahoo. The sealing properties of the HRZ and Kavik
shale intervals are very good and well understood across the North Slope. These confining
strata tend to behave as a plastic medium. Above the HRZ interval there exists
approximately 1200 TVD feet of additional Cretaceous shale prone lithologies until the
West Sak sands are encountered. The water injected into the Lisburne gas cap will be
contained in the Lisburne carbonate due to the sealing capabilities of the HRZ and Kavik
intervals.
Below the LS GCWI Pilot injection zones exist several hundred feet of
predominantly non-pay Wahoo interval, a Green Shale interval separating the Wahoo and
Alapah formations, and several hundred feet of Lisburne Alapah formation.
Fracture stimulation data from the Wahoo formation in the L5 area indicate a fracture
gradient of between 0.53 (LS-21) and 0.57 (LS-23) psi/ft under initial reservoir conditions.
Injection will be performed at pressures less than the average fracture gradient of 0.55
psi/ft to minimize the risk of fracturing the Lisburne. The confining layer's fracture
gradient is 0.65 psi/ft, based on drilling leak-off and formation integrity testing data. This
difference in gradients provides a substantial pressure buffer between the Wahoo reservoir
and the confining layer, minimizing the risk that the confining layer would be fractured
during injection. No injection or fracture propagation below the Lisburne Wahoo Zone 4
is anticipated for the LS GCWI Pilot project. As previously explained, initial injection will
be only into Wahoo Zone 6. The L5-29 may have wellwork done in the future to allow
injection into Wahoo Zone 5 and Zone 4.
13
• •
SECTION J -CONFINEMENT IN INJECTORS AND OFFSET WELLS
The wells in close proximity to the LS GCWI Pilot Project area are shown in Exhibits
B-1 and B-2.
The LS-29 injector has passed all integrity testing to date and is deemed fit for injection
under AOGCC integrity regulations. Furthermore, the L5-29 well has proved zonal
isolation from overlying zones through a competent cement job of the 9-5/8" intermediate
casing. After the 9-5/8" casing cementing operation, the casing was tested to 3000 psi,
and then the casing shoe was drilled-out along with 10 feet of new formation. The casing
shoe and newly drilled formation was then tested with a formation integrity test ("FIT") to
an equivalent mud weight of 12.5 ppg or gradient of 0.65 psi per foot, thereby proving
cement integrity at these pressures.
Section F describes the mechanical status of the injector and offset production wells in
the GCWI pilot area and Exhibit E contains the wellbore schematic diagrams of each of
these wells. A summary of the integrity status of the surrounding producers can be found
in Exhibit J-1.
14
• •
SECTION K -HYDROCARBON RECOVERY
The LS gas cap water injection pilot is expected to result in increased oil rate and
recovery from the Lisburne Oil Pool. To estimate the oil rate benefit, a three dimensional
finite difference reservoir simulation model was built representing a 3000 acre area of the
Lisburne gas cap. The model is a mechanistic approach at estimating the benefits of a gas
cap water injection project.
The model reservoir description was a comprehensive fine scale 3D model of Wahoo
zones 4, 5, 6 and 7. Significant geologic features were modeled including structure,
horizons, faults, fractures and reservoir properties. Facies were modeled to preserve
continuity of extreme properties. Pseudoized relative permeability curves were used to
account for flow through fractures. Historical production data was integrated to validate
the model by history matching the 10 wells in the model.
Model Results
The model predicted a small injection response approximately one year after injection
startup. The model predicted a peak incremental oil production response of
approximately 2000 bopd for a water injection rate of 10,000 bwpd. The peak oil rate
occurred 7 years after water injection startup.
A reservoir uncertainty analysis was applied to the mechanistic model results to
incorporate project risks. As a result, the incremental oil recovery from the LS GCWI pilot
project is expected to range from 1 MMSTBO to 12 MMSTBO. The higher recovery
estimates assume the pilot project is successful and subsequent approval to continue
injection is obtained, resulting in water injection for a total of 20 years. These recovery
estimates correspond to a project incremental recovery factor of up to 3% of the remaining
oil in place in the LS project area.
Model results for a base case run with no water injection were compared to the results
for a model run with 10,000 bwpd of gas cap water injection. In the gas cap water
injection case, individual wells had higher rates because their producing GORs were
lowered to levels below the marginal GOR for longer periods of time than in the base
case. Some wells that were shut in long term for high GOR returned to production.
Modest sweep benefits also contributed and reservoir pressures were higher in the water
injection case. No unfavorable water movement was observed in the model. The gas cap
water injection mechanism of water displacing gas has a more favorable mobility ratio (in
comparison to water displacing oil). The favorable mobility ratio should help to contain
the water in the gas cap reservoir pore volume.
The simulation modeling of Lisburne GCWI indicated the injected water provided not
only pressure support but also acted as a blocking agent to inhibit the movement of
injected gas from the west towards the LS producers to the east. This in turn reduced the
amount of gas produced by LS wells, lowering GORs, improving the on-time of cycle
wells and therefore increasing oil rate.
Lisburne is a highly complex faulted carbonate reservoir. Gas movement through the
faults and fracture system has been illustrated numerous times. Exhibit K-1 illustrates how
15
•
•
faults can be a major conduit for fluids (oil, water and gas) to move through the reservoir.
The gas injection wells at the LGI pad inject gas into the Wahoo zone 6. Injecting water
into the LS-29 well should result in water eventually entering faults and fractures in the
upstructure LS area. The water could inhibit gas movement through the fault system to the
producers. The LS GCWI pilot project will attempt to test this hypothesis.
16
•
SECTION L -SURVEILLANCE PROGRAM
Surveillance will be conducted during the water injection pilot to evaluate the
performance of the project and to mitigate any water breakthrough. The current
production facilities in place at the LS pad are capable of obtaining the bulk of the data
such as oil, gas and water production rates, production wellhead pressures and cycle
times. Production logging will be used to obtain production profiles ("PPROFs") and
injection profiles ("IPROFs"). A flowmeter will be installed on the L5 pad seawater line to
measure water injection rates. Surveillance data will be reviewed every month by the
subsurface team reservoir engineer and production engineer. The surveillance program
will consist primarily of the following.
