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CO 443 B
Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~~ ~~-~~ Order File Identifier Organizing (done) RE CAN Color Items: ^ Greyscale Items: ^ Poor Quality Originals: ^ Other: NOTES: BY: Maria Project Proofing BY: ~_ Maria Scanning Preparation BY: Maria Production Scanning r x 30 = + =TOTAL PAGES ~~ ~ ' ~~~ ~ (Count does not include cover sheet) Date: /s/ Stage 1 Page Count from Scanned File: ~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~/ YES NO BY: Maria Date: ~ I ~ ~ /s/ I' f~ I ~ ~I Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II it II I II II I ~ III ReScanned III IIIIIIIIIII IIIII BY: Maria Date: /s~ Comments about this file: Quality Checked III IIIIII III IIII II ,wa,aea iuuiuiiiiii~uii DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: Date: Ae,~a.~ee~.,~ uuiuiiiiiumi OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other:: Date: ~I~ ,iiiutuiimiu~i u ~n P 10/6/2005 Orders File Cover Page.doc • • INDEX CONSERVATIONORDER 4438 1. December 10, 2008 ConocoPhillips (Alaska) Inc. request to include KRU formation in the Alpine Pool and Expand the Alpine Pool 2. December 14, 2010 CPA application for MPM Multiphase Metering System (Appendices 3 and 4 of application are held confidential) CONSERVATIONORDER 443B ~~ • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for expansion of the Alpine Oil Pool and termination of the Nanuq-Kuparuk Oil Pool, and the removal of inter-well spacing requirements, Colville River Unit, Arctic Slope, Alaska Conservation Order No. 443B Docket Number: CO-08-40 Colville River Field Colville River Unit Alpine Oil Pool Expansion Nanuq-Kuparuk Oil Pool Termination March 26, 2009 IT APPEARING THAT: 1. ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, by letter dated October 10, 2008 and received December 17, 2008 by the Alaska Oil and Gas Conservation Commission (Commission), requests an order expanding the affected acreage and strata of the Alpine Oil Pool and terminating the Nanuq-Kuparuk Oil Pool. CPAI also requests that the 500-foot inter-well spacing requirement for the Alpine Oil Pool be removed. FINDINGS: 1. CPAI is the operator of the Colville River Unit and all non-unitized lands that are affected by this order. 2. CPAI and Anadarko Petroleum Corporation are the owners of the leases affected by this order. The State of Alaska and Arctic Slope Regional Corporation are the landowners of the affected lands. 3. The Iapetus No. 2 exploratory well, located in the north-central portion of the Colville River Unit (CRU) (see Figure 1, below), encountered normal pressures in the Kuparuk Formation (Kuparuk) (see Figure 2, below) when it was drilled during 2005. The Kuparuk is stratigraphically above the Alpine sandstone (Alpine) that is an informal part of the Kingak Formation 4. The Char No. 1 exploratory well, drilled about 1-1/4 miles southeast of Iapetus No. 2 during the winter 2007/2008 drilling season, encountered elevated pressures in the Kuparuk. 5. Two wells recently completed in the Colville Delta No. 1 Drilling Pad (CD1) area encountered elevated pressures of 4,500 psi to 4,600 psi in the Kuparuk. Normal pressure for the Kuparuk in this area is about 3,200 psi. 6. In the southern portion of the CRU, the Kuparuk produces oil from the CD4 Drilling Pad (CD4) area, which lies about 4 miles south-southwest of CD1; the oil is produced from the Nanuq-Kuparuk Oil Pool. See Conservation Order No. 563. 7. Subtle pressure changes in the CD4 area have occurred over the past two years; these pressure changes occurred following commencement of production from the Nanuq-Kuparuk Oil Pool. These changes suggest pressure communication between the Alpine and Kuparuk in this portion of the Colville River Unit. 8. Significant lost circulation events occurred while drilling the CD1-06 and CD1-14 wells, which are east of CD1. These events are attributed to subseismic-scale fractures or faults (i.e., fractures or faults that are too small to be visible on seismic lines) associated with a major fault that lies east of these wells. Water and gas injection into the Alpine reservoirs open to CD1-06 and CD1-14 apparently pressurized the overlying Kuparuk through these fractures or faults. 9. Well CD2-02, located about 5-1/2 miles west of CD1, encountered sand-on-sand contact between the Kuparuk and underlying Alpine. This contact is considered the mechanism responsible for the • • pressure communication between the Kuparuk and Alpine observed in the Char No. 1 exploratory well. The Iapetus No. 2 exploratory-well, drilled in 2005 about 1-1/4 miles northwest of Char No. 1, encountered normal pressures in the Kuparuk, but these normal pressures were encountered. before injection began in the CD2-02 well. 10. Pressure monitoring in wells open to the stratigraphically shallower Nanuq and Qannik Oil Pools shows no indication of pressure communication with the underlying Kuparuk and Alpine reservoirs. 11. Because the Kuparuk and Alpine reservoirs are in communication in the central and southern CRU, these reservoirs must be classified as a single oil pool according to AS 31.05.170(12). 12. The Alpine Oil Pool's affected acreage overlies much, but not all, of the Nanuq-Kuparuk Oil Pool, and therefore, the affected acreage of the Alpine Oil Pool must be expanded to include all of the Nanuq-Kuparuk Oil Pool acreage. 13. CPAI plans to drill additional development wells into the proposed expanded Alpine Oil Pool; those wells would be outside the affected acreage of the current Alpine Oil Pool. 14. Rule 3 of Conservation Order (CO) 443A stipulates that Alpine Oil Pool development wells must be spaced at least 500 feet from each other and from the exterior boundary of the affected area. Rule 3 of CO 563 does not include an inter-well spacing requirement for Nanuq-Kuparuk Oil Pool wells, but requires a 500-foot setback from an external property line where landownership or ownership changes. CPAI proposes to remove the 500-foot inter-well spacing requirement for the expanded Alpine Oil Pool. 15. Rule 11 of CO 443A allows the Commission to administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. CONCLUSIONS: 1. Pressure communication between the Alpine and Kuparuk in the CD1, CD2, and CD4 Pad development areas is demonstrated by drilling, production, and pressure measurement results. Fluid communication in these areas is highly likely. Therefore, under AS 31.05.170(12), these two reservoirs must be considered part of the same pool to ensure proper development of the resources. 2. Drilling, production, and pressure measurement results also demonstrate that the productive area of the pool likely extends beyond the currently defined boundaries, and therefore expansion of the geographic boundaries of the Alpine Oil Pool is appropriate to include likely future development areas and ensure proper development of the resources. 3. Eliminating the Nanuq-Kuparuk Oil Pool is appropriate given the statutory definition of a "pool" and that the Alpine Oil Pool will be expanded to include the acreage and strata currently assigned to the Nanuq-Kuparuk Oil Pool. 4. Eliminating the 500-foot inter-well spacing requirement will increase the operator's flexibility to place wells in optimal locations for resource development and thereby promote more efficient resource development, while maintaining the 500-foot setback from property boundaries where landownership or ownership changes will protect the correlative rights of offset landowners and owners. Thus, this change will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. 5. Amending CO 443A to incorporate the Nanuq-Kuparuk Oil Pool into the Alpine Oil Pool and to expand the geographic boundaries of the Alpine Oil Pool is consistent with the provisions of AS 31.05 and will promote more effective resource development by allowing the resources to be developed as a single accumulation. Accordingly, the Alpine Oil Pool expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Conservation Order No. 443E Effective March 26, 2009 Page 2 of 8 • • NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes CO 443A, issued October 7, 2004 and corrected January 17, 2006, and CO 563, issued December 5, 2005. The findings, conclusions, and administrative records for CO 443A and CO 563 are adopted by reference and incorporated in this decision, except where inconsistent with this Conservation Order. The following rules, in addition to any other requirements (including the statewide requirements of 20 AAC 25) that are not superseded by these rules, apply to the Alpine Oil Pool within the following affected area: Umiat Meridian Townshi Ran a Sections TION R3E 1 TION R4E 1, 2, 3, 4, 5, 6 T 1 ON RSE 3, 4, 5, 6 T11N R3E 1, 2, 11, 12, 13, 14, 23, 24, 25, 26, 36 T11N R4E All T11N RSE 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 27, 28,29,30,31,32,33,34 T12N R3E 25, 26, 35, 36 T12N R4E 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N RSE 13, 14, 15, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 Figure 1. Index Map (Conservation Order 4438 affected area is highlighted with yellow) Conservation Order No. 4438 Effective March 26, 2009 Page 3 of 8 • Rule 1 Field and Pool Name (Restated from CO 443A) The field is the Colville River Field. The pool is the Alpine Oil Pool (AOP). Rule 2 Pool Definition (Revised this Order) The AOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. Correlation Depth Resin Porosdy SP <MD AT9D RFIOB 150 MV 0 .200 OHt,MI 200. .65 GJC3 2. GR NDSS> NPOR AR Z50 ~S TVD DTCP(DT) Sand - Sik - Sha 50 USlF <MD Expanded Alpine Oil Pool Figure 2. Alpine No. 1, Type Log for the Expanded Alpine Oil Pool Conservation Order No. 443B Effective March 26, 2009 Page 4 of 8 • • Rule 3 Well Spacing (Revised this Order) Development wells may not be completed closer than 500 feet to an external property line where ownership or land ownership changes. Rule 4 Drilling and Completion Practices (Restated from CO 443A) a. After drilling no more than 50 feet below a casing shoe set in the AOP, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. b. Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. c. Permit(s) to Drill deviated wells within the AOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). d. A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5 Automatic Shut-in Equipment (Restated from CO 443A) a. All production and gas injection wells must be equipped with afail-safe automatic surface safety valve ("SSV") and a surface controlled subsurface safety valve ("SSSV"). b. Water injection wells must be equipped with either a double check valve arrangement or a single check valve and SSV. c. Safety Valve Systems ("SVS") must be tested on a six-month frequency. Sufficient notice must be given so that a representative of the Commission can witness the tests. d. Subsurface safety valves may only be removed after demonstrating to the Commission that the well is not capable of unassisted flow of hydrocarbons. Sufficient notice must be given so that a representative of the Commission can witness the tests. Rule 6 Reservoir Pressure Monitoring (Restated from CO 443A) a. Prior to regular injection, an initial pressure survey shall be taken in each injection well. b. A minimum of six bottom-hole pressure surveys shall be measured annually. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement. c. The reservoir pressure datum shall be 7,000 feet TVD subsea. d. Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. e. Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the Commission upon request. f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule. Conservation Order No. 443B Effective March 26, 2009 Page 5 of 8 • • Rule 7 Gas-Oil Ratio Exemption (Restated from CO 443A) Wells producing from the AOP are exempt from the gas-oil-ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply. Rule 8 Reservoir Surveillance Report (Restated from CO 443A) A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys. e. Future development plans Rule 9 Well Testing (Restated from CO 443A) a. All wells must be tested at least twice per month. b. The operator shall optimize stabilization and test duration of each test to obtain a representative test. c. The operator shall record well and field-operating conditions appropriate for maintaining an accurate field production history. d. The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards. e. The operator shall maintain records to allow verification of approved production allocation methodologies. Rule 10 Sustained Casing Pressure (Restated from CO 443A) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 psig. d. The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10- 403) aproposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph 3 of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's Conservation Order No. 443B Effective March 26, 2009 Page 6 of 8 • • surface casing. for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph 4 or 5 of these rules, before ashut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3, but not paragraph 5, of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. g. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. Rule 11 Administrative Action (Restated from CO 443A) Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. ENTERED at Anchorage, Alaska and dated March 26, 2009. k~~:---R...~ Daniel T. Sufi~t, Jr., Chair Alaska Oil anr~'G~s (Conservation Commission Gas Cathy P. oerster, Commissioner Alaska it and Gas Conservation Commission Conservation Order No. 443B Effective March 26, 2009 Page 7 of 8 • • 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 unti15:00 p.m. on the next day that does not fall on a weekend or state holiday. Conservation Order No. 443B Effective March 26, 2009 Page 8 of 8 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 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 ~~~~~~` /,~~~ -?may Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, March 26, 2009 3:14 PM Subject: Various Conservation Orders and Area Injection Orders Attachments: aio18c.pdf; aio22d-2.pdf; co456a-4.pdf; co435a-4.pdf; co430a-5.pdf; co406b-5.pdf; co432d-4.pdf; co597-4.pdf; co596-4.pdf; co443b.pdf BCC:'Anna Raff ; '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'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel ;Deborah 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'; 'Gregg Nady'; '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'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant ; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Jacobs'; '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'; 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; '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'; Thompson, Nan G (DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings;'Willem Vollenbrock';'William Van Dyke'; Woolf, Wendy C (DNR); 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, Bren (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: aio 18c.pdf;aio22d-2.pdf;co456a-4.pdf;co435a-4.pdf;co430a-S.pdf;co406b-S.pdf;co432d-4.pdf;co597- 4.pdf;co596-4.pdf;co443b.pdf; Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793-1221 (phone) (907)276-7542 (fax) 3/26/2009 • 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 Adoo Daniel T. Se. r o , r., Commissioner, Chair . •• it . • ss Conservation Commission Ii r man, Coer a Oil , , • a Conserva ion Commission 1 icitil ' • t � �� ..� iv f " l r ig . ,�. Cat y P. oerst r, Commissioner 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(6), "[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. i t • • 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)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Rohrer; 'Bill Penrose'; 'Bill Walker'; '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'; 'trmjrl'; '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 Sa ww.thhcv Fishee Aia4kActiOaiowtcli a b Co -nia-e-rvatw tv Co- -sio-w (907)793 -1223 (907)276 -7542 (favw) 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.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Tools Oil h 7 E P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Fairbanks, AK 99711 Anchorage, AK 99503 Anchorage, AK 99515 -4295 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 Refuge Manager Penny Vadla Cliff Burglin 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 rO \ \ \ Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valves stems' (2) Comment UnitlField Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reats from Order Y systems" ( ) fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered b 25.265(d)(2)(H); arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25265 h q / by arran Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection . g () 9 1 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 "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.2659(b); 25.265(d)(1); (ii) check valve and a SSV. A subsurface controlled injection valve or Check valve requirements for injectors are not covered by Oooguruk Oooguruk arrangement or () a single Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265 h 5 g g readopted regulation valve satisfies single check valve requirement; test every 6 months 25.265(h)(5) )( ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; (except disposal) sa injection wells exce t i ) re uire "Injection (excluding disposal injectors) must be equipped with(i) a double check valve / q 25.265(a); 25.265(b); 25.265(d)(1); on we 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 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 25 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 N/ deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Raven 570 5 yes deactivated SVS; sign on wellhead 25.265(m) tag on well when not manned 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 Check valve re for in ectors are not covered b 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 ection valve or 25.265(h)(5) requirements / y arran Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection . readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 9 () th ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) re 25.265(x); 25.265(b); 25 "Injection wells (e dis injectors) must be e 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 . h 5 arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25265 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 Check valve requirements injectors by Colville River Unit Nanuq 562 6 no 0) double check valve, or (ii) single check valve and SSV; injection 25.265(a); 25.265(b); 25.265(d)(2)(H); equirements for injectors arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or are not covered b 25.265(h)(5) SCSSV satisfies the requirements uirements of a si le check valve." readopted regulation valve satisfies single check valve requirement; test every 6 months q ^9 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 fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.26 / q t permafrost; .f(a); 25.265(b); 25.265(d); N/A replaces SSSV n p for all wellsuire SSSV; Milne Point Unit Schrader Bluff 477 5 yes injection well require uire SSSV or injection valve below ermafrost; test 25.265(h)(5) every 6 months 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; Prudhoe Bay Unit Borealis 471 3 yes injection well require SSSV below permafrost; test every 6 months 25. replaces SSSV nipple requirement for all wells Northstar Northstar 458A 4 no fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500- Existing pool rule established a minimum setting depth for the ft minimum setting depth for SSSV 25.265(a); a ) ; 25.265 ( b ) ; 25.265 ( d )( 1 ) "The minimum setting depth fora 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 4578 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 wets (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 Ba Unit Midni ht Sun 452 6 yes replaces SSSV nipple requirement for all wets Y 9 flow to surface); test every 6 months 25.265(h)(5) 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 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI 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; N/A tag on well when not manned; administrative approval CO Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP Milne Point Unit p 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 valve systems" (2) Comment UnitlField POol Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order 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 Tam 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 Check valve requirements for injectors are not covered by Milne Point Unit 423 7 no every 6 months 25.265(a); 25.265(b); 25.265(h)(5) "Injection wells must be equipped with a double check valve arrangement." readopted regulation River 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 4066.001 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 control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A Badami Badami 402B 6 yes 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(a); 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 deactivated SVS was replaced with requirement to maintain a prescribed by Commission 25 tag on well when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must 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 Unit Prudhoe 341E 5 yes deactivated; maintain list of wells w/deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission 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 Unit Niakuk 329A 5 yes 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(j); 25.265(m) replaces SSSV nipple requirement for all wells 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 Unit West Beach 311B 6 yes w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A A &B) Requirement to maintain a wellhead sign and list of wells with fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Lisburne 207A 7 yes 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 AOGCC Policy - SVS Failures; issued by order of the Commission policy dictating SVS performance testing 25.265(h); h ) ; 25.265(n); n ) ; 25.265 ( o ) N/A Commission 3/30/1994 (signed by Commission Chairman Statewide N/A N/A N/A yes 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 • • sift E[F SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION CODIDIISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVALS CONSERVATION ORDER 432D.010 — KUPARUK RIVER UNIT: KUPARUK RIVER OIL POOL CONSERVATION ORDER 406B.010 — KUPARUK RIVER UNIT: WEST SAK OIL POOL CONSERVATION ORDER 430A.009 — KUPARUK RIVER UNIT: TARN OIL POOL CONSERVATION ORDER 435A.008 — KUPARUK RIVER UNIT: TABASCO OIL POOL CONSERVATION ORDER 456A.008 — KUPARUK RIVER UNIT: MELTWATER OIL POOL CONSERVATION ORDER 443B.001 — COLVILLE RIVER UNIT: ALPINE OIL POOL CONSERVATION ORDER 562.003 — COLVILLE RIVER UNIT: NANUQ OIL POOL CONSERVATION ORDER 569.002 — COLVILLE RIVER UNIT: FIORD OIL POOL CONSERVATION ORDER 605.001— COLVILLE RIVER UNIT: QANNIK OIL POOL Mr. James Rodgers GKA Development Manager ConocoPhillips Alaska, Inc. 700 G Street Anchorage, AK 99501 Re: Request for Authorization to use MPM Multiphase Metering Systems for Well Testing and Production Allocation at ConocoPhillips Alaska, Inc. Operated Pools Mr. Rodgers: By letter dated December 14, 2010, ConocoPhillips Alaska, Inc. (CPAI), as the operator of the Kuparuk River Unit (KRU) and Colville River Unit (CRU), submitted an application report for the MPM Multiphase Metering System (MPM) and requested the Alaska Oil and Gas Conservation Commission (Commission) authorize use of the MPM for well testing and production allocation within the KRU and CRU. CPAI's request is GRANTED with the conditions below. The MPM, developed by Multi Phase Meters AS via a multi -year joint industry project involving ConocoPhillips and other major oil and gas companies, has undergone extensive laboratory and field testing. A key component of the MPM is the 3DBroadBand section, which uses a radio frequency (RF) based technique to take measurements of the flow through the sensor on many different planes. The RF readings, combined with readings from a salinity probe and gamma ray absorption measurements, create a three dimensional picture of the flow through the meter and the composition of the flow stream. This information is combined with a mass flow rate obtained from a venturi meter to give accurate flow rates for oil, gas, and water. A key feature of the MPM system is the ability to switch from a multiphase meter to a wet gas meter automatically and very rapidly. This feature is particularly beneficial when measuring production streams experiencing slugging flow. Tests show that the MPM provides acceptable accuracy under these conditions without the need for a slug catcher or partial separation. The MPM has been subjected to extensive product development, laboratory testing, and several field trials, including one conducted at CD -1 in the CRU in March and April 2010. For this test a 3" MPM was installed upstream of the two phase test separator normally used for well testing and allocation. The results between the two systems were compared. The test was a blind test in which those monitoring and operating the MPM were not shown the results coming from the conventional test separator, which provided "out of the box" results for the meter. A total of 80 well tests were conducted on 16 different production wells during the field trial. The range C0432D -010, C0406B -010 • • C0430A -009, C0435A -008 C0456A -008, C0443B -001 CO562 -003, CO569 -002, C0605 -001 June 20, 2011 Page 2 of 3 of flow characteristics for these wells were fluid flow rates from 300 BPD to 5,200 BPD, gas flow rates from 4 MMSCFPD to 8 MMSCFPD, water cut from 19% to 95 %, and GVF from 88 -90 %. The raw data collected from the field trials indicated that, as compared to the two phase test separator, the MPM under -read total liquid by 4.7 %, oil by 3.7 %, water by 5.4 %, and water cut by 0.4% while over reading gas by 7.3 %. However, Multi Phase Meters AS reviewed the raw data and determined that due to the size of meter selected that two wells slugged sufficiently to over -range the differential pressure cell. Multi Phase Meters AS also found the gas density provided for the calculation of gas flow rate was significantly different from what the meter's densitometer was reading. When the over - ranged test results were removed and the gas density used to calculate gas flow rate was corrected, the measured difference of the MPM was significantly reduced as compared to the two phase test separator. After the MPM data was reprocessed, the MPM meter under -read total liquids by 2.6 %, oil by 2.l %, water by 3 %, water cut by 0.2% and gas by 0.4 %. Although the reprocessed results show all components were under -read, the individual test data indicate no definitive bias towards under- or over - reporting. The appearance of under - reporting in this instance could be a function of the duration of the field trial and the wells that were tested. Since the MPM will be used for well testing and allocation purposes a slight bias in one direction or the other would not be significant due to application of an allocation factor to adjust the test results to match the results obtained from the custody transfer meter. The results obtained during the CRU field trials are comparable to results obtained during other laboratory / field trials of the MPM, demonstrating the MPM's reliability and accuracy over a wide range of flow conditions and fluid properties. Tests have covered everything from heavy oil (163 cP at 20° C) to light condensate (120° API gravity) with water cuts and GVFs from 0% to 100 %, pressures from 75 to 3,000 psi, temperatures from 60° F to 130° F, and liquid and gas rates up to 30 MPBD and 230 MMCFPD, respectively. The publically released test data indicate the liquid and gas rates are typically within +/- 3% and +/- 2 %, respectively, of the reference test separator. The fluid and flow properties for the KRU and CRU pools fall well within this performance envelope establishing that an appropriately sized MPM can be utilized for well testing and production allocation purposes at any of these pools. The Commission finds that CPAI's request is based on sound engineering principles and will not promote waste or jeopardize correlative rights. Therefore, the Commission approves CPAI's request for authorization to use the MPM Multiphase Metering System for well testing and production allocation in the above - referenced oil pools subject to the following conditions: 1) This approval is for well testing and production allocation purposes only. The MPM is NOT approved for custody transfer or fiscal allocation purposes. 2) Before a new MPM can be put into service for well testing and production allocation purposes CPAI must provide notification to the Commission of the location of the new system (i.e. at which facility and /or drill site) and the pool(s) for which it will be used. 3) The MPM must be installed, operated, maintained, and calibrated in accordance with the manufacturer's requirements. 4) In addition to the above referenced pools, the MPM is approved for well testing and production allocation from as yet undefined pools that CPAI may operate, provided that: C0432D -010, C0406B -010 • • C0430A -009, C0435A -008 C0456A -008, C0443 B -001 CO562 -003, CO569 -002, C0605 -001 June 20, 2011 Page 3 of 3 a. CPAI obtains all approvals necessary from any other agency that may have statutory or regulatory jurisdiction over well testing and production allocation for the as yet undefined pool; b. CPAI demonstrates that the expected fluid characteristics and flow properties of the as yet undefined pool are within the performance envelope that has been established for the MPM Multiphase Metering System; and c. CPAI references this administrative approval in its application for pool rules for the as yet undefined pool. SKA 04 7 't$ DONE at Anchorage, Alaska and dated J u l . ;, 4, Daniel T. Seamount, Jr. Q .rmr Cathy P. Foers er Chair, Commissioner issio - Comm ssioner 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), "jtJhe 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: Monday, June 20, 2011 4:55 PM To: '( 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 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 Crocket; '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'; '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'; 'Rena Delbridge'; 'Renan Yanish'; ' rob.g.dragnich @exxonmobil.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 Imm'; '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); 'Lars 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 Wolif; '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) (Iou.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) (Iinda.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: co432d -010, co406b -010, co430a -009, co435a -008, co456a -008, co443b -001, co562 -003, co569 -002, co605 -001 (Kuparuk and Colville) Attachments: co605- 001.pdf 1 0 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.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 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 4 ilip � ,' N • • • Roby, David S (DOA) From: Soria, Dora I [ Dora .1.Soria ©conocophillips.com] Sent: Wednesday, December 15, 2010 11:28 AM To: Roby, David S (DOA); Cellos, Harry S; Cologgi, John R; Parviz Mehdizadeh; Davidson, Temple (DNR); Dykstra, Jeffrey R (DNR); Konsor, Alicia G (DNR); Neumann, Michael P (DNR) Cc: Fullmer, Barbara F (LDZX) Subject: RE: Attendance sheet Importance: High All, This is a reminder that certain portions of the report CPAI presented yesterday are confidential as follows: The information in Appendices 3 and 4 of the AOGCC `Application Report" for the MPM Multiphase Metering System provided by ConocoPhillips Alaska, Inc., as Operator ( "ConocoPhillips "), is confidential and proprietary to ConocoPhillips and is not subject to disclosure because it contains information or data that is (1). trade secret information as defined in AS 45.50.940(3) and State v. Arctic Slope Regional Corp., 834 P.2d 134 (Alaska 1991); (2).required to be held confidential under AS 38.05.035(a)(8); (3). exempted from disclosure under 5 U.S.C. 552(b)(4) or (b) (9); and /or (4). required to be held confidential under AS 31.05.035(d). Best regards and Happy Holidays! -dora Dora I. Soria Staff Landman ConocoPhillips Alaska, Inc. Exploration and Land P.O. Box 100360, Anchorage, AK 99510 email - dora.i.soria crconocophiilips.com (907) 265 -6297 (telephone), (907) 263 -4966 (fax) From: Roby, David S (DOA) [mailto:dave.roby @alaska.gov] Sent: Tuesday, December 14, 2010 12:01 PM To: Cellos, Harry S; Soria, Dora I; Cologgi, John R; Parviz Mehdizadeh; Davidson, Temple (DNR); Dykstra, Jeffrey R (DNR); Konsor, Alicia G (DNR); Neumann, Michael P (DNR) Subject: Attendance sheet All, Attached is a copy of the sign in sheet from the meeting this morning. I once again want to apologize for being so late. Harry, 1 do not have Gordon's email, could you please forward this to him? 1 Thanks, • • Dave Roby (907)793 -1232 From: Davidson, Temple (DNR) Sent: Tuesday, December 14, 2010 11:51 AM To: Roby, David S (DOA) Subject: CPAI MPM App Hi Dave, Thought you'd like to have this — sorry I forgot to give it to you. Did you want to distribute or do you want me to? Thanks, Temple 2 _o evAA Fi\A AFp t 60A-tte-v)1/4. tr2-/1 ---gs 5431/1 2, -s7g3z/ PO gice67 cJn oyer rr� y [is 3 75 - g 33 bN 06. erwaevre.% ,4s 677 6 P : ,14 if i� C 2 J -- L7 7C%/ c7 D -vE AOPr 9.7- /2 72-- 4,6 cc �anvti 35502 • • • • • • ConocoPhillips • • • • • CPAI • • AOGCC "Application Report" for • • the MPM Multiphase Metering • System • • • • • • • • • • • • MultiPhaseMeterb • • • • • • • • • • • • • • • Prepared Parviz Mehdizadeh and Gordon Stobie • 12/14/2010 • • Cover Letter • • A G Street Anchorage, horage, AK 99501 ConocoPhillups Phone: 907 - 263 -3701 December 14, 2010 RECEIVED Daniel T Seamount Jr., Commissioner DEC 2 1 2010 Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 Alaska Oil & Gas Cons. Commission Anchorage, AK 99501 Anchorage Re: Application Report for MPM Multiphase Metering System and Request for Approval of Amendments to Conservation Orders Dear Commissioner Seamount: ConocoPhillips Alaska, Inc.( "CPAI ") as Operator on behalf of the working interest owners of the Kuparuk River Unit ( "KRU ") and Colville River Unit ( "CRU ") (listed in Appendix 1 of the Application Report attached as Attachment 1) hereby requests authorization to use a multi -phase measurement device, as described in the Application Report, for the purpose of well testing and production allocation within the KRU and CRU operations conducted pursuant to 20 AAC 25.228, 20 AAC 25.230, and Alaska Statute Sec 31.05.030(d)(6). The Application Report describes the design, the expected performance and the anticipated applications of the specific multiphase flow meter and compiles the data and literature that were used to qualify the design and establish performance levels for MPM Multi -phase Flow Meter as a self contained unit. This document was prepared following the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued November 30, 2004 by the AOGCC. Upon approval from AOGCC, CPAI would request an amendment to each of the AOGCC Conservation Orders (CO) governing each pool listed in Appendix 1 in order to allow for the use of multi -phase meter technology as described in the Application Report. At this time, there are no specific sites planned for deployment of this technology but having the approval to include such technology will allow it to be included in conceptual planning for project development. The MPM multiphase metering system has been developed by Multi Phase Meters AS ( "MPM ") in Norway under a Joint Industry Project supported and directed by ConocoPhillips Company, ENI, Hydro, Shell, Statoil and Total. A comprehensive test and qualification program was established by the participating members to be able to qualify the MPM Meter for use in field applications. These qualification programs are described in the Application Report. At this time, it is our understanding that 83 MPM meters have been sold for various applications worldwide - of these, 31 units have been commissioned, and the first commenced operating in October 2007 as shown in Table 1 in the Application Report. The main physical components of the MPM Meter are shown in Figure 1 of the Application Report. The special features of MPM are, however, software based. The MPM Meter uses several sensors for different measurements. The data from these sensors are combined in a multi -modal "tomographic" measurement system as described in Section 4 of the Application Report. After a comprehensive review of the performance records of MPM meter from flow loops and field trials, CPAI selected the MPM multiphase metering system for field tests at CRU. The results from these field tests are reported in Section 5 of the Application Report. The CRU tests have demonstrated that the MPM meter has suitable measurement capabilities for well testing. The MPM meter has also been tested in a number of field locations and flow loops. These field tests have been conducted under the MPM Joint Industry Project. Table 8 of the Application Report summarizes the performance uncertainty for flow rates and compositions obtained in t•bove mentioned tests. Taking into acct the uncertainty in the reference devices and data used in the field tests, the MPM has been able to measure the oil /condensate rates with an uncertainty of ± 1 -7 % and gas rates to an uncertainty level of ± 1 -10 %. This is a good record for the overall uncertainty in the many fluids under flow conditions that cover a wide range of fluid properties, water cuts and gas volume fractions. Appendix 1 to the Application Report shows the wells and production horizons for which CPAI is the Operator that may use the proposed multiphase metering unit. This Appendix also shows the working interest owners for those wells and horizons. All parties with working interest, and royalty ownership, as well as the Alaska Department of Revenue will be notified about the use of the MPM meters when the meters are implemented and the application of the metering system affects such interests. The allocation methodology currently practiced at the KRU and CRU will continue and would not be affected by the multiphase metering system. Approval of this request will advance the use of multi -phase technology for North Slope production measurements by allowing CPAI to gain operational experience with the MPM meter and demonstrate that this technology can provide allocation well tests comparable to a conventional separator. Should you have any questions regarding this request, please don't hesitate to contact me at 263 -3701. We would be pleased to provide additional information on this subject at your convenience. '• erely, es Rodgers GKA Development Manager cc: cover letter only: Kevin Brown, BP Exploration (Alaska) Inc. Glenn Fredrick, Chevron U.S.A. Inc. & Union Oil Company of California Mark Agnew, ExxonMobil Alaska Production Inc. Steve Dodds, Anadarko Petroleum Corporation Bobby Donahue, Petro -Hunt, L.L.C. t 0 d • • • • • • • • • • • • • • CPAI • • AOGCC "Application Report" for • the MPM Multiphase Metering • • System • • • • • • • • • • • • • • • • • • • • • • • • Prepared Parviz Mehdizadeh and Gordon Stobie • 11/11/2010 • • • • 12 02- 201UAOUCC MPM for Approval • • Table of Contents • 1. Introduction 2 • 2- MPM Meter Development History 2 • 3. Proposed Applications 2 Table 1 - Current MPM Installations 3 • Table 2- Range of Well Head Conditions and Fluid Properties at the CPAI Proposed Sites • for MPM Installations 4 • 4. System Components and Measurement Strategy for MPM 4 • Figure 1- The main components of the MPM meter 5 Figure 2 -The MPM Meter performs RF measurements in many different planes. 6 • Figure 3 - Schematic of the MPM Well Head configuration 6 • Table 3 — Summary of MPM Accuracy (Uncertainty) Specifications at 95% confidence level • 7 5. Performance of MPM at Alpine 7 • Figure 5 — MPM Meter installed at Alpine 8 • Table 4 - Alpine Wells at CD -1 Tested and Average Test Duration(Hours) 9 • Table 5 - Summary of Alpine Tests 10 Table 6 - Summary of Alpine Test Results - Accumulated Delta Relative to Test Separator • 10 • Figure 6 — Liquid flow comparison MPM Meter to Test Separator The arrows show 2 tests • where the flow rates were high enough for the size meter used in the Alpine trials to cause • saturation of DP transducer. 11 Figure 7 — Water Cut comparison MPM Meter to Test Separator The dotted lines show the • ± 5% variation band 11 • Figure 8 — Oil flow comparison MPM Meter to Test Separator the dotted lines show the • ±10% variation band. 12 Figure 9 — Mass Gas flow comparison MPM Meter to Test Separator. Dotted lines show • the ±10% variation band. 12 • The gas comparison is based on mass flow rates since the Coriolis meter is a good mass • meter and the mass rate comparison eliminates any uncertainty introduced due to PVT • conversion and the additional uncertainties which could be introduced in the gas Coriolis meter converting to volumetric flows. 