Well tests on every LS pad producing well twice per month. Well test data will be
used to allocate production to daily rates. Analysis and interpretation of the well
test data for each well will include
o GOR trend analysis -response should result in lower GOR's
o Gas rate analysis -response should result in lower gas rates
o Cycle time analysis -response should result in longer on-times before a
well reaches marginal GOR
o Oil rate analysis -response should result in higher average monthly oil
rates
o Water rate and water cut analysis -water breakthrough should result in
increased water rates
o The well test data gathered will be used to estimate the oil rate benefit of
the GCWI pilot project
Water sample analysis on every well with an increasing water cut
o Produced sea water can easily be identified due to the compositional
contrast with native formation water
o Scale analysis for scale inhibition program design if necessary. Lisburne
has a low Barium concentration in produced water (less than lppm). This
means there is a low probability of hard barium sulphate scale forming in
Lisburne wells once the GCWI pilot commences.
Production logging
o Injection profiles will be run on the LS-29 and any subsequent injection
wells in the LS pilot area
o PPROF production profile logs will be run to determine source of water
production if necessary
o RST logging may be an option for surveillance in LS wells offset to the LS-
29. The Lisburne subsurface team is currently evaluating the potential of
RST logging in Lisburne wells.
Static pressure surveys
o Response should result in higher reservoir pressures in the LS area
Injection wellhead pressures
o Wellhead injection pressures will be closely monitored to ensure bottom
hole injection pressures do not exceed the reservoir fracture gradient
o A choking system will be installed to lower the surface injection line
pressures to the desired wellhead injection pressure
Injection well rates will be measured daily and allocated
17
SECTION M -MITIGATION PLAN FOR RAPID WATER BREAKTHROUGH
The favorable mobility ratio of water displacing gas in the gas cap should reduce the
water breakthrough time. However, water breakthrough is likely to eventually occur in
some upstructure LS producers. In the worst case scenario of rapid water breakthrough,
risk mitigation options are available.
If early water breakthrough occurs and injection profile logs indicate the majority of
water entering the top of zone 6 in the LS-29 injection well, one option would be to
perform wellwork to shut off injection into upper zone 6 at the LCU truncation surface
and inject only into lower zone 6 and zone 5.
Another option would be to halt all water injection and produce off the water that has
broken through, restoring the production wells to their status prior to the LS GCWI Pilot
project. The producing wells should have the ability to produce off the breakthrough
water over time, since all wells in the area produce at high gas rates and high GORs. The
average gas rate of active wells in the LS pad area expected to benefit from LS GCWI is
17,400 mscfd. The average produced GOR of active wells in the LS pad area expected to
benefit from LS GCWI is approximately 35,500 scf/stb. Considering that a high gas lift rate
on a high water cut well would be 4 MMscfd, these gas rates appear high enough to
produce off any breakthrough water production over time. The LS pad Lisburne wells
produce at low water cuts. Exhibit M-1 is a table of the gas production rate and produced
GOR from recent well tests on active wells in the LS pad area expected to benefit from L5
GCWI.
18
LISBURNE
GAS CAY
WATER INJECTION
PILOT YxoJECT
EXHIBITS
Exhibit B-1
~.! LISBURNE FIELD, WAHOO RESERVOIR -DRILL SITE LISBURNE L5 t :36,000
IJ p PROPOSED GAS CAP WATER INJECTION PILOT PROJECT o s,ooo s,ooo Fit
7(x1[xY) 705000 710000 715000 720000 725000
-- ~ w
CL ~
caNORTHERN BOUNDING FAULT
7
26
25 3 C1
~u~~ 2
isu~NO (RESERVOIR LIMIT )
2a
GCWI Injection Well
LISBURNE PA
¢ aL5-29 L5-36
2 NIAKUK
~ ISLANDS
L5- A
L5-33 35 L5-2836 HEAID `~
32 33 L5-25 vT. i
~ I' SNK
L Guuo2
~
0~ ~ ~ ~ ~
1
28 L5-26.
~ L5-28ALi ~ ~
- ,
a6
- ~ ~
,~ t?UG L5 21
L5-23
- - -
~~
~ _
~
~ c --- -- -- - --- -
-- -- _ -
N
T 11
~ ;~~ --
_ ~~,,~,~
_ - '~,
',
L5-31 ~ L5-32
~
T 1 ~~ N `° -'- ~ -- ~
~ 4
L5-
I'll ('/ )! /(1 i : IS.'1 }' _ _ ~ - ~ ~ I
1
N ~
iakuk Sea Water Line
L5-19 L5-i3,
L5-17
L5_~9 _ .. 3 ? ~~ ,
- ~- '~ L5-16AL2 ~ 6
~- - -
-- -- -
- L5- 8
} ___ _ _ _ L5-16AL1
L5-15 L5-17A L5-16
DSLS _ _
L5-16A ~l
L2-32 L3-01
L5-05 L5-12
L5-01
-~
L3-02 ~ 1 ~ ,,
" ~ ~
9
L3-05
~~!~
~ ~
~
L4-12
j ,, ~
L5-09 i
TOTAL DEPTH WELL LOCATION ~
L5-08
L5-04 w i_~
~ ~ ~_
BPXA Cartography; ms15592.dgn
•
Exhibit B-2
h LISBURNE FIELD, WAH00 RESERVOIR -DRILL SITE LISBURNE L5 1:36,000
IJ p PROPOSED GAS CAP WATER INJECTION PILOT PROJECT o 3,000 s,ooo Fit
700000 7osooo 710000 715000 7zoooo 72sooo
we-os ~ ~\ \ ~ u, I
NK-07A NK07 ~ NK-01A `fl ~ NK-43
NK-20
NORTHERN BOUNDING FAULT 27 ~~ -~~ ~ ~- \ , `' 25 NK-12 `IJ
GULL ISLAND (RESERVOIR LIMIT) ~, ~ ~ NK-61 ~\ \ `• NK-62A NK-62
28 ` ~ y ~ NK-16
GCWI In'ection Welt ~~ ~~V '` ~
1 ~~ NK 19A : NK-05 ' NK21
~\ ~ ,
Lisburne Wahoo Formation ~ ` ~~ ~ ~
in L5-29 Well - ~. \~ ~ ~ NK-19 / NK 18 LISBURNE PA
~ -8485 FT ND SS to -9150 FT ND SS a L5-29 LS-36 ~~ ~~ ~ ~\ ~' ~ ~j ~ j:' ;
O
NIAKUK ~ .\ ;. NK-22A
~ ~~ ISLANDS - 'I~SAGD ~'/
LS 33 35 ~ ~, t~~`ALD ~31
32 3 LS-25 34 LS-28 ~, ~ P,t l~ .