12 • Table 7- Raw and Post Process MPM Gas Data 13 • 6 — Further Field and Flow Loop Testing 14 • Table 8 - Flow Conditions and Fluid Properties In MPM Tests 15 Table 9- Summary of Field and Flow Loop Test Results 15 • 7. Factory Acceptance Tests (FAT) 16 • 8. Field Maintenance and Periodic Calibration 16 • 9. List of References 16 10. List of Appendices - Supportive Documents 17 • • 1 • • 1 1 1 - 17 • 1 1 • • •2- 2010AOCCC MPM for Approval.doc • • • • AOGCC "Application Report" for MPM • • Multiphase Measurement System • • 1. Introduction • This document describes the design and performance of the MPM multiphase metering • system — hereafter referred to as MPM - designed for well testing in operating areas shown in • Appendix 1. This report compiles the test data and literature that was used to qualify the • design and establish performance levels for the MPM. This document is to be submitted to Alaska Oil and Gas Conservation Commission ( AOGCC) as an "Application Report" to • obtain their approval for using the MPM as an alternative to conventional gravity based test • separators for well testing. The "Guidelines for Qualification of Multiphase Metering Systems • for Well Testing" issued by AOGCC, requires operators to submit an "Application Report" • before new metering systems are used for production well testing and allocations. This CPAI "Application Report" provides the information that is requested in the Section 3 of the • AOGCC document. • • 2- MPM Meter Development History • The MPM multiphase metering system has been developed by Multi Phase Meters AS • (MPM) in Norway under a Joint Industry Project supported and directed by ConocoPhillips, • ENI, Hydro, Shell, Statoil and Total. A comprehensive test and qualification program was • established by the participating members to be able to qualify the MPM Meter for use in field applications. • The first part of this qualification program consisted of testing the meter in the MPM Flow • Laboratory. Following successful completion of the vendor flow loop tests, the MPM meter • was taken to K -Lab in Norway for the first performance tests in October 2006. After successfull flow test at K -Lab the meter was made available commercially. Many of the JIP • Partners bought meters for further field testing. ConocoPhillips purchased an MPM meter and • conducted field performance trials of the meter at their North Sea Ekofisk facility. Other • specific application field trials were also conducted. The results from all the field trials are • discussed in Section 6 of this report. At this time 83 MPM meters have been sold for various applications - of these 31 units have been commissioned, and the first commenced operating • in October 2007 as shown in Table 1. • After a comprehensive review of the performance records of MPM meter from flow loops and • field trials, CPAI selected the MPM multiphase metering system for field tests at Alpine. The • results from these field tests are reported in Section 5 of this application. The Alpine tests • have demonstrated that the MPM meter has suitable measurement capabilities for well testing. • • 3. Proposed Applications • The proposed MPM multiphase metering system is designed to be used either as permanent • wellhead installation or mobile systems deployed in a field. Information and data presented in • 2- 17 • • • • • 12- 02- 2010A0GC(' 19P11 for Approval. 0 0 Sections 5 and 6 of this report indicates that the MPM meter has been able to measure the oil • rates with an uncertainty of ± 1 to ±7 % and gas rates to uncertainty level of ± 1 to ±10 % • when compared to a test separator system. This level of performance has been demonstrated • under flow conditions that cover a wide range of fluid properties, water cuts, and gas void fractions. Appendix 1 shows the wells and production horizons for which CPAI is the • Operator or has working interests in that may use the proposed multiphase metering unit. This 4) Appendix also shows the working interest owners. All parties with working interest, royalty • ownership, as well as the Alaska Department of Revenue will be notified about the use of the • MPM meters when the application of the metering system affects such interests. The allocation methodology currently practiced at CPAI operating fields will not be affected by • the application of the MPM metering technology. The well head conditions and range of fluid • properties at the CPAI Proposed Sites for MPM Installations are shown in Table 2. • Table 1 - Current MPM Installations • • Project Country Operator Units Size MP WG Installed Morvin (subsea) Norway Statoil 4 3" v 8/1/2010 • Champion West Brunei BSP 1 3" v 6/2/2010 • Ebla Syria PetroCanada 1 5" v v 5/30/2010 • Baraka Tunisia ENI 1 3" v 5/15/2010 • Welltesting Oman PDO 1 3" v v 11/10/2009 • Oseberg Low Pressure Norway Statoil 4 3" v v 3/1/2010 • Oseberg B46 Norway Statoil 1 5" v 9/15/2009 • Bardolino -Howe UK Shell UK 1 5 v 8/15/2009 Penguin UK Shell U.K. 1 10" v 8/15/2009 • Nini Ost Denmark Dong 1 5" v 2/20/2010 • Oseberg B30 Norway StatoilHydro 1 5" v 12/1/2008 0 Oman Well Testing Oman MB Petroleum 1 3" v 8/1/2008 • Blacktip Australia ENI 2 5" v 9/15/2009 • Maamoura Tunisia ENI 3 2 " -3" v 12/18/2009 • Separation Module Norway StatoilHydro 1 2" v 10/1/2008 • Compression project Norway StatoilHydro 1 10" v 1/1/2008 • Oseberg B28 Norway StatoilHydro 1 5" v 3/1/2008 0 Vega Norway StatoilHydro 1 5" v 10/1/2007 • Ekofisk 2/4 M Norway Conoco Phillips 1 5" v v 10/1/2007 • Separation module Norway StatoilHydro 1 3" v v 10/1/2007 • Separation module Norway StatoilHydro 1 3" v v 10/1/2007 • Gullfaks A Norway StatoilHydro 1 3" v 10/1/2006 • • • • 3 -17 • • • • • • •t2- 201OAOGCC NIPM for Approval.dor • • • • Table 2- Range of Well Head Conditions and Fluid Properties at the CPAI Proposed Sites for • MPM Installations • Well Testing Parameters • ( Average Values) Operating Fields • Well Mead Conditions Kuparuk West yak Tarn Alpine GMT1 • Reservoir Gas Rate - mmscfd 0.32 0.06 10.7 1 10.7 Gas Lift - mmscfd 1 1 0 1.8 0 • Oil Rate - BPD 800 300 6000 1500 6000 IP Produced Water Rate - BPD 2500 300 5000 2500 5000 • Total Liquid Rate- BPD 3300 600 6000 3000 6000 • Water Cut 76% 50% 83% 83% 83% • Formation GOR - scf /stdBbl 400 207 1800 670 1800 • GVF (estimated at the meter) 0.95 0.97 0.85 0.89 0.85 Meter Pressure (WH Pressure )- psia 135 150 450 250 450 • Meter Temperature (WH Temperature) - F 140 120 100 130 100 • Fluid Properties • Oil Density - lb /ft3 55 57 48 49 48 • Water Density - lb /ft3 61 61 62 62 62 • Gas Density - lb /ft3 0.44 0.42 1.88 0.99 1.88 • Mixture Density - lb /ft3 3.36 1.89 8.88 7.34 8.88 • API Gravity 22 19 38 39 38 • Oil Viscosity - cp 14 26 1.14 0.51 1.14 Water Viscosity - cp 0.46 0.49 0.71 1.56 0.71 • Gas Viscosity - cp 0.012 0.012 0.012 0.012 0.012 • Oil /water viscosity 1.05 157 1.16 4.63 1.16 • • 4. System Components and Measurement Strategy for MPM IP The main physical components of the MPM Meter are shown in Figure 1. The special features • of MPM are, however, software based. The MPM Meter uses several sensors for different • measurements. The data from these sensors are combined in a multi -modal "tomographic" • measurement system - Reference 1. The major measurement functions in the meter are • performed as follows: • • 3DBroadBand tomography is used to measure dielectric constant in 3D, the • distribution of annular gas concentration, water conductivity, salinity and density. • • The Venturi is used for flow rate measurements (via differential pressure) and flow conditioning. • • Gamma ray absorption is used for gas /liquid composition and bulk density. • • The temperature and pressure devices provide in situ P and T data for PVT • calculations. • • 4 -17 • • • • • 12- 02- 2010AOGCC MPM for Approval. • • The flow first passes through a Venturi, which is used to measure the total mass flow rate. • The special Venturi model used also creates radial symmetrical flow conditions in the 3D • BroadbandTM section downstream of the Venturi. The 3D BroadbandTM technology is used to • establish a three dimensional picture of flow and composition inside the pipe as shown in Figure 2. The basis for the technology is often referred to as `process tomography'- which has • many parallels to tomography used in medical applications. The 3D BroadbandTM system is a • high -speed radio frequency(RF) based technique for measuring the water cut, fluid • composition, and the liquid/gas distribution within the pipe cross section. • The MPM Meter performs RF measurements in many different planes as shown in Figure 2 at • high speed. At each plane, measurements are conducted at many frequencies over a broad • frequency range, and combined with gamma ray absorption measurements to establish • accurate determination of the cross sectional composition and distribution of oil, water and gas. By combining this information with the measurements from the densitometer and • Venturi, accurate flow rates of oil, water and gas can be calculated in dual mode - either liquid • dominated (MP mode) or gas dominated (Wet Gas mode) flow regimes. With its dual mode - • liquid or wet gas - functionality and the capability to measure water salinity, the MPM Meter is intended to bridge many of the existing measurement gaps in conventional multiphase and • wet gas meters. • • • .�. • • Outlet connection — • . — Electronics Enclosure • *41 w • 1 Gamma Detector — • • — Single Energy Gamma • *"*. • Sensor Body Electronics/ • Transmitters _ Flow computer • (P, dP) 3D Broadband 'm' • ,`,,: section • Salinity Probe fi `" Termination Box • Venturi ..; • Inlet connection • • • Figure 1- The main components of the MPM meter • • 5 -17 • • • • • • •2- 2010AOGCC MPM for Approval.doc • • • _ �.. . _ o I • • . mom do .� • Itirotill*, , . - . • • • • .. il', • • • • _. ... • • Figure 2 -The MPM Meter performs RF measurements in many different planes. • A summary of the MPM measurement uncertainty specification is shown in Table 3. The full • uncertainty specification is defined in Reference 2. The measurement specifications include • sensitivity which is defined as the smallest change which can be reliably detected and trended. • As noted previously, 31 MPM units have been installed in various fields shown in Table 1 for • well testing and field allocation. Some have been operating since October 2007. The MPM • meter is generally installed downstream of a blind tee in the flow line or as a part of wellhead spool. The proposed well head field configuration is shown schematically in Figure 3. • Installation procedures are described in Appendix 2. .01,-, - .. • -- +{� • 11, • WM ■! ." • . TiT 0 ) esiaen = 79.4,' A9410Y- • '� 1.01111=111==Z I ' S.0 _T ~ L 171 ._::,...1 .7 1 . ,7 4 ,.1...1. = Nz_ Ill • -. .`� =cm mom - :sea= � : mica uvau. a • Figure 3 - Schematic of the MPM Well Head configuration • 6 -17 • • • • • 12- 02- 2010AOGCC MPM for Approval • • Table 3 — Summary of MPM Accuracy (Uncertainty) Specifications at 95% confidence level • Topside & Subsea Meter • Uncertainty is Sensitivity • MultiPhase Mode GVF range - % GVF WLR 0 - 80 80 - 95 0 - 95% • Gas Flow Rate 0 - 100% 5 % 5 % _ ± 0,5 % • Liquid Flow Rate 0 - 100% 2.5 % 5 % ± 0,3 % WLR <5% & >85% 1 % 1 % ±0,1 % • 5 -85% 2% 2% ±0,2°.x° • WetGas Mode - 3 Phases (2) GVF range - % GVF WLR 90 - 95 95 - 98,5 90 - 98,5% • Gas Flow Rate 0 - 100% 3 % 3 % ± 0,5 % • Liquid Flow Rate 0 - 100% 4 % 10 % ± 0,3 % Hydrocarbon mass flow 0 - 100% 3 % 3 % ± 0,3 % • Water Fraction labs) 0 - 100% 0.1 % 0.1 % ± 0,01 % WetGas Mode - 2 Phases ( GVF range -'✓. GVF • WLR 90 -95 95 - 99 -100 90 -100% • Gas Flow Rate 0 - 100% 3 % 3 % 3 % ± 0,3 % Liquid Flow Rate 0 - 100% 3 % 5 % 15 % ± 0,3 % • Hydrocarbon mass flow 0 - 100% 2.5 2.5 % 2.5 % ± 0,2 Water Fraction (abs) < 15% 0.04 % 0.04 % 0.02 % ± 0,003 % > 15% 0.08 % 0.08 % 0.04 % ± 0.005 % • • Salinity Measurement Uncertainty • < 50 mSlcm > 50 mS/cm • Multi Phase (Salinity Probe) ±2 mS/cm (4) ±4 %rel (4) • Wet Gas (S -curve) ± 50 mS/cm (6) ± 50 mSlcm (6) • • 5. Performance of MPM at Alpine • The testing was performed at Alpine Field. A 3 "NB, Beta 0.55 MPM meter was installed in • series with a compact two phase separator as shown schematically in Figure 4 • • Alaskan Multiphase Meter Test • Test Schematic • • Test Separator • Flow from wells 1 16ft by 5ft Dia • • • • MPM • • • • • Figure 4- Schematic of MPM Installations at Alpine 7 -17 • • • • • • •2- 2010AOGCC MPM for Approval.doc • • • ,.. • 1 pp, ,, = -- 1 V 1 i -fi 1 iiii ) io • - I ' 1 N1PM • 1.�. , Nieto • Dow nwa ]ow To ` — • I parato t pm aril Ftow • To MPM • t • • Figure 5 — MPM Meter installed at Alpine • Figure 5 shows a photograph of the MPM installed at the well pad. The well pad consisted of • producers and injectors. The injectors were on a miscible water - alternating -gas (MWAG) • cycle. Many wells utilize lift gas (so produced gas composition can vary from well to well). • The Alpine well pad ( CD -1 ) selected for testing consisted of 24 producers. The use of the 3" MPM meter available for the tests restricted some of the larger producers on the well pad • from being tested. As a result only 16 wells were tested. • • The trials were conducted during March -April 2010. The liquid flow rates, gas flow rates, • GVF, and WC were in the following ranges: • • Fluid Flow Rates 300 -5200 BPD • • Gas Flow Rates 4 -8 MMSCFD • • Water Cut Range 19% -95% ( although 99% was observed) • GVF Range 88 -90% (although 100% was observed) • • Flow Line Pressure 145 - 200 psig • • Flow Line Temperature 68 -86 °F • • API Oil Gravity 40 • • Table 4 shows the wells tested, number of tests and average test durations. The test results are • summarized in Table 5. The liquid and oil volumes are reported in BBL, gas volume is • reported in Mscf (although later comparisons are in gas mass flow), deviations are reported in percentage. Well tests varied in duration from 3 to 25 hours — based on operational experience • with the wells. There were some relatively stable, some slugging and some unstable wells. • The total hours of well testing was in excess of 800 hours. The summation of test results • shown in Table 5 illustrates similar performance to currently used well testing methodology. • • 8 -17 • • • • • 12- 02- 2010AOGCC MPM for Approval • • Table 4 - Alpine Wells at CD -1 Tested and Average Test Duration(Hours) • • Well Number of Test III Designation Tests Duration 4 6 9 • 8 5 5 • 12 6 6 • 18 4 7 24 2 6 • 25 5 6 • 27 12 12 28 6 6 • 32 6 7 • 34 4 6 35 5 8 0 38 4 10 • 40 5 8 • 41 5 7 43 5 5 • 44 7 14 • • The 2 -phase gravity test sseparator used for comparison with the MPM meter is a 16ft T -T by • 5ft OD, 42 BBL capacity vessel. Gas was metered by a Micro Motion CMF300 Coriolis meter • - capable of flow up to 9.4MMscfd with a DP <10psi. Vendor accuracy is quoted as ±0.35 %. • Considering the gas leg of the separator may carry some small amount of liquid (less than WG Type 1), the gas measurement is assumed to have an uncertainty of ± 4 %. Liquid was • metered by a Micro Motion CMF200 Coriolis meter. The meter had a 20:1 turndown — with a • range of 660 to 13,200BBL /d with a DP < 0.2 psi. Vendor quoted accuracy for liquid • measurements is ±0.1 % of rate. This accuracy level does not account for any gas carry under during slugging flow. An analysis of the Coriolis meter drive gains indicated that the meter • was working well. Only six short (several minutes) durations when the meter drive gains • peaked above 4V (of 14V) were noted. Based on these observations the uncertainty in liquid • measurement is assumed to be ±2.5 %. Water cut was monitored using a Phase Dynamics • Inc.(PDI) online water cut monitor, backed up by Net oil Computation(NOC) density based calculations. It has been observed that the WC monitor has problems with WC's >75 %, and in • those cases the NOC density calculations have been used. The MPM Meter was installed • downstream of a 3" blind tee in the test separator module. The well fluids moved upward • through the MPM and downward to the Test Separator. • Figures 6 to 9 show graphs of the well test results for liquid rate, water cut, oil rate, and gas • rate. In each graph the data from the MPM is plotted against the data from test separator. • Generally the MPM meter and the test separator tracked each other well. The average of the differences from all 80 well tests are shown in Table 5. The gas data has a positive bias. MPM • were encouraged to review the data with that in mind. MPM did review the data and found • that: • • two wells slugged so badly that the DP cells saturated at 5000mbar (72.5 psi DP) and • these results were eliminated from the data set. • 9 -17 • • • • • • •2- 2010AOGCC MPM for Approval.doc • • • • The PVT gas density calculated based on the composition provided by CPAI and the • in -situ density seen from the gamma densitometer varied by about 0.5Kg/M3 relative • to a base density of about 12Kg /m3. Using the above corrections, i.e. eliminating the saturated DP cell flow data and reprocessing • the data with in -situ gas density, the differences were reduced as shown in Table 6. • • Table 5 - Summary of Alpine Tests • Alpine Separator MPM Deviations (% Well Liq Oil Water Gas WC Liq Oil Water Gas WC Liq 011 Water Gas WC • 4 4784.0 345.4 4438.6 5795.0 92.8 4219.8 340.2 3879.6 6237.9 91.9 -11.8 -1.5 -12.6 7.6 -0.8 • 8 434.9 242.6 192.3 4118.6 44.2 371.6 158.2 213.4 4473.1 57.4 -14.6 -34.8 10.9 8.6 132 • 12 1284.8 881.3 403.5 3410.1 31.4 1286.7 921.8 364.9 3856.1 28.4 0.2 4.6 -9.6 13.1 -3.1 • 18 1880.1 803.9 1076.2 4335.3 57.2 1753.4 818.1 935.3 4772.2 53.3 -6.7 1.8 -13.1 10.1 -3.9 24 2184.0 702.1 1482.0 6492.6 67.9 2186.3 620.5 1565.8 6983.7 71.6 0.1 -11.6 5.7 7.6 3.8 • 25 2375.4 1089.8 1285.6 7535.1 54.1 2486.7 1126.7 1359.9 7781.8 54.7 4.7 3.4 5.8 3.3 0.6 • 27 2142.4 661.4 1481.0 7210.3 69.1 2172.7 812.5 1360.2 7546.1 62.6 1.4 22.8 -8.2 4.7 -6.5 28 572.2 121.0 451.2 2844.4 78.9 614.9 157.5 457.4 3069.5 74.4 7.5 30.2 1.4 7.9 -4.5 32 2347.5 775.7 1571.8 5662.8 67.0 2277.9 671.7 1606.2 6303.8 70.5 -3.0 -13.4 2.2 11.3 3.6 • 34 343.7 276.8 66.9 2865.6 19.5 257.2 183.5 73.7 3308.7 28.7 -25.1 -33.7 10.2 15.5 9.2 • 35 3486.8 1251.7 2235.2 6773.4 64.1 3223.1 1045.6 2177.4 7423.6 67.6 -7.6 -16.5 -2.6 9.6 3.5 • 38 1655.7 664.9 990.8 5296.7 59.8 1674.4 653.3 1021.2 5534.5 61.0 1.1 -1.7 3.1 4.5 1.1 40 1273.9 792.6 481.2 4679.2 37.8 1209.4 815.8 393.5 4920.0 32.5 -5.1 2.9 -18.2 5.1 -5.2 • 41 1809.9 1252.1 557.8 7756.5 30.8 1657.3 1247.0 410.3 7809.0 24.8 -8.4 -0.4 -26.4 0.7 -6.1 • 43 818.4 432.0 386.3 4060.1 47.2 725.4 343.0 382.4 4435.1 52.7 -11.4 -20.6 -1.0 9.2 5.5 • 44 1675.9 1223.0 452.8 4888.8 27.0 1590.7 1178.6 412.1 5340.3 25.9 -5.1 -3.6 -9.0 9.2 -1.1 • E 29069.0 11516.0 17553.0 83724.0 60.4 27707.0 11094.0 16613.0 89795.0 60.0 -4.7 -3.7 -5.4 7.3 -0.4 • • Table 6 - Summary of Alpine Test Results - Accumulated Delta Relative to Test Separator • • Test Location Liq Oil Water Gas WC Alpine Raw data -4.7% -3.7% -5.4% 7.3% -0.4% • Processed data -2.6% -2.1% -3.0% -0.4% -0.2% • • • • • • • • • 10- 17 • • • • 12- 02- 2010AOGCC MPM for Approval. • • 6000 ' r� • - • l' 5000 - F -' I■ • ' � • -Y - Y .- • � s er 3000 r ' w • i a - • 2000 _ . . D P saturated > 5000 mbar • IX ; % =' 4 • S 1000 - • . • 0 1000 2000 3000 4000 5000 6000 • Alpha s.paaratar liquid Aawrat• (stb(di • Figure 6 — Liquid flow comparison MPM Meter to Test Separator The arrows show 2 tests • where the flow rates were high enough for the size meter used in the Alpine trials to cause • saturation of DP transducer. • 1T0 , r sr • y rte` ,..r- rte - - .41% • ft. eis3 - # r .*" 4 • • r - . j • a * , a 40 - = } . • 10 f 1 • r 0 0 10 20 Xi 40 50 490 70 1110 90 tn. • • Alpine separator water cut �'a I • Figure 7 — Water Cut comparison MPM Meter to Test Separator The dotted lines show the ± • 5% variation band • • • 11 -17 • • • • • • •2- 2010AOGCC MPM for Approval.doc • • • 2500 / ` • j _ -f � • Xk'!1 '� J d • € 2000 -,. • ' / • % � ` 1500 ! • i . • : 1000- jJ _ ' • . 