~. . ~~, ~ L5-zs , USNK
GULL-02 ~ „ •-
L1-28 ~` ~~ `,L5.28AL1
'~ `~
tJ~ ' LS-21
:~ G ~-~ L5-31 . - - - -
~ LS-32
T 1 1 f J ~- -- ~ LS-24
L5-1s I ~-1sA Niakuk Sea Water Line
-~ -._~
__ / __ 6
1 _ ____- ----~___ _ 2 a
- ~ Ls-1 e
LGI-04 - - _ - __
LS-17 - , ~~ _ -- - - _ ,_
_- F.
L5-15 _,-- _. _ _. - ..-- - .- - i r\ L5.16AL1
L5-17A \` L5-16
PSI-08 DSL5~` _
PSI-10
LS•16A
L2-32 L3-O1 ~
SI-06 PSI-07 L5-05 L5-12
- PSI-09 / L5-01 ~ i
EBAYST-01 L3-02 ~ 12
PSI-OS ~ 5+ 10 / w ~ w -
., ~`~ ~ ~ c~ L4-12
L3-05 ~ I ~
~ ~ L5-09
Psl-o1 TOTAL DEPTH WELL LOCATION
~ LS-OB LS-04
avxn Cenm~aonv msi Y.a2r eM
•
C7
•
Exhibit B-3
Bottom-hole Location for the L5-29 Injection Well
Coordinates are Alaska State Plane 4
Well Coordinate at Top Wahoo Coordinate at TD
ASP4 X ASP4 Y ASP4 X ASP4 Y
L5-29 710517.76 5982357.88 709930.25 5982945.00
Exhibit C-1
• Surface Pipeline and Pad Work!•
~ ~~
.:, ti I
;, i 1 I ,,
e~u~,e9 '1 Ij I ^
;II I
1I
1
• I
,~-
~r +~+
( .i1 '
I
l
F; `\
~.4~~~
I ~
^
I~
^ I I ' Demoand Replace
I Exietinp We^touse
~ ~'
^ I Ilk,
I 117;
^ I II
^ I ' I I Proposed
I ~ be Road
I I
o ~
I I
I
^ I i, I
^ I !1 1
i (
^
I
I ~~ ~
,"~~I I ^ I ~I i
pro 1 ~ ~ I ^ I
Seawater I action file 1 p'i ~ I; I ~
^ I ~1
I
(4) I ~ I ~ 'f
.~. 1 ~` y _ ~ ~ 1
_~
~ _- ~ y ---
1 yl
~~
l \ I ~~~ ti
~ ~~~.
t3uried Portico dLine / / t I ~. v
1 i r ~
i f ~-~ ~ ~
~. ~ r~
j (~ f
f
Approra mate Lacaitiort far
Hot-tap into Ebatirtg
t0' Seawater lira
~ ~ -_- __ BP DCPLORATION (ALASKA) INC.
~/~ -- ~a
/ / ~ ~ PRUDHOE BAY UNIT - DSLS
~ / I ~ LISBURNE PILOT GAS CAP
~__Il 1 ~~, WATER INJECTION
~ I~ f ~t' ICE ROAD MAP
/ f Ssptemger 2007 P ~ 200' 9
!"'r`'
Exhibit D-1
L5-29 Well Log and Completion Schematic
L5-29 Open Hole Logs IWe,~,lb:o:re Schematic
+"TM
~2k1 y
''J7 r
~
Y~f b1 ~J~ • ~1 M :1 -M 5 :~- ~' 8W
•I
Y
-
x:•11 I ~•: i5 ~_ , ~, .
~
1 8500
-'- 3600 ' ~.
X3700 -- - ~ iA
~
.
~ _ .
a
prx
_ .~
-_j . ~~
_._ _
_
_ w ~ 13800 _ _ a rzt
_ _
M 1
-~
-~- fJeutron Poroe~y
Shaded O'eeit _
-
-- --
`
+` _ __
- ~ - - - - ?.~ F7S
_ _ ~. YY~
=r_:L7 Q 11000 _
-~~ --- ~
- - __
1100
- ~, i'L~
__ _ _ - __. _ U lLR
-'~
~v
~ only V~fahao Zane ~ is open above plug ~
~..~~,
KI11~3~1 i ?
-!- • ~Si T
TTTI i90G d . . ~
awoc: S. .9
{--1ti 17
v~~ •i
~~ N
47100 1 ~
~~
-ii!}
xu~w ~ E
z.
-~- r~a~
4:IiW ~ S
~~
~~ ~ ~
....
~w ~Mq •!f
r ••M-pr p
1 ~ww
s• 1 .~
~ ~
rr YN
rr
~ ;w^
r ~.