1. • E � r • 500- �. r • 0 ` fA„ *• i . i • 0 .::ix 1000 1500 2000 2500 • Alpine separator oil flowrate (stb /d) • Figure 8 — Oil flow comparison MPM Meter to Test Separator the dotted lines show the ±10% • variation band. • 10000 -, 0 � ` • _ �..tr.trle •+ G. • _ r �• 1 r � • • r , ' • I 2ae ..:<- d' • 1 .fi t` • • 0 1 2000 ) reef O 6 7 000 :::i 5004 14000 • ,Alpine separator apes Harnett! (Ib +'tI) • Figure 9 — Mass Gas flow comparison MPM Meter to Test Separator. Dotted lines show the • ±10% variation band. • • The gas comparison is based on mass flow rates since the Coriolis meter is a good mass meter • and the mass rate comparison eliminates any uncertainty introduced due to PVT conversion and the additional uncertainties which could be introduced in the gas Coriolis meter • converting to volumetric flows. • 12 -17 • • • • • 12- 02- 2010AOGCC MPM for Approval, • • As noted previously the gas data in Figure 9 shows a positive bias. The MPM meter used the • gas composition provided by CPAI with their CALSEP PVTSIM® Equation of State • calculation package to determine the gas density using the flowing pressure and temperatures. • The MPM meter is able to provide an in -situ measurement of the gas density under no flow conditions. The results from the in -situ gas density measurements shown in Figure 10 • indicated a discrepancy between the composition based PVT density and the actual measured • density. Figure 10 shows the in -situ measured density is 4.2% lower, which would result in a • lower measured gas flow rate, reducing the discrepancy between the separator and the MPM • meter as shown in Table 7. • 16 • 14 • 12 • 4311411111111101100NIR 10 • -Gas Density PVT 8 (kg/m3) • 6 - Measured Gas Density • 4 (kglm3] • o f • ..4 to .r m ... lD ..1 mm .1 %D iD V 1f5 1.D D l0 .1 O .1 .1 N N M r- V' c ) in V1 tD lm r • .1 N rv1 rr np c O •1 N m Q 1-1 .1 .4 .1 .i Figure 10: Graph showing difference between measure and calculated gas density • Table 7- Raw and Post Process MPM Gas Data • Separaator Raw data Post Process • Well Gas flow Delta Delta Comments • Mscf [%] [ %] • 4 5795 J 7.6 2.3 DP >5000m bar cut off 8 4118.6 8.6 3.2 • 12 3410.1 13.1 7.4 • 18 4335.3 10.1 4.6 • 24 6492.6 7.6 2.2 25 7535.1 3.3 -1.9 • 27 7210.3 4.7 -0.6 • 28 2844.4 7.9 2.5 32 5662.8 11.3 5.8 • 34 2865.6 15.5 9.7 • 35 6773.4 9.6 4.1 DP >5000mbar cut off 38 5296.7 4.5 -0.7 • 40 4679.2 5.1 -0.1 • 41 7756.5 0.7 -4.4 43 4060.1 9.2 3.8 lb 44 4888.8 9.2 3.8 • Total 7.3 1.9 Al data • • • 13 - 17 • • • •2- 2010AOGCC MP\l for Approval.doc • • • 6 — Further Field and Flow Loop Testing • The MPM meter has been tested in a number of field locations and flow loops. The tests listed • below have been conducted under the MPM Joint Industry Project as blind tests or in Operator controlled field tests where MPM have had minimal or no access to the test data. • • • MPM Flow lab tests as part of the MPM JIP, multiphase and wet gas flows with air, water and refined oils at about 10BarG - Reference 1. • • K Lab (1) lab tests were conducted under Statoil sponsorship as part of the MPM JIP high pressure (60- 100Barg) wet gas using field gas, Decane and process water - • Reference 2. • • K Lab (2) lab tests were also conducted under Statoil sponsorship as a combined Statoil subsea compression test with the data released to the In -Situ JIP. Tests are • planned to run for 24 months (18 months already completed) - Reference 3. • • Gullfaks - under Statoil sponsorship as an early multiphase offshore field test. Trial • has now changed to permanent installation and MPM meter used for production well • testing - Reference 4 • SWRI flow loop tests were conducted by Statoil -Shell to assess the MPM for subsea • application at high pressures for wet gas measurements. Tests were lead by Statoil- 411 Shell with JIP financial involvement — high pressure (70- 120Barg) wet gas using field • gas, Decane and process water - Reference 5. • • COP Ekofisk - production well tests in a gas lifted field with various produced water origins. GVF 20- 100 %, WC 20 to 95 %. The field test meter has been converted to • permanent production meter and a 2nd MPM meter has been ordered. This meter is • used for well testing. (API 35 oil, water with large salinity variations) - Reference 6. • • K -Lab 2009, blind test by Statoil for a delivery project to Statoil operated field. Data published in In -Situ Part I Final Report - Reference 7. • • Alpine — Field test under CAPI sponsorship as described in section 5 of this report. • The results are published, Reference 8. • • Heavy Oil Project tests at the Petrobras Atalaia Testing Facility for Petrobras and • StatoilHydro - Reference 9 • CEESI — Lab test under BP /COP sponsorship for wet gas flows. Results are not • currently available. • • Table 7 below summarizes the various flow conditions and fluid properties used in the above • flow loop or field tests. The fluid properties and flow conditions proposed in the CPAI applications, see Table 2, are covered by the test conditions in Table 7. • • Table 8 summarizes the performance uncertainty for flow rates and compositions obtained in . the above mentioned tests. Taking into account the uncertainty in the reference devices and data used in the field tests, the MPM has been able to measure the oil /condensate rates with an • uncertainty of ± 1 -7 % and gas rates to an uncertainty level of ± 1 -10 %. • • This is a good record for the overall uncertainty in the money fluids under flow conditions • that cover a wide range of fluid properties, water cuts and gas volume fractions. • • 14- 17 • • • • • 12- 02- 2010AOGCC MPM for Approvale • 0 Table 8 - Flow Conditions and Fluid Properties In MPM Tests • Test Location . Lig Range .. Gas Range WLR Range GVF Range Pressure Temp - Olt API Gravity Comments • BPD MMSCFD PSI F (Density- Kg /m3) • MPM Flow Lab 0- 30,200 0- 13.6 0- 100% 0 -100% 75 -150 80 37( 840) Stable and Slugging • flows K -Lab 1 300 - 10,600 338 - 150 0-93% 10 -98.5 1800 65- 130 94 -100 Multiphase test • K -Lab 2 30 -1500 20- 230 0-10% 98.5 -100 450 -1800 65 -130 94-100 Multiphase test Gullfaks 970 -13840 20- 220 0-95% 0-95 880 65 -130 38 -52 3 -Phase TS • SWRI 0 -150 8.5- 33.9 0-25% 95 -100 1750 -2940 112 961600;560 Variable water salinity • 0- 100 %R *, 0- 100%R *, 88- Stable and Slugging • Ekofisk 0 -8300 1.7 -13.6 1.5 48% N 97 %N 300 -350 78 -205 35 flow K -Lab 2008 24 Month Wet Gas • NA NA 0 -100 94-100 450 -1800 65 -130 94 -100 2010 Tests • 30 -93 %N, 0- Slugging, Emulsions • Alpine 300 -5000* 2.8 -7.8 100%R 0-100%R* 180 -220 65 -80 40 and variable water salinities • Oil Viscosity- Rates Unavailable for Heavy Oil NA NA 0-90 0-98 105 -180 163cP at 20C Public • CEESI 0 -410 13 -31 0 -100% 99.5 -100% 1000 60-75 67 Wet Gas • CEESI 0 -2100 13 -31 0 -100% 95 -100% 1000 60-75 67 Multiphase • • Table 9- Summary of Field and Flow Loop Test Results • Test Location 1 Liquid 1 Gas 1 WC 1 Oil 1 Water I Reference Used • . . MPM Flow Lab ±1.1% ±1.23% NA 1.2% +0.03% Loop Sep - I K -Lab Blind ±0.1% ±1.4% NA f 0.05% 1.2% Loop Sep -2 Gullfaks Dec 06 ±3.4% ±0.7% NA 1.7% 0.83% Test Sep - 3 Phase -1 • Gullfaks Jan 07 ±1.4% ' - 1.4% NA 0.82% 1.36% Test Sep -3 Phase -F SWRI Wet Gas * * ** ±0.7% 1.2 - 1.63% NA ' 0.96% -2.6% Loop Sep -2 Phase -1 0 SWRI Wet Gas * * ** ±0.7% ±1.2 - 1.35% NA +5.69% ' -2% Loop Sep - 3 Phase -2 • Ekofisk * ** r +1.2% +19.9 * ** +1.5 %abs r +3% r -5.8% Test Sep * ** • K -Lab 2008 - 2010 ±5 -10% ±5 -10% ±5 -10% ±5 -10% ±5 -10% Data not Released • Alpine* -4.7% +7.3% 0.42% +3.7% -5.4% Test Sep - 2 Phase Alpine -Post Proc ** -2.6% -0.4% - 0.22% -2.1% -3.0% Test Sep - 2 Phase -I • Heavy Oil NA NA NA NA NA Test Sep • CEESI - Wet Gas NA NA _ NA NA NA Loop Sep • • NOTES • 2 = The values are reported on accumulative basis • * Out of the box - no processing accumulated discrepancy MPM meter vs. Test Sep. Alpine data comprises >80 well test and 800 hours of flow • ** Post Processed accumulated discrepancy MPM meter vs. Test Sep * ** Test comprised 76 well tests over 360hours of flow. These tests determined that the new Ekofisk 2/4M 0 Test Separator Gas meter was in error. It was a multipath USM of a bounce path design and liquids (in the • gas) contaminated the transducer signals. The MPM gas rates were confirmed as being `nearer to the expected figures' by the Reservoir Engineers from prior GOR knowledge (from 30 years prior production experience of the Ekofisk field). The MPM gas and oil data (converted to GOR) fits the earlier experience. • * * ** 2Phase and 3Phase refers to the MPM Measurement Modes - each has its own advantages. • • 15 - 17 • • • • • •2- 2010AOG MPM for Approval.doc • • • 7. Factory Acceptance Tests (FAT) • Factory acceptance tests will be conducted prior to field installation as described in the • Factory Acceptance Test (FAT) MPM Manual shown in Appendix 3. The FAT procedures • include : • • Hydrostatic pressure testing is performed according to the meter's pressure rating. • • Venturi Calibration • • Liquid and gas flow rate tests to check the performance of the skids. The test • conditions will be guided by both the operating constraints of the test meter and of the • flow facility. • • Communication tests. • 8. Field Maintenance and Periodic Calibration • • The maintenance and periodic calibration procedures for MPM are described in the • Maintenance and Calibration Manual shown in Appendix 4. These procedures include but not • limited to the following items : • • The PVT tables used for gas and liquid density calculations would be updated • periodically • • Periodic in situ calibration of gas density and water salinity if needed • • Correct operation of the primary device - Venturi inspected visually using boroscope on yearly basis - if sand is detected in the well fluids. • • Periodic calibration of DP/P/T transmitter - as needed. • • Densitometer nucleonic source - Leak test - per International/National /State codes by • the RPS, plus Empty Pipe Reference - every 6 months • • 3D Broadband - using in -situ testing via the TCP /IP link to Stavanger and a certified quality index report as needed. • • • 9. List of References • 1. "NSFMW 2007paper - Tomography powered multiphase and wet gas meter providing fiscal • accuracy By Wee, Berentsen, Moestue and Hide" • 2. MPM HighPerformanceMeter- Unparalleled measurement accuracy and sensitivity White • Paper No 1,18 February 2008 . 3. MPM HighPerformanceFlowmetersTM White Paper No 6 1 August 2009,MPM Flow • Laboratory • 4. StatoilHydro- Well Informed 07 • 5. Field Test of MPM Subsea Meter at SwRI with special focus on Wet gas and Salinity Measurements - Preliminary Report Dec 4, 2007. • 6. Successful Implementation and Use of Multiphase Meters, Oystein Fossa and, Gordon Stobie • - ConocoPhillips, Arnstein Wee — Multi Phase Meters - NSFMW , October 2009. 7. In situ verification for multiphase and wetgas metering JIP Final Report — Phase] • 8. MPM User Group Forum — Stavanger June 7 -8th 2010, Alaskan Multiphase Meter Test • Gordon Stobie - ConocoPhillips Company • 16- 17 • • • • • 12- 02- 2010AOGCC MPM for Approv ° ale • • 9. MPM METER EXPERIENCE IN HEAVY OIL,Arnstein Wee (MPM), Hans Berentsen (ex Statoil) and Lars Farestvedt (MPM Inc), InternationalWorkshop on the Challenges in Heavy • Oil and Associated Multiphase Flow Measurement,Brazil, 12 -13 November 2009. 10. Erosion in a Venturi Meter with Laminar and Turbulent Flow and • Low Reynolds Number Discharge Coefficient Measurements, G Stobie, COP R Hart • and S Svedeman, SWRI, K Zanker, Letton -Hall Group, NSFMW, Oslo, 2007 • • 10. List of Appendices - Supportive Documents • • Appendix 1 — Field, Pool, and Wells for proposed applications, list of ownerships, etc • Appendix 2 - Installation and User Manual -MPM Topside Meter Appendix 3 - Factory Acceptance Test (FAT) MPM Manual Appendix 4 - List of relevant papers and publications • • • • • • • • • • • • • • • • • • • • • • • • • • 17 - 17 • • • X '0 C a a. a Q ••••••••••••• ••••••••••••••••••••• Appendix 1 NS Facilities Operated by CPAI Colville River Unit Alaska Property Ownerships Participating AOGCC Pool AOGCC Pool Oil Royalty Gas Royalty Processing Facility Area Code Description Rate Rate ConocoPhillips Anakardo Petro -Hunt Total Colville River Unit Alpine 120100 Alpine 9.8150% 78.00% 22.00% 100.00% Colville River Unit Fiord - Kuparuk 120120 Fiord - Kuparuk 12.5000% 12.5000% 78.00% 22.00% 100.00% Colville River Unit Fiord - Nechelik 120120 Fiord - Nechelik 11.6035% 77.62% 22.00% 0.3800% 100.00% • Colville River Unit Nanuq -Nanuq 120175 Nanuq -Nanuq 9.7726% 9.4685% 78.00% 22.00% 100.00% Colville River Unit Nanuq - Kuparuk 120100 Nanuq - Kuparuk 7.7713% 78.00% 22.00% 100.00% Colville River Unit Qannik 120180 Qannik 8.3285% 3.0808% 78.00% 22.00% 100.00% Kuparuk River Unit Alaska Property Ownerships Participating AOGCC Pool AOGCC Pool Oil Royalty Gas Royalty Processing Facility Area Code Description Rate Rate ConocoPhillips BP Exploration Union ExxonMobil ,Total Kuparuk River Kuparuk River Unit CPF #1 Kuparuk 490100 Unit 11.2513% 12.5010% 55.2753% 39.1920% 4.9506% 0.5821% 100.00% Kuparuk River Unit CPF #1 West Sak 490150 KRU West Sak 12.5000% 52.2247% 37.0247% 4.9506% 5.8000% 100.00% Kuparuk River Kuparuk River Unit CPF #2 Kuparuk 490100 Unit 11.2513% 12.5010% 55.2753% 39.1920% 4.9506% 0.5821% 100.00% Kuparuk River Kuparuk River Unit CPF #2 Meltwater 490140 Unit Meltwater 12.5000% 55.4889% 39.3438% 4.9506% 0.2167% 100.00% Kuparuk River Kuparuk River Unit CPF #2 Tarn 490160 Unit Tarn 12.5000% 55.4023% 39.2823% 4.9506% 0.3648% 100.00% Kuparuk River Kuparuk River Unit CPF #2 Tabasco 490165 Unit Tobasco 12.5000% 55.4023% 39.2823% 4.9506% 0.3648% 100.00% Kuparuk River Kuparuk River Unit CPF #3 Kuparuk 490100 Unit 11.2513% 12.5010% 55.2753% 39.1920% 4.9506% 0.5821 % 100.00% Kuparuk River Unit CPF #3 NEWS NEWS 12.5000% 55.4024% 39.2822% 4.9506% 0.3648% 100.00% • • • • • • • \-r' • t • aas"°+w Har _ 8 • c.mti —� ay Kogru River n i Fh4,„„ j - ,, NW MILNE1 C7 • V ({��, ' P wm lqun \S V 4 F r • • + 1 �•M ( L \ "..----Cs1/4 \ • J II � MIS ITE E A 6 7\ t SIT • ♦ KRU . . c � • PAD J v FP 1. 0 . \ - oN G t E 1 '_ _ � �1� WSAK16 � 3N �WSAK7 WSA.2N 4 ,_ /i i i - ll �� fr� a n A'A ( 5ii'r) 6 k 1 EUGN PROD. TEST �� • 1R or • • WSAK 11 ,•2W 11G °1H v • ..,,...-,,,----..._..=..--___ ' v� - :� a - %KOS KUP KIC i- tY AR IR STRIP - '1.. � 1 1 2X 1A ° r� Bear Tooth Unit CD -5 ALPINE WEST MINE SITE F 4 2V 12Z a•PP- 1C • • ` I; MINE MINE E C '\ CD-4 N UO 2A �WSAK1 A 2 1FI U1E ,1D MP1 1 ........1. .. Z p i CD-0 L OUT 1} Fr PF -2 ' 2M e • • Colville 1 fiver Uni f .1 2 E • 11J • v 1rej 2K' Ktiparuk River Unit C • D -7 - - ARK � • NUIQSUT "; • l� • , • l W9AK25618 r / - • Greater Mooses Tooth Unit . i • i �, _i • .� / • % \ 1 N • /r L / ll U, , % �\ � , WE i S • i� NPR -A - ' • ill i 1:340,000 -.. ' � t • 0 1252.5 5 7.5 10 • / Kuparuk River Unit Miles • • ;- Mask.. ,; Conoc -1I •t .1 CPAI Operated Facilities • L. - : - ,, Map , r • i 10100701A00 10 -7 -10 • • Appendix 2 • • • • • • • • Appendix 2 • • MPM High Performance Flowmeters • • Installation and User Manual • • MPM Topside Meter • • • • • 1 • • • • • i� 4 . • • • • • Project Name Magnolia, Entrada • Project Number 4054 • Customer Name ConocoPhillips, Callon PO Number 4509571200 • Tag Numbers 20 -ZAU -001, 20 -ZAU -002, 20- ZAU -003A, 20- ZAU -003B • Document No /Name TD -010 Installation and User Manual — MPM Topside Meter • (Operating and Maintenance Manual) • Classification PROJECT CONFIDENTIAL • • Rev Date Purpose Written By Accepted By Approved By • 01 14.08.08 Issued for Approval OAI KG AW • — — — — • • This document is a successor of the MPM document: QP -010 • • • • • • • • • mPm • • TABLE OF CONTENTS • • 1 INTRODUCTION 4 • 1.1 PURPOSE 4 • 1.2 IMPORTANT NOTICE 4 1.3 TRAINING 4 • 1.4 UPDATES AND CONTACT DETAILS 1.5 ABBREVIATIONS 5 • 2 MPM METER DESCRIPTION 5 • 2.1 GENERAL 5 • 2.2 HIGH PRESSURE/HIGH TEMPERATURE DESIGN 7 2.3 TOPSIDE METER COMPONENTS 7 • 2.4 MECHANICAL PARTS 8 • 2.5 ELECTRONICS SYSTEM 10 2.6 MPM TERMINAL AND COMMUNICATION SYSTEM 11 • 3 INSTALLATION 13 • 3.1 GENERAL 13 • 3.1.1 Check of meter, flanges and covers 13 • 3.1.2 Mechanical installation 13 3.2 SITE INSTALLATION 14 • 3.2.1 MPM Terminal 14 3.2.2 Empty Pipe Verification test 14 • 3.3 ELECTRONIC TEMPERATURE SURVEILLANCE 14 • 3.4 INSTALLATION COMPLETED 14 4 COMMISSIONING 15 • 4.1 METER START UP 15 • 4.2 METER CALIBRATION 15 4.3 SITE SYSTEM TEST 15 4.3.1 Transmitters 15 • 4.3.2 External communication ports 16 • 4.4 METER CONFIGURATION 16 4.4.1 PVT Data 16 • 4.4.2 Conversion to Standard Conditions 18 4.4.3 Two Phase wet gas Mode 19 • 4.4.4 Input of look -up tables 19 • 4.4.5 Continuous input of density values (Live PVT) 20 5 OPERATION 21 • 5.1 STARTING THE MPM USER INTERFACE 21 • 5.1.1 MPM Terminal 21 • 5.2 REMOTE ACCESS 21 5.2.1 Setting up the remote computer 21 • 5.2.2 Main page 22 • 5.2.3 Menu 23 5.2.4 The Information area 24 • 5.2.5 Graphics area 25 • 5.2.6 Status bar 26 5.3 ALARM STATUS 27 • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 2 of 41 • Project Confidential • • • • • • • • • mpm • t. +uttrci'ka tife+(4r, • 5.4 EVENT LOG 28 • 5.5 TREND /EXPORT DATA 29 • 5.6 METER CONFIGURATION 30 5.6.1 Select active process data set 30 • 5.6.2 Create New Look -Up tables (PVT gas and oil properties) 30 • 5.6.3 Process data configuration 30 5.7 DIALOG TOOLBAR 35 • 5.8 PVT, OIL AND GAS PROPERTIES DIALOGUE 36 • 6 MAINTENANCE 38 • 6.1 OPERATIONS INTEGRITY SERVICES (OIS AGREEMENT) — LINK TO MPM OPERATIONS CENTRE 38 6.2 VERIFICATION / RECALIBRATION OF VENTURI CD 39 • 6.3 PVT MAINTENANCE 39 6.4 COMMUNICATION TESTS 39 • 6.5 MECHANICAL MAINTENANCE 40 • 7 REFERENCE DOCUMENTS 41 • • • • • • • • • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 3 of 41 Project Confidential • • • • • • • • • mpm • • • 1 INTRODUCTION • 1.1 Purpose • The purpose of this Installation and User Manual is to provide information and guidance for users of • the MPM Meter, as to how to install, operate and maintain the Meter. • • 1.2 Important notice • The MPM Topside Meter is a field instrument, designed and built for problem -free operation to fulfil • customers' satisfaction. • However, there are some special precautions that must be taken to avoid problems or degradation of • the instruments capabilities, and to avoid unwanted HSE situations. • Please make sure to avoid the following: • - The Meter contains a RADIOACTIVE GAMMA SOURCE. The source is well shielded, and the • radiation to the environment is within specified and acceptable values. The gamma source is • equipped with a shutter mechanism. It is important though, that NO HUMAN LIMB MUST EVER • BE PUT INSIDE THE PIPE. - NO ELECTRICAL WELDING must be performed on the meter body or parts, nor in the adjacent • pipework or structure. • - All TRANSPORTATION AND HANDLING of the meter must be performed as per the • specific Handling of Radioactive Source and Action Plan Procedure. In particular, the • Meter must not be exposed to shocks and vibrations, outside the specified range. • 1.3 Training • • MPM is offering a set of training courses, which are aimed at personnel and operators at different • levels. Training courses can be provided in the MPM Flow Laboratory in Stavanger, and at site. In • Stavanger, operators are provided the opportunity to run the Meter in the MPM Flow laboratory, at a variety of flow conditions and rates, under supervision and guidance. • • 1.4 Updates and Contact details • This manual is made to the best of our knowledge and we hope it will be a useful tool for the • operators. We would certainly like to improve it based on experiences and knowledge gained as we • go along, and we would appreciate feed -back and comments on how we could achieve this. To do so, or in case that further assistance is required, MPM can be contacted as follows: • • e -mail: support ct mpm- no.com • phone: +47 4000 1150 • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 4 of 41 • Project Confidential • • • • • • • • • • • • • 1.5 Abbreviations • MPM - Multi Phase Meters AS • GUI - Graphical User Interface GVF - Gas Volume Fraction (in -situ) • PVT - Pressure Volume Temperature • FOR - Enhanced Oil Recovery dP - Differential Pressure • WLR - Water Liquid Ratio • • • 2 MPM METER DESCRIPTION • • 2.1 General • The MPM Meter is intended for production monitoring, well testing and allocation metering purposes, and is tailored for use in WetGas and MultiPhase flow applications. • • • • • • • • • 4 • • • • • • • Focus during the development phase was to design a High Performance Meter, characterized by: • • • High operational stability • Unique sensitivity and reproducibility • • Unparalleled accuracy • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 5 of 41 • Project Confidential • • • • . • • • mpm • The MPM Meter is an in -line and full bore meter, based on conventional multiphase metering • equipment in combination with the patented 3D- BroadBandT"" technology. • • The MPM Meter has undergone a very extensive operator -driven qualification program. During the program, the Meter has demonstrated very high performance as to measurement accuracy. The • specifications for measurement uncertainty are derived directly from the field testing. More details of the meter accuracy specifications and how these are derived are provided in White Paper No 1 - Unparalleled measurement accuracy and sensitivity. • The second main part of the qualification program focused on mechanical integrity, and the meters • ability to withstand normal and extreme conditions during its life. More details are provided in the • following section. • The MPM Meter can be configured as a wetgas or a multiphase meter (Dual Mode), depending on • the flowing conditions. Mode selection is automatic, or manual. In multiphase mode, the Meter does extremely fast measurements to capture rapid fluctuations in the flow. In wetgas mode, the Meter • uses its ultra high sensitivity to differentiate tiny fractions of water and liquids from the gas. The Meter • has no flow regime dependency - potential measurement errors due to slugging