L5.29 = ~~ r.,YY...
f~TT~
i. slA
~I- WW
•ir 1Fl1-}ip•Y
~- ~ /~!~
i
•
•
Exhibit E-1
L5-2g Wellbore Schematic
TRH= d' n+~erov
C _
AT = AXSSC~J
K8. ELEV = 80~D'
8 . = Pi4
KOP = 120D'
Maz Angt = 83 ~ 85 '
DaermMQ= 14218'
flatumTVd = 8900` SS
I t~-s.~' csc~. 7~»,1r-eD. ro= i2_~4r I-i 53oa•
Minimum ~ = 219T" ~ 13660'
Z-7/8" AVA BNG NO GO NIPPLE
x
7323G H5-t:r~°X4-it2"xo,t3=3958'
PEf2RJRA'= ~Ot l St3hA44RY
Rt3= LOC,: OA Z OEfGRY LOG CF08J10t87
A NGLE AT TO P PEItF= 48 ~t 3685
Ne4~ RPf=r to PFCduclinn 11G Enr hicrnri~sl n®A el its
AL pnlSgs
4' t 1..35 ,~13 ~ C 031 11
t-tlild' f 138t6,18,25,35< C D1130'90
1-1tP1d'" t 41~~i,84,92,98 G D7F3G'8D
t-11118' 4 13903,Q9,13,19. C 01+3!3'99
t-11114' 1 38,41,49,43,78, C 01,+38'90
t-1t1t8 1 85.:94 C 01138'90
S-1i7td' i 14W2,12,20,22. C 01~~9D
1-11118" 1 46,32,58 G 01138'90
2.7:8" '8G. 8.6~Y. L-8D, .D058 bpf, O = 2.441' 13663'
7' LNR 29~, L-8fi.0D371 bp[, Q=6.184' H 14653'
A BY C
1 [V .' IGNAL flOA+PI. .D
' 41 Y
t, ~ t S NV G4NVA
1 L
t '1 1
F I1L VIIS /tCi NY, 17=~.fi9
' PXN RUfl SEi CXd 03321 it41
19.3:8" C3G, 47#. L-80. IQ= 8.881' 1
z-brli_,4~vn cw~n~ ~=ar
arm quG sE=aN o~r~Dr9D
L'St7JRVEUNR
WELL- L5-29
PERNR Pb: t87-0A60
AFlNc 50-029-213'24.00
2t63' FSL 6145' Fr"L. Sac. 02. T11 K R16E
3AFElY NOTES:CAT Il35V li2$ (PPM)
L ~ -11 ~ 20Q. PXN PLUG IN pl NIP ~ 13333' ~ BNP
(~ PLUG IN BNi NP ~ 13688x_
2225' TCAMCCIBAL-C}SSSVK~=
1 1 ~
• •
Exhibit E-2
L5-25 Wellbore Schematic
Q4iE REV BY ~AdAB~ITS p4TE REV SY COMh£NrS
02!11!89 OfiGINAE CCdN PLEiION Od+07lOT JCA1P10.G PULL XXN RUG (5t10.~f17)! FLT!
30/02!01 RPU RRECfI~tS Od{21l07 JG LO H4 CH'
03t23r05 WiSilLH PXNPLUG ACTION OTIOd!07 SW~G~J ~fUPPERPATCH
10r021OS RCTIILH PXNPLIXi PULtEOk2~Ei
12101!08 RGTl7LH PXNTiLK3 fitLl®tXXN SET
0 03V07 J3-1lTLH GLV (7U(Dit28 )
1.IS~fRNE UNfT
U'1~L: L5-25
PERMT No: 88-135
API No; 50-029-21$8800
T11N. 815E A37.02 FH. X13.13 FNL
33P EzPioraNoR {Aloe ka)
tELl. HEAD hCEif 4Y ~ ~ - i ~ I SAFETY NdTES: CAT t 355V H25 (PPNI) 4D
CTUATt]R ALEX SOP ,F(.J'
B.ELEV 55
• •
Exhibit E-3
LS-33 Wellbore Schematic
TREE • 2.9:16` FNC
at z
ACT`~IATt1R • AXELS~
K9. EllV • 59.0"
K#a • 130Q"
N:~tt Angie - d7 10360`
Datum. MD • 31364'
Datum TVD • 6916' o-S
L5-33
SAFETY NOTES: CAT 1 SS SV H25 (PPM) 80
~~
I Tl~SSV , D • 2.312'
CrBaK:A L IN.IL'C7~k ltANDREIS
Dev ~YC~ vv uTai
?9 KBIAG•LTS iii tu'f
CA 8 LIF'' UA I~:RL4 S
inllmum I 1. ' ~ 11011'
2 Tr8" AVA NIP W1 BPC Sl.V
1 a-3'd' CSG, d5..gt, J-f 5 6Q • 9.956`
ST -1D ND DEV 'Y FE VLV LATgi FCRT 0,4°E
1 4t K . d
a 6t77 say' 3z TE'GPD DV TG a
3 a39D 6758 sT TE•TG~ ^.V TG 0
d i[Qa3 7362 46 TE?GFD DV TG 0
5 to3ta aT79 47 TE?GPD RK® eJT o
'-Wi8° X 2-7t8° Si(R SA B P!CR D • 3.89x'
PRO~DtJCTDN MA~IDREZS
10522' H1-5~8' X 5-tf2° 34T Fh' FL4 lkR ri{aIR
7.518' CSG. c'9.76. L-sO. ID• 6.875'
PE4¢O~RATION S4MtARY
R~ LQG: SS4S Civl4F 0611&89
AMGLEATTOP ~_: 39~ 1 T1a+ti
hbtt: RE°flT10 ROtWCtlOnDBT01'h~btkal ~endaa
tteTERVAL riSgz DA
SwPAC-E 2 ^4R
F~C,RATIDY DATA
t10ft` a-iA8' AVA BPL'JP D- 2.312"
'BPCSLY'41N1-19-99, D•#.875
1t013' Z•7+a' AVA BLAST.sTS
{ Ti 613'-1 T>1+t3'}, D • 2dd t"
110dd' BKR LaC SEAL ASSY, L~• 2.406'
IOdS'eim `-t;a' x 2.718' BKR °B-1 PKR, ea
4{IU[q LJ?.161° L9{• R.4f: IJQ IA .? b5T
1 z-7.a°
G3- 24st' H f 10'S8'
-a:e3r I-
~ t 1038' r--~a-7.Q° 3ef l S CS t TTL, ~ - a_°
71060' B.ifi T? LOGGED C3FaS'97
DATE f~V SY CCMNEhTS DATE REV BY C~+IatErlTS
07}S65$9 CRIG64AL C4bP1.E'FDI~ Da'a3.~@7 '9t OATLdA bfl
ie MV /`
1213t! 1 ti y
11~2t~03 lADRiPJC WLEGE£MACCRIAtC's~N
LIS BI ICiiE tNt7
i'!EL': Ls-~
Farrar roo= ,a~-aa~o
AFTNO: sa-a2~2~9a3•ao
S~ 2. Ti t N.1t1 sE 2363' fSl 8 142'
• •
Exhibit E-4
LS36 Wellbore Schematic
T!'~E • 2-9'16' FMC
lYB.LH,a.AJ • FMC
ALfi.IATOR• Axasa'i
CB.'.fV • 59A'
~F fLEV • MA
i(CP ~ 1300'
11ax Ars k • ~ 1D4iID'
Saturn A,45,1 • 12268'
^.a~wcnTVD- a9W'SS
1
Minimum ®= 2205" ~ 11624'
2-718" OTIS XN NIPPLE
-9.950` H 4953'
L ~ _w ~ SAFETY NOTES: CAT B S SSV kt2S ~PPfd) 75
7922' 2.7!H°CA1,tTRDP-#A TRSS3V,D•2.312'
GI^fNlCAL eLfCfK?4 MA-~pRlLS
ST N'i °YD DN TYPE VlV LATgi POR" DATE
1 2018 191: Z9 K2ANG-L 6K•2
r!ea x ~~~aunns~ a
ST W TS7D DfJ .~~TYPE-" "VLV IAT~ PGRT DATE
a8
2 850a 506E as TE~TiGfD Tc
3 8935 6762. .f9 TE-TGFO TG
1863 7987 48 TE-TGFD TD
S 11336 8302. S1 Tf-TGFD 't~C
17399 ~-"~2~T~"BKRL{~CSfALASSY.~•24d1"
375'@kfl 7-g~' X2-7~'a' 6i(R O6 fKR, ID • 33°IY
77476' TOPOfa4T`~1f6AGlC51.V
17424` 7-S~J" Jts-t+'2° ®OT L"~1RHGR
7•S~a" CSG. 23.7:F, L-80. Iq ~ 5.87'" H 17
PE?i~CM/t TtDM S~64N RY
R~ _oo< cra bPCiRDSrTY) DA f)N 061a7~a9
ANGI.EATTOPPE4F:3Z~ 1faTS'
WCCe: Refer b ProdfucOd1 DS for IYirAr!C2r' er' da•.a
v@. YPF PlTf9VAL 4pnF.ag2 DATE
SEA PAGE2 f~CR?°H8fORAT#DN CATA
I 72767' 1
15-1 ti lNR 173f. L-9D, O.a7232 Epf„ D ~ II.892' I'
~ 11614' ~-j~~'~5-o~xN~~~•2.2as
17636' 2-7Fa' SHEAR :A1fP'~T.1D • 2.361"
17633' _Lld7'+TIdGJNAVAlU1®tf
77835' H5-1t2'C'GxTL^S+^+PISR
~ATf RfV 3Y CGMMEk'7S DATE ~ifV BY GBNhENT.;
0793'89 GRIGeiAI CGM~E?IOR
Ot~n9+o1 SIS-GS GQMYER'="fdTC}G4NVAS
93+n2'D1 SIS-lG fNAI
1?~31.!01 GHI.'P GDRRfCRCN3
a~n3~o7 ~ oATLM
LIS BlRkf 1Yfr
V~'r-z: l3"36
P9tMT No- 189.0369
A R `!o: 50-02421433-0D
Tf 1 N. ?i15f 2387' fSL 8.37` R
1~ Ex¢lorailon (Jitask a8
• •
Exhibit E-5
L5-21 Wellbore Schematic
-fiEE: 7.~trc cuf.
WELCHEAD= FMC
AC'ty4 R= AXB.SON
s
_
Max Aogle : 59 ~ 5EU 0
datumMCB= 12398'
DatumTVD= ~9fA'SS
Minimum ID = 1.812"~ 12403'
2.318" CAMCQ D NPPIE
~TOPOF7'LNRHGR ~ 77t135'~
,!.-8d,4.D0579bpf,~=2441" 11911'
Se'8` CSG. 47+. L-~. ~ =8.881" 121163'
2-?:9" TT? fi.5it_ i-gf_ B05i~ hof_ ~= 2.~4f`
F~RAT1aHSUMI~aRr
REF LOG. Z DL CIA ON Oli~.t!$7
ANGL=ATTDPP~:32~ 121®1'
Noce: Refv to Psoduction G8 fa historical rf 3ats
SIZE SPP INTERVAL O ! x QA'E
SEE PIB;FORAT~1 I1A A
ONPA~2
= 3 1 E4'
L5-21
n
SAFETY FgrTB: CAT 11 N0 SSSY H2S (PPM) 6Q
COULOMT SHFT SLY TO IdIN WR SSSV-LOCfiEO
OUT_*SETK-VALVEtUf2Tl91~ •RSH2"X 13N6'
SS HYD HOSE END CAP HUNG UP IN PROFILE 341
t. t SG. 718" Pt3iF BAL LS ON TOP OF Plot FROM
ST11t. JET CUf TAIL PIPE ~ 72AW' 9019QP1i9 TO
ESTABLISH COMM BELOW 80T PKR
JD= 2.312", LOtKi:DOFEN
L 1.4T
11 1 1 d
2 49£4 58 TGPD SO RK ~ 03l3€3A)8
3 6968 9081 57 TC?D CRAY TG r7 D?121,89
4 11457 7877 48 TC~PCf CAA'! TG O D2<21A39
3 11A34 8321 3t~ TGPD RKEp RK O OZ'21$9
12405' I-I 2-S'8' CAM00 D N 1? 'O =
7 a~ aa7' I-12-ass- x x.7:13- ~co ie.tw~, a =
12408' 2-718' 1hYEG, Ei= 2441"
12ao9' -[-e:a~'TtoGUtwVAt.ABLE1
1 C A Y
tOf1718T OR1G~94LCOMPLEfION
02Q1189 RWO
a1,n2ms ???m.s~t xxnl ~uG sEr
03,GOA8 OAVr'PJC GLV Cr0
04l12A9 JCAVPJC PULLXXNF7JJG 11x80'
A
L66t t:NiT
1Y~1.= L5-21
PERAAR Noc 167-0..'70
APINo_ aa429-2173'-~
~C2.Tt1TtR15E 194TFSL&15T
BPExpbntion (Alaska)
•
Exhibit F-1
Injection Seawater Composition
GPMA Seawater Dissolved Solids
Beaufort Sea 1 -Summer Beaufort Sea 2 -Winter
Determination
H 7.5 7.8
Calcium 196 365
Ma nesium 631 1190
Sodium calc 5680"" 10400""
Sodium AA
Potassium
Strontium 0
Barium 0
Iron 0
H drox I
Carbonate
Bicarbonate 85 142
Chloride 9880 18200
Sulfate 1380 2490
Total Dissolved Solids 17852 32787
** Sodium + Potassium
Exhibit J-1
Offset Well Confinement for Lisburne LS GCWI Pilot Project
Well Status Cement LOT/FIT Comments
Log
L5-29 Shut-in gas No CBL FIT: 12.5 Ib/gal Cemented 9-5/8" intermediate casing w/ 150 sx of lead 50/50
injection. on 9-5/8" @ 8,498-ft TVD. poz G cement @ 12.0 Ib/gal and 500 sx of tail type G cement
Planned GCWI csg. C 15.8 Ib/gal. No losses during displacement. Calculated top
pilot injector. of cement C 12,400' MD. FIT to 12.5 Ib/gal equivalent mud
weight, no leak-off observed.