and /or annular gas concentration are eliminated by the fact that measurements are done extremely fast making • measurements in 3 dimensions inside the pipe. With the dual mode, correct measurement of watercuts across full range of GVF's and water fractions • are obtained, resulting in correctly measured oil flow rates even at high watercuts, and correctly • measured formation water flow rates at high GVF. More details of the Dual Mode features are provided in White Paper No 3 - Dual Mode — Wetgas and Multiphase Meter • The MPM Meter is fully calibrated at the factory, prior to the Factory Acceptance Test (FAT), and has • lean requirements for field configuration. Field configuration consists of entering typical data for the • produced hydrocarbons using the Graphical User Interface. All the data related to the gas and oil phase can be calculated using a standard PVT simulator such as Calsep PVTSim based on the • hydrocarbon composition for the well. The Meter also offers a high tolerance to configuration • parameter shifts. While this is valid for most parameters, the conductivity of the produced water is different. At low WLR a potential erroneously specified value for water conductivity has little impact • on measured flow rates. However, once the WLR increases, and the emulsion turns into water- • continuous (typically for WLR of 40 -50% and upwards), a potential error in the specified value for water conductivity can have detrimental effect of the measured flow rates. This effect is more or less • the same for all brands of meters. Except the fact that the MPM Meter can be outfitted with an Auto configuration functionality. With this functionality, the water conductivity is automatically measured • by the Meter, and there would be no more need to provide manual input values (which would also • eliminate the need for sampling). The measured water salinity and water density will be available as output from the Meter, when the • flow is water - continuous. More details of the Salinity Measurement features are provided in White Paper No 2 - Water salinity • measurement & auto configuration • The MPM Meter is outfitted with comprehensive set of In -situ verification and self- diagnostics • functions. The operation and use of these are explained in detail in later sections of this manual. • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 6 of 41 Project Confidential • • • • • • • • • • MPM • • 2.2 High pressure /High temperature design • A dedicated part of the development program consisted of developing and qualifying a subsea • version of the MPM meter. The subsea meter design specifications included high temperature and high pressure, and a major part of the project consisted of qualifying the resulting design with respect • to mechanical integrity. During this phase of the project, up to nine international Oil Companies • worked in co- operation with MPM. • The resulting HP /HT design is also available for topside meters. It is made to cover the full range of expected requirements for operating pressure and temperature, and to operate without failures during • the full life of the well or field. • ,w ,a The qualification program for the HP /HT deisgn was performed as per • DNV's recommended practice for qualifying new products; the RP A- C9 203. At the end of the program, DNV issued a Statement of DET NORSKE VERITAS ' y' • Compliance, for design conditions as follows: STATEMENT OF COMPLIANCE • P design < ��- ..-� -- 15 kPSI • .,.. ,..,...,�,_:� _,Q.K• - T design < 480 °F (250 °C) • -Water Depth < 2700 m • The design and qualification program was further done in accordance to • • ISO 13628 • API 17D/ API 6A. °" " • • NACE compliance a_ ti • . Hk �r•,.� e744- 4,41.614- 0;;; • • 2.3 Topside Meter Components • The Meter is built with all parts in one unit with little need for final assembly on site. The only part • which needs to be assembled is the gamma source. • The MPM Meter does all measurements and calculations locally in the meter electronics, and transmits the measured data to a SCADA (control system) at the host platform, and /or the MPM • terminal (PC). The main components of the MPM Topside Meter are as follows: • - Mechanical parts, including sensor, antennas and transmitters. • - Electronics system. • - MPM Terminal and Communication system. • • • • • • • TD -010 - Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia. Entrada Page 7 of 41 • Project Confidential • • • • • • • • • • 2.4 Mechanical parts • • • Outlet connection — • • — Electronics Enclosure • '\ Pi • 1 Gamma Detector - 411R7 t - • hi • — Single Energy Gamma • Sensor Body`( • � 1 4, Electronics/ Transmitters Flow computer • P, dP • 3D Broadband (TM) r section • Salinity Probe „ - i • _ .o •r 1 " 3 " . +31.4 • Termination Box Venturi • Inlet connection f • • • • The MPM Topside Meter and its parts in detail are shown in the figure above. The pressure and • temperature transmitter is optional. The temperature transmitter is recommended mounted in the blind- • T up- stream the meter. To the right on the figure above is the electronic canister containing flow computer and other • electronic, hart modems etc. • The flow first passes through a Venturi, with differential pressure sensors at the inlet and optionally at • the outlet section, which are used to measure the total mass flow rate. The Venturi is also used to • ensure radial symmetrical flow conditions in the 3D BroadbandTM section downstream the Venturi, where also the gamma detector system is located. • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 8 of 41 • Project Confidential • • • • • • • • • Mm • • The functionality of the different measurement elements is briefly explained below: • • Component Function (simplified) • Venturi Constriction which generates a differential pressure between two • points for measurements of mass flow rate. It also generates radial symmetric flow regime for better measurement conditions. • Differential Pressure Used to measure pressure drop over Venturi, and from this deriving • Transmitters mass flow rate measurements. The dP transmitters are connected to • the process via remote seals • 3D- Broadband section Main component of the tomography measurement system, used to make 3 dimensional measurements (pictures) inside the pipe. • Measurements are performed in many planes (up to 27), and at • typical 25 frequencies spread over a large frequency band (MHz to GHz). The measured permittivity is particularly useful for water cut • and salinity (wetgas) calculations. • Salinity probe The salinity probe is mounted in the 3D Broadband area, and is used • for measurements of the water conductivity. From the water • conductivity, the water salinity and water density can be calculated. • Pressure Transmitter Inline Pressure Measurements. The transmitter is connected to the • process via remote seal. • Temperature Transmitter Inline Temperature Measurements. (Recommended mounted in the blind -T up- stream meter) • Gamma Detector Used to obtaining mass absorption measurements in the centre of the • pipe. The mass absorption measurements is used (in combination • with 3D Broadband results) to calculate the effective mixture density • in the cross section of the pipe and in situ gas volume fraction measurements • Electronics Electronics system which performs flow and associated calculations • based on input from all sensors and transmitters. Very high quality • system, with MPM primary uncertainty specifications • Graphical User Interface Web based service, which serves as the interface between the users • and the meter. • All transmitters in the MPM topside meter are high performance versions. They are rated after • application requirement and can be delivered as high pressures and high temperatures versions, • typical 1035 Bars and 250 °C. The transmitters are connected to the flow computer via ModBus protocol. The temperature element is connected with the process via a thermo well. The range of the • pressure transmitter will be application specific. • Further descriptions and details about the MPM Topside meter are found in the Reference • Documentation (See Table of Contents). • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 9 of 41 Project Confidential • • • • • • • mpm • • • 2.5 Electronics System • The electronics system used in the MPM Meter has been especially designed and qualified for problem -free operation in both topside and �`` �4 - - �_ • subsea applications. It has particularly been designed to survive in severe and violent conditions. • • The field electronics system is located in the meter housing. The software running on the electronics is the "brain" of the meter and does all data recordings, calculations and transmittal to surface. • All electronics, apart from the gamma densitometer, are rated for the full tt. • ind'u'strial temperature range of -40 °C to 85 °C. When selecting ing th he electronics units for the system, special attention was made towards • finding modules with high MTBF figures which had undergone vibration and shock testing in addition to HALT (Highly Accelerated Life Time Test). • • • • • • • • • • • • • • • • • • • • • • • TD -010 — installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 10 of 41 • Project Confidential • • • • • . • • • ? _ . w • • 2.6 MPM Terminal and Communication system In addition to the Field electronics, a MPM Terminal is needed for configuration and service of the • MPM Meter. The MPM Meter can also be linked directly (or indirectly) to the Control system (SCADA) • of the host platform. • It is possible to connect to the MPM Terminal from remote locations, such as onshore operations • centres, or from the MPM operations Centre. IP The MPM terminal is a tool for logging, calibration and configuration. The physical form of the standard terminal is the 1U form factor, for mounting in a 19" rack. Dimensions for the 1U terminal is; height • 4,3cm, width 43,0cm and depth 67,2cm. Other dimensions may be supplied upon request. ¢ t , . • • • • MPM Meter electronics and MPM terminal • • Remote FIELD • PC SENSOR AND ELECTRONICS • oLI. g a • U • Modbus mpm ,-tS485orTCPnP Flow /t RF • Termina Computer PCI DSP ' I Sena( Electronics • a j 1' • II c. P Bo ar= 0.1 • :i • SCADA Transmitter. Sensor • • The MPM Meter communication protocol is MODBUS v1.1a. The protocol may be on RS485 or • TCP /IP. There are two RS -485 serial lines, configurable for data rates between 1200bps and 921.6Kbps. • In addition the log database, located on the terminal, can be accessed through ODBC. • In order to optimize communication with the meter over slow serial connection, parts of the MODBUS • map has been made customizable. That means that there are blocks in the map where variables from • the static map can be stacked in any desired combination. This enables more efficient transfer since the desired variables can be transferred in one MODBUS frame, provided the desired registers • consumes no more than 251 bytes. • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 11 of 41 Project Confidential • • • • III • • The MPM Terminal software consists of several different components; meter communication service, • database, web service and GUI application. Below is an overview of the MPM Terminal components. • . The MPM Meter communication service is M Datafa3se PM Terminal (op #il r • esponsible for communication with the MPM )° ` "" Mee Ingging meter. It is possible to connect multiple meters to • 8 optional one terminal. Its tasks comprise the following: communication • • Poll configured measurement variables at configured intervals. • • Log the polled measurement variables. • • Log alarms, events and diagnostic information from the connected meters • • Create and distribute periodic reports for • service personnel by e -mail, if SMTP server is available web seriica _` • • Run diagnostic functions • Upload software updates ,--,-N, • Upload configuration /calibration data. • • Update average values measurement • data in the database. ...,...7 • The database is a repository of information for the • user. In addition to the logged measurement Remote PC • variables from the meters stored here, all configuration updates, software updates and diagnostic data are also stored in this database. • It is easy to create views for report generation, accessible through ODBC. • The GUI application is the main interface for the MPM meters and is made as a web service. The GUI • can either run locally at the MPM Terminal or be accessed on a local machine connected to the • Intranet/Internet. • Access to the GUI application is protected by username and password. In order to change any settings • you need a user with extra privileges. The GUI is described in separate chapters. • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 12 of 41 Project Confidential • • • • • • • • • • MPM • • 3 INSTALLATION • • 3.1 General • The installation procedures cover all steps from receiving the Meter, until installation is complete and • field commissioning can start. • • 3.1.1 Check of meter, flanges and covers • Before installation starts it's important to • • 1. Check that the flange covers are undamaged, and protecting the flanges. 2. All stud bolts, nuts and seals must be checked for potential damages. If hubs are used • their sealing surfaces and tensioning bolts have to be inspected. • • 3.1.2 Mechanical installation • The Meter shall be mounted with flow direction upwards, if not else specified. • The gamma source has to be mounted to the meter. Make sure the shutter mechanism is shut and • locked while mounting the source. • The vertical alignment should be made to secure a correct vertical position. An angle of plus /minus 2 • degrees off the vertical line can be accepted. If a larger inclination is observed, then MPM shall be • contacted for evaluating the situation and providing advice. • Make sure that it is possible to remove the electronics canister. In case of hardware failure this has to be removed. The free space above the electronic canister has to be the length of the canister lid in • addition to lifting equipment. • Please note that since the MPM Meter contains an electronic measurement system, NO • ELECTRICAL WELDING must be performed on the meter body or parts, nor in the adjacent pipe - work, neither during mechanical installation nor at a later point. This might cause severe damage to • the meter. • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 13 of 41 Project Confidential • 111 • • • • • mpm • • • • 3.2 Site Installation • • 3.2.1 MPM Terminal • • The MPM Terminal shall be installed in an appropriate location. • The Terminal may communicate with the Meter on or TCP /IP or RS485 . The Topside Meter must be connected accordingly. TCP /IP is recommended since this provides more flexibility and enables • better service and support of the MPM Meter. • Verify that communication with the meter is present by starting the MPM GUI. • • 3.2.2 Empty Pipe Verification test • This section is only applicable if static conditions are feasible. E.g., if the gamma source has been • removed during transportation of the MPM Meter, an empty pipe calibration has to be performed. The • calibration procedure shall only be performed with a warm electronics and warm gamma detector. • Below is a stepwise procedure to verify the empty pipe calibration parameters for the Sensor. • Item Description • 1 Make sure that the sensor is clean inside • Perform a logging in WetGas Mode for 300 seconds (5 minutes). • 2. Store the result to file : Site test — S /Nxxxx — air check WG Mode Compare the expected vs. measured value for the gamma counts. The expected • 3 value should be within 1 standard deviation from the measured value. Consult MPM if the measurement is outside the acceptance criteria. • • 3.3 Electronic temperature surveillance • • The electronics canister is fitted with cooling ribs on top. To avoid the inside temperature to increase • above specified temperatures, there needs to be free air flow around the electronics canister. • The sun can also contribute to temperature increase inside the canister. If the meter is exposed to severe sunlight over longer periods (like the desert) it needs to be shielded towards direct • sunlight. • 3.4 Installation completed • When the above steps are successfully completed, the installation process is completed. • Next phase will be start up and configuration of the Meter, as detailed in the Commissioning Section. • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 14 of 41 • Project Confidential • • • • • • • • • • mpm • • 4 COMMISSIONING • • When the Installation Part is successfully completed, the Commissioning part may start. During • Commissioning, the work should be performed as per the steps and guidance provided below. • • 4.1 Meter Start Up • The MPM Meter starts automatically when it's being powered up, and the context of this first step is to • assure that the Meter indeed has started, and that the communication between the MPM Terminal and the meter is functioning. • To do so, start the GUI, and select the meter you want to check. Make sure that measurement data is • valid and that no alarms are present. • • 4.2 Meter Calibration • The Meter is factory calibrated prior to shipment. There is no need for a calibration at site during • commissioning unless the gamma source have been removed during transportation. If the gamma • source is replace with the same used at the factory, a single point empty pipe calibration (air) is required. If the gamma source is replaced with a different unit, a two point calibration in air and fresh • water is required. • • 4.3 Site System Test • • 4.3.1 Transmitters • Reset the transmitter communication counters and log for minimum 1 hour. Record total number of • polls and error messages during the entire period and fill in table below. The error rate is calculated as: • Error Rate = (Number of errors /Number of messages) * 100 • Acceptance Criteria: The test is accepted if the error rate is less than 0.1%. • Transmitter Number of Number of errors Error rate [ %] Conclusion messages • dPinlet 1 • dPinlet 2 dPoutiet 1 • dPoutlet 2 Temperature 1 Temperature 2 • Pressure 1 • Pressure 2 • Gamma Detector • • • TD -010 — Mstallation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 15 of 41 • Project Confidential • • • • • • • mpm • LsaS °h r !; n y, • 4.3.2 External communication ports • • Before starting error logging on extemal communication ports, data logging shall be started with a • minimum poll rate of 1 Hz. • 4.3.2.1 External Serial Ports — RS 485 • Connect the MPM Terminal to COM 1, and perform logging of number of messages and errors for • minimum 1 hour and fill in table below. Repeat for any additional COM ports on Meter. • Acceptance Criteria: The test is accepted if the error rate is less than 0.1 %. Serial Port Number of Number of errors Error rate [ %] Conclusion • messages • COM 1 COM2 • • The serial ports have been tested with Modbus poll and interface to the control system. No • communication errors have been detected. . 4.3.2.2 • 4.3.2.3 Ethernet (TCP /IP) • Connect the MPM Terminal to communicate with the MPM Meter with Modbus over TCP /IP. Perform • logging of number of messages and errors for minimum 1 hour and fill inn table below. Repeat for any additional Ethernet ports on Meter. • Acceptance Criteria: The test is accepted if the error rate is less than 0.1%. • Communication Number of Number of errors Error rate [ %] Conclusion • Channel messages • Primary Eth1 port • Primary Eth2 port* • Only applicable for electronics with redundant Ethernet car • • 4.4 Meter Configuration • • 4.4.1 PVT Data • To provide measurements in accordance with customer requirements and as per its specifications, • the MPM Meter needs a certain amount of information about the different constituents of the • multiphase mixture (oil, water and gas). These configuration data is often referred to as PVT data, and can be provided to the MPM Meter manually, or automatically, depending upon the agreed set- • up. • In general, the MPM Meter offers a high tolerance to shifts in configuration parameter, dependent on • the flow conditions in the meter. This means that for a particular well, data specific values for that well can be used. Or, if the PVT properties for several wells are more or less the same, a common set of • configuration data can in most circumstances be used. An average composition for several wells • • TD-010— Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 16 of 41 • Project Confidential • • • • • • • • • • mpm 1 • which originates from the same reservoir may in most cases be sufficient. During the project and commissioning phase, it is recommended to perform an evaluation of the wells that will be used to • evaluate the need for multiple PVT setups. MPM can also during commissioning perform an evaluation of the goodness of the PVT data and provide recommendations whatever the configuration • data is sufficient in order to meet the performance specification for the Meter. • While the above comments are valid for most parameters, the conductivity of the produced water is • different. At tow WLR a potential erroneously specified value for water conductivity has little impact • on measured flow rates. However, once the WLR increases, and the emulsion turns into water - continuous (typically for WLR of 40-50% and upwards), a potential error in the specified value for • water conductivity can have severe effect of the measured water liquid ratio. This effect is more or • less the same for all brands of meters. Except the fact that the MPM Meter can be outfitted with an option of Auto configuration functionality. With this functionality, the water conductivity is • automatically measured by the Meter, and there would be no more need to provide manual input • values (which would also eliminate the need for sampling). • In the table below are listed the different configuration data. The table below also indicates the • importance of the various configuration data in order to maintain the uncertainty specification for the • meter. If some of these parameters are wrong, the meter will work, but some of the measurements may be outside the specified uncertainty limits. • Key parameter Importance • • • Oil density Important, particularly at low GVF and low WLR • Gas density Important, particularly at high GVF • • Water conductivity (low WLR) Less important • • Water conductivity (high WLR) Very Important' • • Water density Medium' • • Surface tension oil /gas (P > 15 bar) Less important • Surface tension oil /gas (P < 15 bar) Important for wet gas flow conditions • • Viscosity of gas Less important • • Viscosity of oil (< 2 cP) Less important • Viscosity of oil (> 2 cP) Important, particularly for high viscosities • • All the parameters for the oil and gas phase can be calculated based on the total hydrocarbon • composition for the wells, and this is the preferred way of obtaining the parameters for the oil and • gas phase. E.g., temperature and pressure dependent Zook -up tables for the oil and gas density, viscosity and oil /gas surface tension can be calculated based on the composition. • The tables can be downloaded directly to the Meter using the GUI. A typical hydrocarbon composition • (total) which can be used for this purpose is shown below: • • Componen Density t Mol % Mol wt [kg/m3] • • 1 If the MPM Meter is equipped with the automatic configuration option (salinity measurement), the • importance is low • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 17 of 41 • Project Confidential • • • • • • • mpm • 1.4. tesm • Componen Density • t Mol % Mol wt [kg/m3] • N2 0,354 28,014 • CO2 1,154 44,010 C1 55,767 16,043 • C2 4,658 30,070 • C3 2,774 44,097 1C4 0,583 58,124 • nC4 1,263 58,124 • IC5 0,546 72,151 nC5 0,711 72,151 • C6 1,197 85,300 • C7 2,400 90,000 731,7 C8 2,710 103,700 755,8 • C9 1,992 118,800 748,4 • C10+ 23,889 298,700 913,8 • Based on the composition, MPM can calculate all the required data for the oil and gas phase using • Calsep PVTSim (Equation of State). The measurements from the MPM meter can together with • together with Calsep PVTSim and the MPM Meter simulator also be used to verify the well • composition. If the total composition is not known, the total composition may be derived from oil and gas samples • at a known GOR. This may performed during the commissioning phase if pure oil and gas samples • can be obtained under pressure. A total composition for the hydrocarbon phase can be obtained by • analysing the gas and oil composition separately and recombining the composition for the oil and gas phase at the GOR measured by the MPM Meter. Please contact MPM for further details. • Even if salinity measurements are included in the MPM meter, it is recommended to put in density • and conductivity for the water as a fallback option until the meter has made a proper measurement. • In order to calculate the PVT tables MPM need to be supplied with the following data: • • Hydrocarbon composition of the actual well(s) • • Operational range of temperature and pressure • • Density for water at a given temperature (e.g. 15 degree Celsius) • Salinity or conductivity for the water • Please also note that if measurements are done for Hydrocarbon Mass basis, then the oil and gas • densities are of less importance since an overriding of the gas tends to be followed by a similar under • reading of the oil and visa versa. • • 4.4.2 Conversion to Standard Conditions • • The MPM Meter can also provide measurement outputs at standard conditions or any other fixed • temperature and pressure conditions such as test separator conditions. The conversion from actual to standard conditions can be done with or without phase transfer between the oil and gas phase. • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 18 of 41 • Project Confidential • • • • • • • • • • mm ra.n,- rte, ttra • • The Meter is then configured with the density of oil and gas at standard conditions. These parameters can typical be calculated form the total composition for the well. If the calculation is performed without • any phase transfer, the standard volume rates are calculated by dividing the measured mass flow • rates of oil and gas at actual conditions by the density at standard condition. • A temperature and pressure dependent Zook -up table for an oil to gas transfer factor is used to calculate net phase transfer from oil to gas (user selectable). The amount (in mass terms) of oil which • is degassing is calculated by multiplying the oil mass rate at actual conditions by the oil to gas mass • transfer factor. The mass which is degassing is added to free gas and divided by the density at standard conditions to obtain the total gas flow rate at standard conditions. The oil mass at standard • conditions is reduced by the amount (in mass terms) which is degassing such that the total • hydrocarbon mass flow rate is unchanged. • The look -up table for the oil to gas transfer factor can be calculated based on the composition of the well using a PVT simulator such as Calsep PVT and downloaded to the MPM Meter using the • GUI. • • 4.4.3 Two Phase wet gas Mode • In two phases wet gas mode the MPM Meter requires the GOR as an input parameter. The GOR can • either be downloaded directly to the meter using live PVT as described in section 4.4.5 below or based on a temperature and pressure dependent look -up table. The look -up table can be calculated • from the composition for the well. • • 4.4.4 Input of lookup Oil and gas densities • tables PVT IVO tYPe O density t e 01 density tkg nal • In this case, oil and gas Presage Peg] • densities are provided at r# 10 15 20 21 given pressures and t° � �° e30 zo s3o Kt asa s 870 • temperatures in tabular Temperature s40 850 985 870 880 • form. tde0 Cl 40 too 860 am VA a 870 sao astl sao 50 • To find the correct densities ensttcha for a given temperature and Gas dynl • pressure, the Meter will do a 10 Presage [Sera[ 1001 1002 1003 1004 • linear interpolation between 10 8 8 a the data points in the table. 20 s 9 Temper/ewe 33 10 10 10 10 10 • In the figure is shown typical low. CI - e 11 11 11 11 11 • density table 12 12 12 12 The other PVT data are • keyed in via the GUI/ PMP j OK ft c I Terminal. • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 19 of 41 • Project Confidential • • • • • • • mPm • f K42, • • 4.4.5 Continuous input of density values (Live PVT) • • PVT data can be transferred on a continuous basis from the platform control /SCADA system (live PVT). The configuration data is written into specified modbus registers in the MPM Meter. • The live PVT can be enabled and disabled from the process data set. The live PVT functions such • that the live PVT data has a higher priority than the data from the look -up tables. E.g., if there is no • data (or NAN is written to the modbus register), the corresponding PVT values in the look -up tables are used. • Hence, it is possible to use a combination of live PVT and look -up table such as : • • 1) Viscosity of oil and gas and surface tension calculated based on look -up tables • 2) Gas and oil density downloaded via live PVT 3) GOR (required for two -phase wetgas mode) downloaded via live PVT • • • • • • • • • • • • • • • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 20 of 41 • Project Confidential • • • • • • • • • mpm • un:r • 5 OPERATION • 5.1 Starting the MPM User Interface • • 5.1.1 MPM Terminal Login • Click on the Icon for the MPM GUI, a login- window like Use 'user • the one in Password I • Terminals: • Figure 1 will appear. If the Name I Server name/IP address • desired MPM terminal is not available in the list, it must Loop Terminal mpm loop terrain be added. Click the plus button to add a terminal to the • list. Enter the server name or IP address of the terminal • and press add. • Enter user name and password, and click "Connect ". The User interface window should appear. • r Press pleas to add or remove a terminal • Connect I Cancel • • • • Figure 1 Login Window • • 5.2 Remote Access • The MPM User interface can be accessed from a remote computer if it is installed on the same • network as the MPM terminal. To set up the user interface on a remote computer, the following is necessary: • Both computers must have access to the same TCP /IP network (intemet type connection) A user account (user name and password) must be available on the MPM terminal GUI for the remote • user. • The MPM Software must be installed on the remote computer. • • 5.2.1 Setting up the remote computer • Assuming that the remote and the MPM terminal is on the same network, and that a user account • exists, the setup process is straightforward: • Copy the MPM GUI software to a folder on the remote computer Advanced users may want to create a shortcut (icon) in the Windows start menu, on the desktop for • easy access. If so, the shortcut should point to the file MPMGUI.exe.The software installation is now • done. For first time used, a server name has to be added, see 5.1.1 for instruction on how this is done. • • TD-010— Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 21 of 41 Project Confidential • • • • • • 4) • mpm • t4. :tl Welk =et. ebzri • • • 5.2.2 Main page • The Main Page of the user interface consists of a standard MS Windows GUI divided into three parts, • a menu bar (top of window), an information area (left hand side of window) and a graphics area (see • Figure 2). In addition, the status bar (lower part of the window) is used to give some information about the meter. • The Main Page serves several purposes • - Provide a trend of flow rates, fluid properties and flow condition — as a function of time. • - Shows numerical, instantaneous values of flow rates, fluid properties and flow condition. • - Display information of the meter state The menu gives access to meter configuration, adding or removing MPM Meters, select different • trend, and look at diagnostics information. Consult MPM personnel in order to alter meter add or 0 remove MPM Meters and to select the variables and units displayed in the main page. • MPM GUI v3.0.0.2124 <Subsea Primary (1010) c!t..X • Lope and conNpraton Mete' Service Diagnostic 3D vier; ! 1 • - Update trends and values - - Trends - ® Updae — a�,m =. r, Graph averages • Oil. gas and water fiox - - - 3as W.f., - Flow raise (Actual conations) — wrr la'. • Oil ' 6 Olin.* • 00 Miliiii eh Gas I 0.0Im'fi Gas MBE r te Water I o I.% • Water � 0.' , 1 a oc Fk b _, -1 mR� 1 ' F 3 R • Formation MEE m'fi Measured fractions - -- - - - • WLR EMU : 4 roil •3 =I • p' . , 34Z 1342 13SZ wyF GVF � ,�; — y , % rsph averages - Salinity and Carductwtp — CO *[ t ^5:� GDR 0." OW Sal I 0.0J'.. • Other - 2 - -- . - - -- - Q ' Cond. I 0- 00ImScm Temperature ME • - Pressure Barg x I3 1 • Density We dP =EU mew • Velocity 0' mis SNA IE x •3 .ems 3..'>e • �� ' Tb� 1drat 114m 11:02 Water conductivity I IEL mS'an Water salinity ME3: WOR;t,` Graph averages • Seale Index Mj%: 1x :.1R end GJF —'h,.; m - WLR I 100 LI% . - -- ni • __ --- .. Active process data set .. - - c 0. _ GVF I 100,01 * 1- Subsea Meter Number One ' Status - -- - - - ; 3 - - z ' Q Status -OK x w_ _m: — Q Meter Online x_ -3: • a M2:08 -3acaa v *.ri -1.21C/4 -1.21C/4 -1.21C/4 me 4 • 2Ae 1 • Q Undefined 0 WGM mode (3ptaae) 0 Measored w. density 0 Measured w, conductivity : Stable) 5l ;aiity 0% l 100%: ; Figure 2 Main page showing Menu (1), Information area (2), Graphics area (3) and status bar (4) • • • TD-010 — installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 22 of 41 • Project Confidential • • • • • • • • • • mm • 5.2.3 Menu • The Menu (Figure 3) gives access to the following items: • Login • Login in as another user, (change user level) • Select Meter • Select other Meter to display data from (if more than one meter is installed) at the MPM Terminal • Configuration Report • Prints the configurations of the MPM terminal • View event log • View details about events on the meter (See also Section 5.4) • • MPM GUI v2.0.0.1902 <Local meter> (11100) • Login and configuration Meter Service Diagnostic • Figure 3 MPM Terminal Menu • • • • • • • • • • • • • • • • • • • • • TD — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 23 of 41 • Project Confidential • • • • • • • • mpm r, +m ,tr s w,,,Nra • • • 5.2.4 The Information area • The Information area displays current values for —Update trends and values - - - -- -- • flow rates, measured fractions and other ® Update • measurements. —. ____- -___ -. _ ._ . - Ilow rates (Actual condtionsJ A check box on the top makes it possible to of 32.8 an r, ( • stop the updating of values. This is useful if the Gas MI= rTM1 • operator wants to stop the update and evaluate 3.4 n /b • the data. • r Measured fractitms — The flow rates are presented in the selected WLR 9.3 % • units. ; 1 WVF 0.0% • Measured fractions display the fractions GVF 87.5 calculated by the MPM Meter. GOR 0.0 mslm; • The area called "Other" show some of the Other • transmitter readings, calculated velocity, ' Temperature NAI'C • measured Water Conductivity (converted to Pressure 16.3 Barg • 25 °C) and measured Water Salinity. , Density o.0 kg/re The status Tight is green if no alarms are active dP 204.9ImBar • on the meter. If an alarm situation occurs, the Velocity 0.0 mts • Tight switches to red. Sw 0.0 % • Click on the Tight to view Alarm status. From the 2.63 mSlcm Alarm status it is possible to click "View event Water conductivity • log" to see the details (See also section 5.3). water oink) 0.8 % Scale Index MAI % • The meter connection state Tight is green when • the meter is online. If the meter is offline or Status having communication error (no contact with the 0 Status: OK • meter), the Tight switches to red. go • Meter On If Remote, yellow Tight is displayed if limited or • no connectivity. If limited or no connectivity Figure 4 Information area • exceeds one minute, the light switches to red. • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 24 of 41 • Project Confidential • • • • • 0 • • • • • • • 5.2.5 Graphics area • Trends • gas 7 y ��� Graph averages :DO . and wader tiVK oa I 32.o,rr m • , .. = � -. +,P.M'4+r`IMIth ..Nt+yV'l. '` - 4 ` Water I 3.5Im;Jh • Gas I 258.1Im'Jh • _ - • • - �rw'w�. �n.:..-.. 'r . •+...- .n.r..'.,.W�-:. —_- v. nlnerv++.. rn�.•.' 4nri4 '�Y^.ft++ ^14.n.N'}rni+a�• ✓-.. -- . --s „' ..py_ C6 , G raph averages • Salinity and Conductivity - 1 : •, _� Sal. 081% • r ti,y�ry� Cond. ` 2731m5/cm • E 9 0 - O i ,X 7 ®L21.26G X. -232 =796 1T.1aw - 2 -.:Y_ • LRarsdGVF — WLR,`.\ Graph averages —V tt.. • WLR 1 9.8 e • - t - GVF I 67. % • - • --- - • 2 -Z • 08 : 0I 0.tiSi 012,2567 1..m.20 15% 251096 • Figure 5 Graphics area • • The graphics area shows three trend plots that are continuously updated. The graphics area shows trend of selected variables. Graph averages of the trends are shown on the right hand side. It is possible to right click in the trend area and set or change axis limits. • If the trends are static, it is most likely caused by either update is turned off, a communication error, or the meter is not enabled in the configuration. • Each graph can be configured to display different data independently. It is also possible to set the Y- • axis and Y2 -axis for each graph to fixed min and max values; the default is auto. The available trends • are dependent on logged variables. • • • TD -010 - Installation and User Manual - MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 25 of 41 • Project Confidential • • • • • • MP M • tx .rteicr • 5.2.6 Status bar • The main window have a status bar (Figure 6) in the bottom of the window that displays information • about the metering state. • o of ominous Q MPM node 0 Measured w. den* 0 Measured w. cadJCUViy Stable '3 Slug : Qualky Ox 3 700* Figure 6 Status bar • • From left to right, the items on the status bar are as follows: • Liquid Phase, Oil Continuous/Water Continuous, 3D BB disabled • o In MPM Mode, this section shows whether the flow is oil continuous or water • continuous o In WetGas Mode this flag is undefined • • Multiphase Mode/Wetgas mode, 3D BB disabled • o This flag show the selected mode of the meter • Measured density • o This flag is green if measured water density is used. If it is grey, a static value or LivePVT is used. • • Measured conductivity • o This flag is green if measured water conductivity is used. If it is grey, a static value or • LivePVT is used. • Stable /Slug • o This indicates a stable flow regime (few gas - slugs) or sluggish regime (many gas slugs). The measurement is based on data from the last 20 seconds. • Quality Index • o Not implemented. • • • • • • • • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 26 of 41 • Project Confidential • • • • • • • • • • • • 5.3 Alarm Status • The Alarm status provides information about the transmitters, Software and External Communication. • When a transmitter is installed it will display a green light when everything is ok and a red Tight if • errors are encountered. If a transmitter is not installed a grey light is displayed. • If errors occur, click the "View event log" button to see the details (see section 5.4). • • Alarm status NIM • 1 2 Gamma Q Q • dPirdet Q V' • dPOutlet Q o • Pressure Q Q • Temperature • 3D Broadband • Software • External Communication Q • V OK Q Failed ) Unavailable • I View event log I Close • • • Figure 7 Alarm status • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 27 of 41 Project Confidential • • • • • • • MPM • tir • • 5.4 Event log • The event log lists events with the severity 'Info ", "Warning" or "Error ". It is possible to get a selection • of events limited by severity, process and /or event id. To view additional event information (Figure 9), • double dick the event in the list. • Event log pt. „,, • Q Seventy Process Event id - - -_ — —.-- - -__ • ❑ Irk 0 DSP Interface ❑ Meter Con,mmication 3ervbe IA data ire (Trendier data or broadband data) has faded 1163986 ❑ Warrin ❑ External CominaicaoOn ❑ Process Supervisor A shays data roe goo t vab has as oaa s eocue Nis inapol m done (6/701 • dn6/01 ) Axrae/Kd pave issue 6 e of thenrd [201927 • ❑ Euu ❑ Flo. CalouleEon [7 m s 7ru )ter Interlace Accu Calculation 3881 ❑ Log Could id red paces [4100) Could rot open le wih caioatbn constants [1 63961 v Date !Sarraeiti !Saxe Proms Event Id Even Description ► • 06.1220061 &08 Warrig flow Calculation/ 16389 Calculation issue 06.122006 125B y Wareing Flow CabJetiaa 1638E Calculation issue • 081220861253 , Warring now Calculations 16388 Calculation issue 08.1220061250 VI* DSPlnerface 20491 DSP/Ebwori:s diagnose valu • 08.1221061250 t DSP interface 20492 Accurxiated patine ref charnel 0312.2006 1250 Y ' Info DSP Interface 20490 DSP Serial port diageosis values 08.1220861246 _y Wising Flow Calculations 16388 Calculation issue • 08.12200812:43 ;Warning Flow Calculations 16388 Cab.lation issue 09 1 Warning Flow CabulMUrs 16398 Calculation issue 08.12.2[06123.5 Jlno DSP Interface 20492 Accumulated patine ref charnel 08.1220061235 Jlrio DSP Interface 20491 OSP/Electroics diagnosis value III 08.122[061235 I Ina DSP Interface 20490 DSP Serial port diagnosis values • 08.1 2 2006 1233 s Warning Flow Calculations 16388 CabJetirissue 08.1220061228 r Warn:o Flow Calculations 16386 Callouatir issue 08.122006 1223 Warning Flaw r 16388 Caklatm issue • 631220%1220 )Info DSP Interface 20490 DSP Serial port diagnosis rattles 09.122006 1220 )Info DSP Interface 20491 DSP/Electror cs diagnose vale ;08.12.2006 1220 parr DSP Interface 29492 Accraulated pahse ref charnel • __08.12208 t 61218 .Wawg Flow Calculations 16336 [ablation :issue _ _ 08.122006 1213 tWarni al'v g Fbw Calculs 16388 Calculator issue 08.1220% tWarnrg Flow Calculations 16388 Calculation issue • o 08.1 2 2008 1205 J)Irfo DSP Interface 20492 Accumulated pahse ref channel Fist page 11 Revio o page I Next page I' Last page l Page 11290 ( • Figure 8 Event log • Event properties a ©® • Event Id: 20490 Severity Info t 1 • Date: 08.12 2006 1250:56 Process: DSP interface i • Meter: Local Meter Description: • I► SPSerial..tt di ., ross value.: • • Addtional data: f Bytes (Hex) a. Text • PSU -OK, T>1.1.0 K. RXSMU -OK, TXSMU -0K, RXU-OK, HWCU -OK • • • • • III Figure 9 Event properties • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 28 of 41 • Project Confidential • • • • • • • • • MPm • txa.;tC ettte. • • • 5.5 Trend /export data • This dialogue is available for user with Supervisor privileges. In order to log on as Supervisor, select • Login dialogue from the "Login and configuration" menu. • In the "Trend /Export Data" dialogue it is possible to view historical data for all meters with the log • interval: user defined (e.g. 0.5 sec), 1 minute or 1 hour. It is also possible to export data to a comma separated file. • Trend and export data an • Meter Internal test meter `'. Start I06.11.2007 1412012J End 15 minutes J I ,_,.l Log intend 10.5 second J I V 1 Export ' ( Close Trend • Available variables Local minter dPInlet e, • dPIrien dPInlet2 dP�W�t Was �x�xva� ef^n`.TI — a'7u x::_ - ,e [�+F *l — �rax;wiv [m :,`F4 dPOabti � :_ rPOutlet2 Emulsion • FCStatus • GmmaCount rAwNN,j�(�r.