CET on 7" Cemented 7" liner w/ 495 sx of 35/65 poz cement C~ 14.0 Ib/gal
liner. and 75 sx of type G cement C~ 15.8 Ib/gal. Lost 98 bbls during
cementing operation. CET log indicates cement quality
sufficient for zonal isolation from 13,519 -13,552' MD (33')
and 13,561'MD -13,670' MD (109').
L5-25 Shut-in No CBL FIT: 12.6 Ib/gal Cemented 9-5/8" intermediate casing w/ 122 bbls (600 sx)
producer. TxIA on 9-5/8" C~ 8,603-ft TVD. class G cement C~ 15.8 Ib/gal. No report of losses during
comm. csg. displacement. FIT to 12.6 Ib/gal, no leak-off observed.
CBT on 7" Cemented 7" liner w/ 150 bbls (552 sx) C~ 14.8 Ib/gal, normal
liner. displacement. CBT showed good cement from TD to 15680'
MD and 15540' to 15000' MD.
L5-36 Cycle No CBL FIT: 12.8 Ib/gal Cemented 7-5/8" intermediate casing with 105 bbls (507 sx)
Producer on 7-5/8" C 8,537-ft TVD. batch mixed class G cement @ 15.8 Ib/gal. Full returns
csg. throughout cementing operation. Successful FIT to 12.8 Ib/gal
equivalent mud weight, no leak-off observed.
CBL on 5-
1/2" liner. Cemented 5-1/2" liner w/ 165 sx of Self Stress II cement C~
14.8 Ib/gal, no reported losses. CBL showed fair cement from
TD to 11900' MD.
•
Well Status Cement
Log LOT/FIT Comments
L5-33 Cycle No data. 7-5/8" casing cemented with 400 sx of SS II.
Producer
CET on 5- 5-1/2" liner cemented with 165 sx class G. CET showed good
1/2" liner. cement bond over most of the liner.
L5-21 Cycle No CBL FIT: 12.5 Ib/gal Cemented 9-5/8" intermediate casing with 150 sx 50/50 poz G
Producer C~ 8,681-ft TVD. cement ~ 12.0 Ib/gal and 520 sx class G cement @ 15.8
Ib/gal. No report of losses during displacement. Successful
FIT to 12.5 Ib/gal equivalent mud weight, no leak-off observed.
CBL on 7"
liner. Cemented 7" liner with 310 sxs 35/65 poz G cement C«3 14.0
Ib/gal. No report of losses during displacement. CBL shows
fair cement over entire interval.
• •
Exhibit K-1
Theoretical Model of Lisburne Reservoir Illustrating Flow Paths
T
MAJOR FAULT ZONE
Vertical + lateral
communication
SAZ
High•permeability layer
along unconformity
MEGAFRACTURE
Subseismic fault
Variable spacing
DEPOSITIONAL
LAYERING
• 10% cutoff
• Thin layers separated
by nonpay
• Low kv between layers
• Stratabound fractures
(after Jameson, 1994)
Idealized geologic model of the Lisburne reservoir showing the importance of
a variety of porosity and permeability controls on reservoir performance,
including major fault zones, the subunconformity alteration zone (SAZ),
megafractures and rock matrix properties within the depositional layering.
(J. Jameson, AAPG Bulletin, V. 78, No. 11 (November 1994), P. 1651-1678)
~~
L
Exhibit M-1
Gas Production Data for L5 Pad Active Wells
Wellname
Well Test
Date Gas
Production
Rate (mscfd)
Produced GOR
(scf/stb)
L5-05 12/11 /2007 13, 926 30,155
L5-13 11/21/2007 12,306 46,568
L5-16A 12/14/2007 22,658 39,056
L5-17A 12/16/2007 22,684 36,070
L5-18 12/15/2007 8,687 22,480
L5-21 12/16/2007 8,741 20,213
L5-23 12/12/2007 23,846 31,004
L5-24 11 /27/2007 21,276 33,190
L5-28A 12/09/2007 27,001 45,385
L5-31 12/11 /2007 19,362 38,903
L5-32 11 /23/2007 14,321 36,702
L5-33 12/12/2007 16, 431 39, 931
L5-36 08/06/2007 15,220 42,398
=#2
Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC
Group 1 IPA Group 2 GPMA Group 3 Satellites
~--'~._--"-"-'--~-- ---- t-------------~---------
Annual Surveillance Report 15-Mar 15-Jun 15-Sep
~--- -----~----------------- t---------------~-------~--- u.'__._.. - ------~-----------
-_._-._-~----~._----- ---
Annual Overview Presentation 22-Mar 22-Jun 22-Sep
--.-.-------- ---
------. - --- ----
Production Period to be Covered Jan 1-Dec 31 Apr 1-Mar 31 Jul1-Jun 30
.