�f ^', - ' W,�y Y r 'ti`�'aMr+V " � ^I'Ar wt y YU " M "AGI i Y'' Y'1� ""Y�v 7 Y�4�'J` , Gas density Gas velocity • GOR Mass GOR Standard Mass: GOR Standard Volume • GOR Volume GVF Actual Volume Lipid veocty • 1 MeterStatus Mu density Oil density • Pressure Pressure2 • QFormWater Actual Mass 4FormWater Actual Volume QFormWater Standard Mass • QForrnWater Standard Volume QGas Actual Man r QGas Actual Volme • 0Gas Standard Mass QGa. Standard Volume • j 130i Actual Mau QOi Actual M ass vi _'"w^-"'^"-"""'i�"'°"^""' ' - � - vu QOi Standard Mass • Q _ _ _ _.___.,,,.,..- Ot ndnn v 4Cd Standard ndex Water Actual Mass • Figure 10 Trend /export data • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 29 of 41 Project Confidential • • • • • • • • • • • 1111 Dialogue toolbar • _ j �� v ' v Figure 11 Toolbar Button • The toolbar button (Figure 11) functions are as follows: • • 1. Page setup 2. Print the graph • 3. Print preview • 4. Copy the graph 5. Previous • 6. Next • • 5.6 Meter Configuration • • These dialogues are available for user with Supervisor privileges. In order to log on as Supervisor, select Login dialogue from the "Login and configuration" menu. • • 5.6.1 Select active process data set • With this menu option the user may select a process data set for the current MPM meter. There are • 10 process data sets available for each MPM meter; each set can be configured individually. The next • section explains the various data input fields available in a process data set. • • 5.6.2 Create New Look -Up tables (PVT gas and oil properties) In order to create a new look up tables in the process data set, density gas, density oil, viscosity gas, • viscosity oil, surface tension and Gas - oil - ratio(GOR at actual conditions) as function of temperature and pressure is needed. When these parameters are available, open the Process Data Configuration • page and choose which process data set you want to enter data into. Open the PVT, oil and gas • properties page and type your obtained parameters into the tables as function of temperature and pressure. • Then close the window and press `send to meter' to upload the tables to the meter. • • • 5.6.3 Process data configuration • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 30 of 41 • Project Confidential • • • . • w • . • mpm • In order to get accurate measurements it is vital to give the MPM meter accurate information about • the physical properties of the fluid components. • This is done by selecting Process data configuration from the Meter menu. • P rerrss data configuration I - Procea dam eat htarnutiar , Water calsration • . ..... .... ..... .. . • ! Name ( Aveage C m p o s ti a n t « at web an Maki 1 i , Water corducti* Q Ford 0 Measured - . . ,, • D Water den* Q Fixed 0 Measured - ' - Water - - - _. .- -- - --- -- - --_.. _ _ . Dandy I 1045 kg/m3 at tmperatuo I 151 deg. C �:: Co ductiviy I 91 mS /cm at temperature I 251 deg. Metering settings .. - - _... -_..-- -- -.- __ -.-- - - -- -- - i t' v.de ;eor ^ a , er - • Meameemmet mode Q WetGas Q MJtphase fl Automatic MPM GVF I SEOI , - I 1 ` - I WGM GVF I 97.01 I I 1 . - . 1 l ' 21 Use Broad Band demiW - Standard conditions - . _- � - - � �- - - --- - -- • - Minimum GVF f o r Broad Band m e a s u r e m e n t I 9151 Denedy+ of 1 855.0071 kgrm' 1 751 deg. C at Mar®om GVF (« Gamma measurmer 1 99.0 Densk gas 1 o.salkgm 1 01 bag • ❑ the Moving Average tier on output data . • ❑ Use Reed GOR Food GOR I I 0 Use Lookup table ❑ Disable BB Fired WLR I " ❑ Add flashed gas from of ❑ Enable Live PVT input • Dielectric constant -- _ . - - -- -- - -- - . - - - D'ndedric c tart offset - - - . - Gas - - - - -- _ - - - - - - - gas tace krxion - . Oi 1 1 ❑ Override 1 I deg. C Oi 1 Ol Gas Ism Exponent 1 7.41 Co ® Water / p surfaee su fermi E«n water 14 141' . Niro • Gee { _I ❑ Over at : Surface tension water - Override I -) berg Gee I 01 Use Dry Air Dersiy ❑ • - Soft water lectors - - Viscosity at actual conditions - - Water viscosity factors - Water smoky filer Eras - - -- - - Mass absorption coefficient - - - B0 1 ?; El I Oi 1 OA061491Pae DO 1 0.7181 Min value 1 1.51$ 0 I I ❑ Override • 61 1 ;.'.1 Gas 1 1.59E-051Pas D1 1 0.003591 Max vatue1 41% Water 1 ❑ Override 62 1 i water I 1Pas 0 u 02 1 OI j ` Gas I 1.OI 67 Ovemde • I Close - - - -- - • Figure 12 Process data configuration • In the following is provided information about the different options and input data: • Function Description • Metering settings Selection of measurement mode. The Meter may be forced to use • multiphase or wet gas measurement mode. If automatic measurement mode is selected, the meter switches between multiphase and wet gas • measurement mode. • There are two wet gas modes namely 2 -phase and 3- phase. In two • phase mode the GOR is required as an input parameter. A look -up table for the GOR can be entered in the PVT properties section. This table is • typical calculated from the composition of the well using a PVT simulator • (Equation of State) • The switching works such that if the GVF is above the GVF value "WGM • GVF ", wet gas mode is selected. Similarly, if the GVF is below the value • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 31 of 41 Project Confidential • . • • • • • • mpm • Function Description • "MPM GVF ", multiphase mode is selected. WGM GVF should always be • larger than MPM GVF. In the section between MPM GVF and WGM • GVF, the last setting is used. • For low pressure applications (e.g. below 10 -15 barg), recommended • switching area would typical be around 90% GVF. For higher pressure applications, it may be desirable to use a higher GVF setting, typical • around 95% GVF. • For ultra high GVFs, an additional BB based GVF measurement may be • used. This measurement is particularly accurate for ultra high GVFs. The GVF range for the BroadBand GVF measurement can be configured by • the parameters Minimum GVF for BroadBand GVF and Maximum GVF • for Gamma measurement. Recommended values are 99.5% for Minimum GVF for 3D- BroadBand GVF and 99.0% for Maximum GVF for • Gamma measurement • Note: The Broadband GVF measurement is not available in multiphase • mode. A moving average filter of 20 seconds can also be added to the output • data in order to provide some damping on the output data. • The meter can also be configured to be forced to use a fixed GOR. This • function can be used to provide measurements from the meter if the • gamma detector fails. However, the uncertainty of the measurement will • be significant higher. The broadband electronics can also be disabled in this section. If the • broadband unit is disabled, a fixed WLR value can be downloaded to the • meter which will be used together with the remaining transmitter • measurement providing simplified calculations of the flow rates. The measurement uncertainty for disabled broadband electronics is • significantly higher particularly for slugging flow conditions. • NOTE : If the meter is configured to measure the water salinity in wet • gas flow conditions, this function will only be enabled if wet gas mode is • selected. I.e., the meter will not measure the water salinity in wet gas flow conditions if mode selection is set to AUTOMATIC. • Dielectric Constant This section allows the user to entering a fixed value for the dielectric • constant of oil and gas which over rides the dielectric models in the MPM • Meter Dielectric Constant Offset This section allows for correcting the dielectric constant models with a • constant offset and can be used for fine- tuning or correction for error in • the PVT input data. • Salt Water Factors These parameters allows for use of different salt water models for • calculating the temperature dependency of the water density. The default • values correspond to NaCI salt. • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 32 of 41 • Project Confidential • • 110 • • • • • mm • 1.#01,= t teette • • Function Description • Viscosity at actual The oil and gas parameters are not used and will be removed in future • conditions versions of the GUI SW. (The oil and gas viscosity is calculated based • on the temperature and pressure look -up tables) • The water value can be used to over ride the viscosity calculation • performed based on the salinity for the water • Water Viscosity Factors These are salt composition related factors which are used to configure • the models for calculation the water viscosity based on the water salinity. • Water Calibration The water density and conductivity can either be entered into the meter manually (fixed option) or measured by the meter (measured option). • The fixed values are entered at a given temperature (and 0 berg) which • usually are 25 °C for the conductivity and 20 °C for the water density. The MPM meter performs temperature and pressure corrections for the • density to the actual T and P conditions. • If the measured conductivity and density is used, it is still recommended • that the meter is configured with a typical fixed values for conductivity and density since this is used as fall -back values when the salinity • measurement is out of range (the water salinity measurement is only • available in water continuous flow) • Standard Conditions The standard conditions calculations are configured by entering the oil • and gas density at standard conditions. These parameters are typical • calculated from the composition of the well. The temperature and • pressure conditions for standard conditions are also defined here. • In this section flashed gas there is also an option to add flashed gas from the oil. The oil at standard conditions will then be reduced • accordingly such that the total hydrocarbon mass flow rate is conserved. When this option is enabled, it is possible to enter a temperature and • pressure look -up table for the mass transfer factor from oil to gas. • • Gas This section allows specifying if some additional properties for the gas • such as the Gas Isentropic Exponent. • There is also an option for using equations for dry air for calculating gas density which is used during testing of the meter in the MPM flow • laboratory. When this option is enabled, the temperature and pressure • look -up table for gas density will not be used. • Water Salinity Filter Limits This is filtering limits for the water salinity measurement for removal of • measurement outliers. It is recommended to set the filter limit • approximately 25 - 50% above the highest salinity which can be • expected and 25- 50% below the lowest salinity which can be expected • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 33 of 41 • Project Confidential • • • • • • MPM • 4k t,' �Peet�r; • • Function Description • for the wells. For water injection wells, the upper value may be the salinity of the • formation water whereas the lower salinity limit may be the value of the • injection water (e.g. seawater). • Water / Gas surface The water / gas surface tension is calculated by the meter based on the • tension salinity and measured temperature when the "Calc surface tension from water salinity" option is enabled. A fixed value can also be entered. • Mass absorption The mass absorption coefficients for oil water and gas at 660 keV can • coefficient either be calculated by the meter or entered manually if the over ride • function is used. The meter calculates the absorption coefficient from the • oil and gas density and water salinity assuming NaCI salt. • The mass absorption coefficient for oil, gas and water can be calculated form the composition using the XCOM database at NIST (National • Institute of Standards and Technology) • (http: / /phvsics. nist .qov /PhvsRefData /Xcom /html /xcom 1 .html) • NOTE . The mass absorption coefficients calculated by XCOM has been • found to be slightly lower compared to measured mass absorption coefficients by the MPM Meter. Also ,a gas mass absorption coefficient • of 1.0 has been found to provide satisfactory result in most applications • involving hydrocarbon gas. • • • • • • • • • • • • • • • I • ' • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 34 of 41 • Project Confidential • • • • • • • • • mm • Isun Dees • • • 5.7 Dialog toolbar • S en d t o meter • • Figure 13 Toolbar Button • • The toolbar button (Error! Reference source not found.) functions are as follows: • 1. Select the process data set to view • 2. Erase all data from the process data set 3. Enter PVT, Oil and Gas Properties (See • Figure 14) • 4. Upload current data set to meter 5. Export current data set to file • 6. Import from file into current data set • • The dialog has two free -text fields, Name and Description, where the operator may enter any • information as pleased. • For PVT calculations several options are available: • Density and GOR If this option is selected, densities are calculated using look -up tables and • interpolation (see Figure 14). GOR is used in Wetgas 2 Phase mode. • Simplified PVT (Currently not implemented) Use LivePVT If this option is checked, LivePVT will be used. LivePVT means that Oil, • Water and Gas densities are continuously updated from ModBus registers. • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 I• Project Name: Magnolia, Entrada Page 35 of 41 Project Confidential • • • 1 • • I I mpm tAMPIallelletes ' 4 5.8 PVT, Oil and Gas properties dialogue 4 4 Oil and gas properties _ N 4 PVT ink hype Q table Viscoedy 1 GOR (Actual condtions) j Surface tension oil/gas j Oil : gas mass t ansferfactor j De sity oi fltgier31 4 T e [deg. C[ 6E '; 7C; BC'' SO' 100 25G; 544; E2"; 6 £2C. 620 4 2&C 62c i 586.8E 534 5815 577.6 Pressure 27:6 62v! 583.6 586.9 5;7.9 574.5 i gl t-... - 22O' 62C . 556:4 577.2 ; 574.8 571.5 4 29D 1 62C 577.2 i 574 571.6 ; 569.4 4 �itygeS l Temperature [deg. C[ 3C, 35 4D` 45 5C 19D' 146. 1 146.9, 136.9 133.3 123. 4 Presstae 15 148.4 ? 144.2 14D.2; 132.5 1 tB&gl 2, C ' 151.8: 147.5 ; 143.4 139.E 136 2E5 c 1551 ' 15.. ! 14E.E , 1427 133.1 I 21 158.3. 153.9 149.7 ; 145.8 142.1 I 1 OK 11 Cancel I 4 Figure 14 PVT If Density and GOR is selected as PVT method, densities are added by pressing PVT, Oil and Gas I Properties button in the tool bar (button 3 in Dialog bar). Oil and gas densities are entered with 1 increasing temperature and pressure in the tables. Pressure, Temperature and densities should be entered. I Below is also a picture of the table entry for oil to gas mass transfer factor. This table is only available I if the "add flashed gas from oil" option is enabled in the Standard Condition part of the process data I setup (se section 5.7) 1 1 1 1 I 1 I I TD-010 - Installation and User Manual - MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 36 of 41 I Project Confidential I I I • • • - • • • mpm fAIII h. Netea • • Oil and gas properties r ,---- L • FYT input type C) table -) c . :0 • Dens+yy I Viscosity I GDR (Actual condition)) Surface tension oflgas 08 •> gas mass transfer factor I • 0II - > gas mass transfer factor • Temperature (deg. Cj • 401 601 80, 1coj 110 20 0.02 0.021 r 0.0221 0.023 0.024 • 25 0.02 0.021 0.023 0.0231 0.024 P3argl 30 0.022 8023 0.024 0.026 0.028 • 35 ' 0.028 0.03 j 0.0321 + 0.037 40 0.03 i 0.0311 0.034 j 0.037 0.04 • • • - - • - - • I o 1(I • • • • • • • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 37 of 41 • Project Confidential • • • • • • s .. • • • 6 MAINTENANCE • • The MPM Topside Meter requires some maintenance. • The following maintenance activities are suggested by MPM: • • 6.1 Operations Integrity Services (OIS agreement) — link to MPM Operations Centre • It is highly recommended that a OIS agreement is made for the continuous in -situ verification and • diagnostics of the Meter, with regular reports being issued and submitted by MPM to the Operator. • The OIS agreement contains the following elements: • • • Remote Connection to Meter • Reports sent regularly from Meter to MPM Operation Centre • — Events, Alarms, Quality Index and raw measurements for In -situ verification • • Assessment and In -Situ Verification of — Overall performance / Quality Index • — PVT / configuration data • — 3D Broadband — Transmitters • — Gamma Detector • Client reporting • — At defined intervals and events (SMS, e -mails etc) • The link to the MPM Operations centre is shown in the Figure below: • Further details are provided in the Agreement for Technical Services (ATS). • • III _- _ .OPCentre Server oM • MPM " • Operations Centre • Internet Example: • FIELD B - Africa -_ All • Example: FIELD A - North Sea MPMT ,n, M- ermine' • AV 41, 4664 • it k 9 4 . mt. .4a • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 38 of 41 • Project Confidential • • 411 • • • 0 • • Mm • M.,n. -t ,deter • • • 6.2 Verification /recalibration of Venturi Cd • • Verification of the venturi Cd is recommended being done only if sand is being produced (erosion of pipe internals). To be able to verify the Venturi Cd, the Meter must be compared to a well proven • reference, preferable with single phase flow. • • 6.3 PVT maintenance • It is recommended that the to verify the PVT data used to configure the MPM Meter on an annual • basis. Some applications may require more frequent verification and some Tess depending on the stability of the total hydrocarbon composition from the wells. A well composition verification can be • done by verifying the measured GOR from the MPM Meter with the flashed GOR using a PVT • Simulator based on the total hydrocarbon composition for the well. If a deviation is observed, a re- calculation of the total composition for the well may be required. Measurements from the MPM Meter • or the MPM Meter simulator, together with a PVT simulator can be used for this purpose. Please • contact MPM for further details. The MPM Meter may also be used to measure single phase properties during shut down periods; however this may depend on the particular installation and flow • conditions. If the Meter is filled with pure oil or gas during a shut down, measurements can be taken • to verify the quality of PVT input (please contact MPM for further details). • 6.4 Communication Tests • There are two types of communications tests; one is to check how the internal communication runs • the other is how the communication runs between MPM meter and the terminal. These tests are run from the MPM GUI and can be found under flag 'Diagnostic' choosing subflag `Hardware'. The • window in figure 15 below will appear. • Meter CEnf Maamoura 01? (#4027) isEI . Q • Communication with meter Last reset lice: 01.04.2008 0&37:47 • Errors: 0 • Tot 395 I Reset error counter Transrr ter E Enos G Total • dPlrrkt1 0 1592 • dPlydat2 NA NA dPO�let1 NA NA • dPOullet2 NA NA Game 0 1241 • Samna2 NA NA • Pressuret 0 1591 Press ze2 NA NA • Teir+peraEae1 0 1591 Temperaure2 NA NA • I Read I4 Reset ( 1 clwe I • • Figure 15 Communication and error reading • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 39 of 41 Project Confidential • • • • • • • • mpm • • The errors in communication between the MPM meter and the MPM terminal can be read from the • upper left comer. It shows the last reset time, how many errors on the total of communication • packages received. This communication can either be run on Modbus over TCP /IP or Modbus over • RS485, depending on what was requested for the application • The errors in communication between the transmitters and the flow computer can be read as seen on