Amends Order/Rule
Order Date
Comment
Group 1-:.1_~A ºil~()C?~~_______
Prudhoe Oil Pool C0341 D Rule 11
,.---------....---..------.-..........-...-----...---,~---_._----~_._-----
Put River Oil Pool C0559
11/30/2001
-~---~--~---------.--_.__.-
11/22/2005
---+
I Note C0341 E (modified Pool Definition to
include a portion of Put River Sandstone)
Corrected 2/14/2006
--- ,.----
----~---_._.__.._,-~----
Groue_ 2 --ºf=)IVI~()iLr:'()()~~__________
.. --------'"-~--~_._-
_._--_.~~----,--~----~--._---_.
Lisburne C0207, 207 A
.--.-------------------------.- -----~---~._.._---_.,_._-~-~-_.-
Niakuk C0329A Rule 9
-------_..__._-~_. .~--
__________ }~ort~_p~~~~~~ Bay C0345 Rule 8
___ ___ ________Pt. ~clntyr~___fO~_17B Rule 15
Raven Oil Pool C0570 Rule 10
..._-_._-_.__._.._---~~_._-~--_..~_.,.---_.~.----_._--_.__._.~.-----~~----
West Beach Oil Pool C0311 BRule 13
No rule on SUr'lleillance report(;_
6/4/1996
12/16/1994
4/19/2000
8/9/2006
8/1/2000
..-------- ------------~~-_..~-.,_.-~~.._----~'-'---
"--,._.~-..,-._~-_.._---,_.._--~.....
----~-------~.._._,._-----~----"--_.._--
---t----------------~-----------
.
G ~C?IJ P~..-~!~~~()~_ª~!!ll~~~.Q!~~ool~_
Aurora
-----,,---..---.----
Boreallis
~___._.. ...________~__~____M~._·__·__
__~~'!i9_t!.t..ªu!l
Orion
--,._-~---
Polaris
----~~--
~---~._-_.. --_._._-~-~,------_.-
-------_._....._~~
C0457B Rule 8 6/25/2004 ________ico~rected 8/~/..?_º_º_~___
------C0471 Ruie-.f-- 5/29/2002
-----_.._.._._..._~._._.,-----~---_.._~--- -_._-~- ------_._-_._---~_.,..._.__..._---,.__._~._----_._._.~-.--.
C0452 Rule 11 11/15/2000!
C0505ÄI:~ule 9-- ---- 4/2812006-----1---·-----·-----------
--------------------- ------------------------+-------------------------- - -------
C0484A Rule 9 11/3/2005 I
l" ....... l.~ .. -. .".... ~..., . _·"._0,,_- .-r--........ ..........-.....J.
.
.
Subjcct: [Fwd: [Fwd: Re: surveillance report dates ]
From: Jane Williamson <jane _ williamson@admin.state.ak.us>
Datc: Fri, 20 Apr 2007 13:03:59 -0800
To: Jody J Colombie <jody_colombie@admin.state.ak.us>, Dave Roby <daveJoby@admin.state.ak.us>,
Cathy P Foerster <cathy _ foerster@admin.state.ak.us>, Alan J Birnbaum
<alan _ bimbaum@law.state.ak.us>
cc: Stephen E Mcmains <steve_mcmains@admin.state.ak.us>, art Saltmarsh
<art _ saltmarsh@admin.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us>
There is sornething I didn't get around to before left and that was to administratively amend the CDs for
PBU to include reporting dates agreed to verbally with BP (and DNR). Really, only pt. Mcintyre and Borealis
have the wrong dates in the CO's. The others are either ok, or not explicit. Attached are the cas affected_
I'rn not sure how you want to handle. Jody. Please put this in the following CO files along with the
attachrnent.
Group 1 - IP A Oil Pools
Prudhoe Oil Pool C0341D
Put River Oil Pool C0559
Group 2 - GPMA Oil Pools
Lisburne C0207, 207 A
Niakuk C0329A Rule 9
North Prudhoe Bay C0345
Pt. McIntyre C0317B
Raven Oil Pool C0570
West Beach Oil Pool C0311 B
Group 3 - Prudhoe Satellite Oil Pools
Aurora C0457B
Boreallis C0471
Midnight Sun C0452
Orion C0505A
Polaris C0484A
-------- Original Message --------
Subject:Re: surveillance report dates
Date:Thu, 31 Aug 2006 17:27:45 -0800
From:Jane Williamson <jane 'Nilliamson(â!aclmin.state.ak.us>
Organization:State of Alaska
To:Lenig, David C <David.Lenig(a;bp.com>
References:<CBF4D8E92B5A 70479F64416582F6A 17CB81 AEO(2l;bp 1 ancexOOS.bp 1.ad.bp.com>
Oops
Lenig, David C wrote:
Hi Jane.
of3
4/23/2007 9:50 AM
l& ....... l" .. ....... . '-_. ........& . ....................... . -t'........ .............-....J.1
.
.
I didn't get th2 attachnlent.
Davjc1
From: Jane Williamson [,^,^:?¡;~G:j2n-=.: jl,'¡!;:¡í,:è':,-;@C__\^ -:;':::::::-:;,:')5J
Sent: Thursday, August 31,20065:14 PM
To: Lenig, David C
Subject: Re: surveillance report dates
E-mail is fine_
Attached is a list of the pools and orderslrules that will be arnended with the Adrnin approval. Take a look and
see if this looks right to you. (Note, I'rn only listing the rules that are affected by the new dates - there may be
additional amendrnents unrelated to the surveillance requirernents that "ve not listed.)
I'm flexible on the date for the Overview presentation_ I'd be fine with specifying it to be within one or two months
of the report date rather than the POD overview that you've noted_ What would you prefer?
Lenig, David C wrote:
Jane,
Here is a table showing the dates for the various Reports and
Presentations. I've added the production period as well. The IPA review
date remains problematic due to the proximity to spring break but we
seem to work around it each year.
Would you prefer that I put this in a letter requesting the changes? I
know we talked about this a little while ago I just haven't found the
time.
Thanks,
David
Plan of Development
Production Period
Jull-Jun30
IPA GPMA
March 15 June 15 September 15
March 22 June 22 September 22
March 30 June 30 September 30
Janl-Dec31 Aprl-Mar31
Satellites
Annual Surveillance Report
Annual Overview Presentation
-----Original Message-----
From: Jane Williamson [mailto:jane ,,villiamson@adrnin.state.ak.us]
Sent: Thursday, August 3~~06 2:30 PM
To: Lenig, David C
Subject: surveillance report dates.