figure 15. These values do not update automatically, in order to update press `Read'. • The normal acceptance criterion is that Tess than 0.5% of the readings can be errors. Error rate • should be even lower than this, it should be zero. But if the error rate exceeds 0.5% something is • wrong and MPM technical support shall be contacted. • • 6.5 Mechanical Maintenance • The topside meter requires annual inspection of the EX- components and a general visual inspection. • The EX- components consists of the P -, T- and dP- transmitters and also the gamma detector and the • electronics canister. Depending on the application the P -, T- and dP- transmitters are intrinsic safe EX- • components. • As regards the EXD components — we recommend EX maintenance according to IEC 60079 -17 /IEC • 60079 -1( NEK420) • See Instrument Datasheet for details on EX -parts • Double Block and Bleed Valves: • We recommend interval for periodical maintenance operation and flushing /cleaning of valve and seal flanges to follow Company procedures for the specific system and service. • Open lids on antenna boxes to check for moist • • Check shutter mechanism on gamma source that the lock operates as it should. • Gamma source will have to be replaced after 15 years. • Transmitters, Dp and PT. Calibration routines to follow Company procedures for the applicable system the meter is specified • for. • Check that supports of cables and hoses are tight and undamaged • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 40 of 41 • Project Confidential • • • • • • • • • mpm • b .m: Rtetera • • 7 REFERENCE DOCUMENTS • • Document title Document number Document revision • • Transport, Handling and Preservation TP -008, MPM internal 4 Procedure document • MPM Topside Meter — Technical Description TDS -001, MPM internal NA • document MPM Subsea Meter — Report from Design and 4015- REP -003, Project 1 • Qualification Program document Test report - MPM Subsea Meter at SWRI REP -007, MPM internal 4 • document • White paper 1: Unparalleled measurement Internal document NA accuracy and sensitivity • White paper 2: Water Salinity Measurement Internal document NA • White paper 3: Dual Mode functionality Internal document NA • • • • • • • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 41 of 41 Project Confidential • • • ~~ ~~~ r +~~c~t~~~€~~ h.laska. Lnc~ December 10, 2008 Commissioner Dan Seamount, Chairman Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 • Chris Wilson Supervisor, WNS Base North Slope Operations and Development, ATO 1762 700 G. ST. ANCHORAGE, ALASKA 99501 Telephone 907- 265-6573 E-mail Christopher.j.wilson@conocophillips.com RE: Request to Include Kuparuk Forma#ion in the Alpine Pool and Expand the Alpine Pool Colville River Unit Area North Slope, Alaska Dear Commissioner Seamount, ConocoPhillips, inc. as Unit Operator on behalf of the working interest owners of the Colville River Unit ("CPAI") respectfully requests that the Alaska Oil & Gas Conservation Commission ("Commission") approve administrative amendments to Conservation Order C0443A and Area Injection Order 18B to allow for the expansion of the Alpine Oil Pool ("AOP") and Alpine Area Rnjection Order ("AIO") to include the Kuparuk formation and new prospective lands in anticipation of future development for oil production. The proposed AOP, as described in subsequent paragraphs, overlaps the Kuparuk formation with the Nanuq Kuparuk oil pool. Therefore CPAI requests that the Commission amend the AOP to include the Nanuq Kuparuk oil pool and terminate the Nanuq Kuparuk Conservation Order No. 563 and Nanuq Kuparuk Area Injection Order No. 27, so as not to have two sets of rules for the same stratigraphic unit. CPAI requests the AOP and A10 modifications for two reasons: 1) seismic, drilling, well log, pressure, and production data indicate that the Kuparuk and Alpine intervals are in pressure communication at the Char No. 1 exploration well, CD1, and CD-4 areas, and 2) the AOP drilling program for the winter 2009 season and in the future is anticipated to expand the pool beyond the current AOP area. These reasons are discussed below. Tectao~ 6ca8 IBac&g roar ~d r~ressure communication within ,nraposed AOP. Drilling, well log, pressure, and production log sits indicate that the Kuparuk and Alpine intervals are in pressure communication. ~`;E>r~ocoPhillips recently c©mpleted two wells in the Kuparuk sandstone (whirt~ Iles st°=tigraphically above the Alpine sandstone) for production in the CD1 area and found elevated F~rwssures of 4500-4600 psi in the Kuparuk formation, whereas 3200 psi is considered °norms!" ;:ressure. In addition, elevated pressures in the Kuparuk formation were Mound asst ~virter in t~ ~: ~r:r ivo. 1 exploration well. "third, subtle pressure changes, Indic«ting ~: pressure ~s munication .in the CD-4 Kuparuk area, have been observed over the r~,. iU', t °~eara with the nericement of testing and production out of the Nanuq Kuparuk iii poi • • In the Alpine CD1 area, significant lost circulation encountered while drilling the Alpine C sand in the CD1-06 and CD1-14 wells resulted from natural fractures/faults associated with a nearby fault to the east. Water and gas injection in the Alpine C in the CD1-06 and CD1-14 wells is interpreted to have pressured up the overlying Kuparuk sand via natural fractures/faults at or near these injection wells (Attachment 1). However, there were no lost circulation or pressure "kick" incidences while drilling through the shallower Torok and K-2 sand intervals, implying that faults/fractures in the proposed expanded Alpine pool do not extend into overlying shallower sands. Furthermore, seismic in the CD1 area shows that the seismically-resolvable regional faults in the area are difficult to interpret through the Kuparuk formation, and do not propagate into the HRZ (Attachment 2). Additionally, even though CPAI has injected large volumes of gas in the Alpine C at CD1 since 2001, no wells drilled subsequently have encountered over pressure in zones above the Kuparuk. Pressure communication in the CD2/Char No. 1 well area is likely the result of the Alpine A/Kuparuk C sand-on-sand contact as observed in the "toe up" of the CD2-02 Alpine A injection well at TD. Additionally, there are no seismically-mappable faults in the area (Attachment 3). Normally pressured Kuparuk was measured in the Kuparuk in the Char No. 1 well area by the Iapetus #2, drilled in 2005. CD2-02 did not begin injection until months after Iapetus # 2 was drilled in 2005. Pressure communication outside of proposed AOP. There is no evidence of pressure communication between the existing AOP and the Nanuq-Kuparuk Oil Pool with shallower zones. Pressure monitoring of wells completed in the Nanuq turbidite (Torok Formation) in the Nanuq Oil Pool showed no evidence of pressure communication with the Alpine or Kuparuk Sands. Pressure measurements of wells completed in the Qannik Oil Pool in the Nanushuk Group also show no evidence of pressure communication with the Alpine or Kuparuk Sands. There is minimal in-situ measured data below the Alpine; however, those data available suggest that the Nuigsut sand in the CD1 area is extremely tight. Alpine AIO 18B indicates that the Alpine sandstone is underlain by a think shale interval assigned to the upper Kingak Formation. Petrophysical analysis indicates the parting pressure of these shales is 700 to 800 psi greater than the Alpine sandstone. Therefore it is expected that fracture growth initiated by injection into the Alpine Sands will be arrested in the shales immediately below the Alpine Sands. Pressure monitoring. The properties and thickness of the rocks underlying and overlying the proposed expanded pool render it unlikely that natural or induced fracturing/faulting would cause fluids to move out of the expanded pool. Additionally, casing pressures will continue to be monitored for all wells and available to the Commission. If out of zone injection occurs, it may lead to sustained casing pressure particularly in the outer annuli of the injection well with out of zone injection, or in offset wells. Consequently, sustained casing pressures exceeding 2000 psi for inner annuli and 1000 psi for the outer annuli will be reported to the Commission in accordance with the Commission's orders. Injection volumes will continue to be monitored by continuous metering at each injection well. Producing wells will be tested at least twice per month to monitor reservoir withdrawal. Injection rates will be set on the basis of voidage ratio accounting for reservoir withdrawal and injection to maintain reservoir pressure near original. Reservoir pressures will be monitored and reported per Rule 6 of the Alpine Pool Rules (CO 443A), including a minimum of six bottom-hole pressure surveys annually. Voidage management coupled with reservoir pressure monitoring will indicate whether out of zone injection is occurring. In addition, initial pressures will be measured in all future vveils, and pressures will also be measured in the existing completions as needed to effectively marage hydrocarbon r2coveny orocesses. Within the proposed AOP Area, there are presently 11 wells cok°~~pleted in the ~~;s.~aaruk C Sand, 106 wells completed in the Alpine Sands, and nu wills cr,~mpleted in both 6C~=~aruk and Alpine Sands. • • Pr®p®sa- f®r ~scpanded Alp-ra~ ®ii- P®®- AOP Expanded stratigraphic Definition. The AOP is currently defined as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths ("11AD") of 6,876 feet and 6,976 feet as seen in the Bergschrund No.1 Well (Attachment 4A). CPAI proposes amending the AOP to be defined as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths ("MD") of 6,980 feet and 7,276 feet in the Alpine No. 1 Well (API # 50-1 03-2021 1-00) (Attachment 4B). The proposed AOP interval includes the Alpine A, Alpine C, Kuparuk C, and Kuparuk D intervals. The Alpine No.1 well log is proposed as the type log in lieu of the Bergschrund No. 1 Well because the Alpine A sand is truncated (not present) in the Bergschrund No. 1 well but is present in the Alpine No. 1 well. Additionally, the Alpine No. 1 well has 5 feet of Kuparuk C sand represented in the log data whereas Bergschrund No. 1 well only has 2 feet of Kuparuk C, consequently it is difficult to determine representative logging tool response for the Kuparuk C sand with the Bergschrund No. 1 well log data due to logging tool resolution limitations and limited number of data points collected in the sandy interval. Additional Lands. The current AOP and Nanuq Kuparuk oil pool overlap aerially to a significant extent. In addition, wells planned to be drilled in the near future are planned to be located outside of the current AOP in the southwest corner (Attachment 5). The proposed AOP revision (At#achment 5) is intended to include both of the current Alpine and Nanuq Kuparuk oil pools, near-term future drilling locations, plus lands which CPAI and Anadarko Petroleum Company ("Anadarko") ultimately intend to develop. The proposed AOP, when expanded vertically as described above, also overlaps in the Kuparuk formation with the Nanuq Kuparuk oil pool. CPAI requests that the Commission amend the AOP to include the Nanuq Kuparuk oil pool. Alpine Conservation Order ("CO') and A/O Modifications. In addition CPAI requests that CO 443A be expanded to cover the revised AOP (see map and land description, Attachment 6) and be defined as encompassing the lands listed in Attachment 6. The rules stated in C0443A and AIO 18B would then also apply to the revised AOP lands and stratigraphic units. CPAI requests that the Commission terminate the Nanuq Kuparuk Conservation Order No. 563 and Nanuq Kuparuk Area Injection Order No. 27, so as not #o have two sets ofi rules for the same stratigraphic unit. To include the current Nanuq Kuparuk oil pool under Alpine CO 443A and Alpine AIO 18B as proposed requires consideration to insure that Alpine CO and Al0 rules are appropriate for Nanuq Kuparuk. A comparison of the Alpine and the Nanuq-Kuparuk conservation orders found the orders to be similar. CPAI believes that the existing Alpine pool rules wi#h proposed changes (Attachmenfi 7) will be appropriate to apply to the Nanuq Kuparuk and requests that the AOGCC approve the changes as shown in Attachment 7. It should be noted that by adopting 'the Alpine Al0 18B for the revised ADP, which would include the Nanuq Kuparuk, the more restrictive Rule 4 from Al0 27 currently in place for the nlanug Kuparuk would no longer apply to the Nanuq Kuparuk. CPAI does not believe that Rule 4 ofi A10 27 is necessary any longer based upon information gained since the Al0 27 was issued. Rule 4 of AIO 27 provides as follows: "Rule 4 Authorized 1=luids for 1=nhanced Recovery fluids authorized for injection are: a. source water from a sea water treatment plant; b. miscible gas obtained from the Alpine Central facility with thy; c~ .~6:.~ition that the rc:~~~ Moir ~:~:ssure must be maintained to ensure The miscibility of the irj«~~r~i:~~nt; ~ • c. tracer survey liquid to monitor reservoir performance; and d. small amounts of other non-hazardous liquids: sump liquid, hydrotest liquid, rinsate from washing mud hauling trucks, excess well work liquids, and treated camp waste water. Prior to injection of any liquid other than seawater or any mixture of liquids, compatibility wi#h the Nanuq-Kuparuk reservoir must be demonstrated and administrative approval to inject must be obtained from the Commission. Sampling, analysis and reporting protocols shall conform to those listed in AIO 188.002." Not including AIO 27 Rule 4 in the revised AIO 188 would allow CPAI to inject other fluids (including Colville River Unit produced water) in addition to the sea water, miscible gas, tracers, and miscellaneous liquids listed in the existing Nanuq Kuparuk AIO 27 Rule 4, above. The primary alternative fluid not listed in existing AIO 27 at Rule 4, but in use at the AOP, is Colville River Unit produced water. In support of this request to not restrict fluids allowed for injection under the proposed revised AIO 188, CPAI notes that the Kuparuk formation in the Nanuq Kuparuk oil pool is mineralogically similar to the Kuparuk composition in the Fiord oil pool; the main difference is the increased presence of siderite at Fiord (Attachment 8). CPAI has been injecting produced water into the Kuparuk formation in Fiord oil pool in accordance with AIO No. 30 and Administrative Approval No. AIO 30.002 without evidence of formation damage. Furthermore, there CPAI currently injects produced water into the Kuparuk (at Fiord), Alpine, Nechelik, and Qannik formations in the Colville River Unit, and has never seen any evidence of produced water incompatibility with these clastic rocks. Formation damage studies with core from the Qannik and Fiord pools have reinforced observations in the field that the formation is unlikely to be damaged from injection of produced water. Therefore CPAI concludes that all injected fluids allowable in Alpine AIO 186 are compatible with the Kuparuk and Alpine injection zones. CPAI believes the requested amendment approvals are based on sound engineering and geoscience principles, will increase ultimate field recovery, will not promote waste or jeopardize correlative rights, and will not result in an increased risk of fluid movement into freshwater. Please do not hesitate to contact me at (907) 265-6822 should you have any questions about this request. Sincerely, ris Wilson Supervisor, WNS Base • Attactaevaswt ~ a ~®~ CAY~Sa~as C st~asctaar~ ae~d Yost carc~aYatior~ ao~c~~9ea~c~s • Attachment 2: Seismic E-W transect near CD-°I with mappable faults stack W-E 'transect Attribute Extraction 11V-E CD1-14P61 • 8~ttachrv~ertt 3~ C®2-®~ t® C~Oar ~~ uverl seasrviic trarosect South CD2-43PB/ CD231P81 CD2-02 (Alp injector) CHAR North ~~ zg Attachment 4A: Current ASP type log - ~ergschrund 1 well ~,~~ BERGSCF~UND 1 TYPE LAG ~ l~ INE ° Resistivit ,:,,. Sonic - - ~ L - ~- saoo ~~ Torok ndstones =1 ~_ - _ _;~.-.-~ .~= - _ =i ~~ r ~0 ~.~- ~ ,p--- ~. Kuparu -; -~~ k Interval :~"~ ~, ` - .~_ '. Alpin e Sandstone K b l ~°° ~ ~ )~ ~.. - ~ro ~ Nuiqs Sandstone _~ ~,co C" 7d0 Nechel' k Sandstone s ` • ~~it@a~cllv~~~ir ~~~ (~~®~~~~~! ~~~ r7~~~ ~®~ - e~fl~ouw~ it ~+~89 Alpine 7 O O a O d .Q ~27s • UH.f]T DAS 5 t OH.RS t OH NPHIS CNTG S~ t . OH GR t OH.RD 1 ~H F-HOB 1 OHMM t0 K-1 ssso Ku aruk D p 7000 6 Ku aruk C p 7040 7060 7080 7,00 ~ 7,zo 7,ao 7,so Alpine C 7180 Alpine A 7zzo 7240 \ 7260 Kin ak E 7zao g .. ~--~~ Black line -Colville River Unit boundary Biue - ;4lpine oil pool boundary & wells Green - Nanuq Kuparuk oil pool boundary & wells Red -Planned well locations (2009-2012) • Attachment 5: Colville River Unit -Current Alpine and I`iord Kuparuk oil pool map witf-~ C®1, C®2, and C®4 well locations • ,~a~@~~Iroce~u~>m~ ~a L~w~ trav~~ ~~oc0 ¢B~~ea~ti®~o ®ff pta~~~s~a~ A~~cov~ ®~~ ~®®9 ~~epxauvusu®~¢ ~ --, .. c __ _. r ~...__.. .r __.__ _..-.. _ ~. ..._.._.. _. ~'. .. ---.- IA. .} ~~ J :~ :M;LEY Il f T 1 1 N i .. tfgy~ t '"• .-_... __.- R14 1_'.41 _ I Iil ._.. _ .~ WWW r~ `C - x.l „ II +9 I „u A:t . ~,, * g1Y1 2 Nr•r.[ 11,~~ 1~4. , - _ .I i _ Ai(:~yA .~': i~YC~ ••L°_SIY.~ ~ ~ ~(~7 `~~~ .., er <lx4 ;fa'n-.:. -.VAC ~iW r Asa ~ `~ +. .. `~ ;1~ ~~t r"1+ Y 'raft i T !mil , t ~y f J ~ ~•., I: i!J v_ ~[ r %'~ ~ sl td :Y-;.r .i I. ~ ~'I . I '1V {{ a~ !' 31 A )3 lC1 .• _ AI[~. I~+ i iV ':. H`l~ - ~ > Y ` ~ zy ~~ ~ ~7F. ~. L (6 t (q ~ ~ .. ,~ 1 `~ S ~ ! 1 1P£~ r3r t]SV ~ ~,. ~ ' 1~ ~ f'C7Y? 9rn+ ~_x~_._.~ : r ao~a ~ . 4 • ~ ~ 4L I ~'... i M_ .~ ~ t' _~ . Y 1 1 ~~ ~ ~~ 1'. l'1~ y,. '., I ' I ~ ^^ ~v~ (~?i, ~ I - tJ3 ^y"~{~ / !.~ .. . '. ~ ~ Lly ~ 1 +N_ ? G ~ ~~ / AVit V75 M+ AV f? QJR vfal' r, ~ M1a+C4 r xcw I ~ ~ ®o m n ca v o m ©e4 cs c c a s-f '~ w y. 'y 'LC c ie: ' _ I n - i - v \ ~ ..~ ,. - '^'' I , . . .w rev. r- waa rnx I R s+ ~+ ' - ~ ' n ' 14 at~' f ~ I ~" ~ ~ = l r fi Y PfOposed Ezpan~inn fa n ,,,,.{ n•( ~ .F ' (1 ~ .t~~ N ++ + fSlpine Pool & ASO ~. ,.. ~ ~f .t n Ta , q I~~ ~ ,;j~ + _ , - H a . i. arm rc r rtaa~~ik z\ • va~~ N Y "` ~ ~c~~~~:crE'~~r•~(i~s~ ` , \ <` h Alaska. -Inc. I :1 3.i 1 r t~-~ k ~ ] Y ~ ~ . . _ , - L VY•lY Y Y4J1{4.re7 hl6 WbL~ '- ~. ~ t ,a ~~ , I ~ ~,5t14'~t'6F~L ~Bef~B' ~~E~ ! LnK + ~_._ ~ 5 25~OS ~8061901A01 • • D~roposed ASR land description IJMIAT MERIDIAN Township /Range T10N, R5E Sections: 3, 4, 5, 6 T11N,R5E Sections: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 27, 28, 29, 30, 31, 32, 33, 34 T12N, R5E Sections: 13, 14, 15, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T10N, R4E Sections: 1, 2, 3, 4, 5, 6, T11N,R4E Sections: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N, R4E Sections: 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T10N, R3E Sections: 1 T11 N, R3E Sections: 1, 2, 11, 12, 13, 14, 23, 24, 25, 26, 36 T12N, R3E Sections: 25, 26, 35, 36 • • a~ttacliu~ruer~t "~~ Pr®~os~~9 ~~ras«~r~atii®ru ®~der° crud Aa°ea tro~ectii®~ O~~er Ctua~~es Conservation Order 443A Proposed Changes CO 443A Rule 2 (Pool Definition) Current: "The AOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,876 feet and 6,976 feet in the Bergschrund No. 1 well." Proposed: "The AOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6980 feet and 7276 feet in the Alpine No. 1 well." C0443A Rule 3 (Well Spacing) Current: "Development wells may not be completed within 500 lineal feet of another AOP development well nor closer than 500 feet from the exterior boundary of the affected area." Proposed: "Development wells may not be completed closer than 500 feet to an external property line where lease interest ownership or fee land ownership changes." Area infection Order 18B Proposed Changes AIO 188 Rule 1 (Authorized Injection Strata for Enhanced Recovery) Current: "Within the affected area, fluids maybe injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,876 and 6,976 feet in the Bergschrund No. 1 Well." Proposed: "Within the affec#ed area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6980 and 7276 feet in the Alpine No. 1 WeN." • ~ ~^ Attachment 8: Thin section point count data from Eiord #1 and Nanuq #1 wells. Kuparuk zone petrophysical summary Well Fiord #1 Fiord #1 Fiord #1 Fiord #1 Depth (core or log) 6907.53 6909 6909.8 6910.8 Nanuk #1 Nanuk #1 6975.0 6977.0 QUARTZ 56.7 51.0 50.0 52.7 56.3 63.9 FELDSPAR 0.0 0.0 0.0 0.0 0.3 0.7 CHERT 3.3 2.0 0.3 2.3 3.7 1.7 SRF 1.0 0.3 0.0 0.0 1.0 1.3 MRF 0.0 0.0 0.0 0.0 0.0 0.0 VRF 0.0 0.0 0.0 0.0 0.0 0.0 PRF 0.0 0.0 0.0 0.0 0.0 0.0 MICA 0.0 0.0 0.0 0.0 0.0 0.0 GLAUC 3.0 1.7 2.7 2.7 1.3 2.0 HVY MINERL 0.0 0.0 0.0 0.0 0.0 0.0 OTHER FRMWK 3.7 3.7 2.0 1.3 0.3 0.3 CLAY 11.0 6.3 6.0 18.3 6.3 6.0 SILICA CMT 0.0 0.0 0.7 0.0 2.0 1.0 FELD CMT 0.0 0.0 0.0 0.0 0.0 0.0 CARB CMT 4.3 34.0 34.0 19.7 6.0 0.0 OTHER CMT 0.0 0.0 0.0 0.0 0.0 0.0 TS_PORO 17.0 1.0 4.3 3.0 22.7 23.2 TOTAL 100.0 100.0 100.0 100.0 100.0 100.0