Hi David.
When you get a second, could you please send back an e-mail that lists
all the surveillance report dates that we've agreed to for all PBU pools
(including GPMA)? Also, do you have dates for surveillance reviews?
I'll go through the list and make sure the Conservation orders are
correctly worded, then put out administrative amendments as necessary.
I checked with Cammy and she said an e-mail is fine for starting the
, of3
4/23/2007 9:50 AM
t· ,~. i..' ...... .,_. 'J~~.. ..-...-...-- '-t'~"~ ·...-~·_··IJ
.
.
administrative action process.
Thanks.
T~~G
.}-_';'..l:"..,.,
1! i ?rr:SC,)I~~ P ~ <j :ll1{:; ~//111 ia:~sotl(c[¿~~:lr:~J. ~~,~. =:=2~'~--::, a:\., '_:s>
Senior Reservoir Engineer (907) 793-1226
Alaska Oil and Gas Conservation Commission
Content-Type: application/vnd.ms-excel
surveillance report.xls
Content-Encoding: base64
30f3
4/23/2007 9:50 AM
#1
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1'1
ARca Alaska, Inc.
Post Office Box 100360
Anchorage, Alaska 99510-0360
Telephone 907276 1215
Joseph A. Leone
October 28, 1996
Mr. David W. Jolmston, Chairman
Alaska Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501
Re: Request to Revise Conservation Order 207, Rule 7
Prudhoe Bay Field, Lisburne Oil Pool
Request to Revise Conservation Order 311, Rule 6
Prudhoe Bay Field, West Beach Oil Pool
RECEIVED
NOV 1 4 1996
Dear Mr. Johns ton:
Alaska Oil & Gas Cons. Commission
Anchorage
51 t Æ)--
?J> ~ ....
~~
I CQi~tM - ~j
COMM ¡ ¡
CO¡Y.~~=~C~ 1
R[:,~~~~: f>~~.::., "\"~_
SF\ ¡:r., \. '. I
NR~"-'~""'" '.'¡'"-'.-
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GEOL' ASS" { -
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STAr TECh'¡-
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~~
~.~.J . .,'
With reference to your letter, dated September 26, 1996, ARCO Alaska, Inc., BP Exploration
(Alaska), Inc., and Exxon Company are amending our July 8, 1996 correspondence to request that
the Commission only revise the requirements of Conservation Orders 207, Rule 7, for the Lisburne
Oil Pool and Conservation Order 311, Rule 6, for the West Beach Oil PooL At this time, we have
elected not to include the Point McIntyre and Niakuk Oil Pools in this request. The proposed rule
change modifies the safety valve system requirements for the Lisburne and West Beach Pools by
eliminating subsurface safety valves and requiring only surface safety valves in wells in these
Pools. The background, proposal, and justification for this request remains as stated in our July 8,
1996 correspondence. For clarity, a copy of the current rules and proposed new rules are attached
(Attachments 1-4).
On October 17, 1996, Mr. Kris Fuhr with ARCa Alaska, Inc. discussed our amended request with
Mr. Bob Crandall of your office. Please contact us if you have any questions or need more
information related to this matter. Our phone numbers are 263-4431, 564-5433, and 564-3689 for
the ARCO, BPX, and Exxon contacts respectively.
5:', incerely, , r¡ nJ
¡Î (Ì fA JJ ûLLu
Y~lY(/:B II .
(\ ~ ~
J! A. Leone r:;J":Å.. N. Bolea
Manager GPMA Asset Manager GPMA
ARCa Alaska, Inc. BP Exploration (Alaska), Inc.
t::::::?
Prod uction Manager-Alaska
Exxon Company USA
Attachments
)
)
Attachment 1
Current Conservation Order 207, Rule 7.
Rule 7. Automatic Shut-In Equipment
a) Any well which is capable of unassisted flow of hydrocarbons must be
equipped with
1) a fail-safe automatic surface safety valve (SSV) capable of
preventing an uncontrolled flow; and
2) a fail-safe automatic surface controlled subsurface safety valve
(SSSV). This valve must be in the tubing string and located below
permafrost. The valve must be capable of preventing an
uncontrolled flow. For operational necessity the Commission may
administratively waive the surface controlled requirement.
b) A representative of the Commission will witness performance tests at
times prescribed by the Commission to confirm that the SSV, SSSV, and
all associated equipment are in proper working condition.
c) When requested by the operator, a representative of the Commission will
witness IIno~flow testsll to verify that a well is no longer capable of
unassisted flow. Upon approval by the Commission, the operator will no
longer be required to maintain the SSSV1s in that well until any
subsequent workover or stimulation of the well makes it again capable of
unassisted flow. The Commission may require additional IIno-flow testsll
following subsequent well work. '
RECEIVED
NOV 1 4 1996
Alaska 011 & Gas Cons '''''m . .
Anch . \IV mISSIon
orage
\
Attachment 3
Current Conservation Order, 311, Rule 6.
Rule 6. Automatic Shut-in Equipment
(a) Upon completion, each well which is capable of unassisted flow of
hydrocarbons shall be equipped with:
i. a fail-safe automatic surface safety valve (SSV) capable of
preventing an uncontrolled flow.
(b)
(c)
(d)
ii. a fail-safe automatic subsurface safety valve (SSSV), unless
another type of subsurface valve is approved by the Commission,
installed in the tubing string below the base of the permafrost
capable of preventing an uncontrolled flow.
A well that is not capable of unassisted flow of hydrocarbons, as
determined by a uno-flowu, performance test witnessed by a Commission
representative or by other means, is not required to have fail-safe
automatic SSSVs.
For projects receiving Commission administrative approval, the
requirements for fail-safe SSSV equipment may be waived.
SSSVs may be temporarily removed as part of routine wellwork
operations without specific notice to, or authorization by, the
Commission.
RECEIVED
NOV 1 4 1996
Alaska Oll & Gas Cons. .''''......m .
Anchorage \NUI ISsJOn
