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O 112
OTHER ORDER 112 Docket No. OTH-16-005 Great Moose's Tooth Unit Great Moose's Tooth 1 Pad North Slope Borough, Alaska 1. February 26, 2016 CPAI's request for approval of production measurement (Exhibits 1 B, 1 D, A, B, C, D and Executive Summary held confidential in secure storage) 2. April 1, 2016 Notice of public hearing, affidavit of publication, email distribution, mailings 3. May 3, 2016 Transcript, sign -in sheet, exhibits 4. June 1, 2016 Email: Additional Information Deadline Extension 5.-------------------- ASRC's Comments 6. June 2, 2016 CPAI's follow-up responses to May 3, 2016 hearing 7. October 31, 2016 CPAI's application for reconsideration 8. November 2, 2016 AOGCC's letter granting approval to file documents in support of reconsideration and approval for an extension of time to file supporting documentation and denial decision on reconsideration 9. November 21, 2016 CPAI's supporting document for application for reconsideration 10. December 1, 2016 AOGCC's Denial of Application for Reconsideration 11. January 10, 2017 Notice of Clarification ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7" Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Docket No. OTH 16-005 ConocoPhillips Alaska, Inc. for a waiver of ) Other Order No. 112 the requirements of 20 AAC 25.228(a) to ) Greater Moose's Tooth Unit provide custody transfer measurement of ) Greater Moose's Tooth 1 Pad hydrocarbons prior to severance from the ) North Slope Borough, Alaska lease or unit. ) October 12, 2016 IT APPEARING THAT: By a letter received February 26, 2016, ConocoPhillips Alaska, Inc. (CPAI) requests the following waivers to the requirements of 20 AAC 25.228(x) to provide custody transfer measurement of hydrocarbons associated with the planned development of the Greater Moose's Tooth (GMT) Unit; a. Utilize a coriolis-based metering system at GMT Pad 1 (GMTI) to allocate GMT Unit production to GMTI; production would be commingled with Colville River Unit (CRU) production and shipped to the Alpine Central Facilities (ACF) for processing to pipeline quality requirements and final sales measurement; b. Utilize a gas measurement system installed at GMTI instead of within CRU for gas transferred from the Colville River Unit (CRU) to GMTI. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for May 3, 2016. On March 31, 2016, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On April 6, 2016, the AOGCC mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. The hearing was held as scheduled on May 3, 2016. Testimony was received from CPAI. At the conclusion of the hearing the record was held open until June 3, 2016 so that CPAI could respond to questions and data requests made during the hearing. On June 1, 2016 the hearing deadline for CPAI to submit the additional information was extended to June 10, 2016. 4. On June 3, 2016, CPAI submitted written responses to the questions raised during the May 3, 2016 hearing. 5. On June 3, 2016, the Arctic Slope Regional Corporation (ASRC) submitted comments in support of CPAI's application. 6. On June 9, 2016, CPAI provided the AOGCC with access to a data room so that project economic data could be reviewed. Other Order 112 October 12, 2016 Page 2 of 4 FINDINGS: 1. CPAI is the operator of the GMTU and CRU located within the North Slope Borough, Alaska. Working interest owners (WIOs) of the GMTU are CPAI and Anadarko Petroleum Corp. (Anadarko). WIOs of the CRU are CPAI, Anadarko and Petro -Hunt, LLC. 2. The GMTU landowners are the United States Bureau of Land Management (BLM) and ASRC. The CRU landowners are Department of Natural Resources, BLM, and ASRC. 3. CPAI proposes to install a single stage three phase separator to support measurement of production leaving the GMT1 development. The oil leg coming off the three phase separator will be metered with a coriolis meter and water cut analyzer; the gas leg will be metered by a pair of orifice meters sized to measure the full range of expected flow. After metering the oil and gas flow streams will be recombined before being shipped to Colville Delta Pad 5 (CD5) and commingled with the CRU production gathering system. 4. The commingled GMTU and CRU production will be processed to pipeline sales quality specifications at the ACF and then metered at the CRU lease automatic custody transfer (LACT) sales meter before shipping to market. 5. CPAI proposes that the production allocation factor for GMT1 be fixed at 1.0. Thus the oil production allocated to the CRU would be the volume measured by the CRU LACT meter minus the volume measured through the Coriolis meter coming off the three phase separator at GMTI. 6. The dual orifice meters coming off the three phase separator at GMT 1 will serve as the gas sales meter for gas shipped from GMT1 to the CRU. 7. CPAI testifies that gas will need to be shipped to GMT1 from CRU for fuel and rich miscible gas injection. CPAI proposes to install orifice gas meters at GMT1 instead of within the CRU, stating operational and space constraints at CD5 are the basis of their request for the waiver of requirements to measure before severance of production from the property or unit where produced. 8. CPAI maintains that stand alone production facilities at GMTI would be necessary to process the production to pipeline sales quality before custody transfer quality metering could occur as required 20 AAC 25.228(a). 9. CPAI testified that a standalone processing facility at GMTI would cost in the neighborhood of $500 million. Using a 10 percent rate of return and the Alaska Department of Revenue's price forecasts, CPAI states this would make the project uneconomic. 10. CPAI provided the AOGCC access to a data room to review confidential project specific economics. The information made available to the AOGCC included a cost estimate prepared for CPAI by Turner & Townsend Larkspur (TTL), a company with extensive experience preparing conceptual project cost estimates for CPAI and other operators on the North Slope. TTL bases its estimates other costs estimates they've prepared and recently completed projects as bench marks when they prepare new cost estimates. 11. CPAI stated the recently commissioned CD5 drillsite was not designed to house a sales gas metering system for gas sales to GMT1 and would require modifications to incorporate one. 12. On April 21, 2016, CPAI announced it would fund additional wells and install additional on- pad infrastructure at CD5 to allow for expanded production from the pad'. ' http://alaska conocophillips cominewsroom/Documents/NR-AK-CD5%2OExi2ansion-Ani/202016 FINAL Vddf Other Order 112 October 12, 2016 Page 3 of 4 CONCLUSIONS: An exception to 20 AAC 25.228 is necessary to allow for final custody transfer quality metering of oil production from GMTI to occur after the production has been severed from the unit and commingled with production from the CRU before being processed at ACF and metered for sale at the CRU LACT meter. 2. An exception to 20 AAC 25.228(a) is necessary to allow the custody transfer measurement point for gas transferred from CRU to GMTI to be at a location after the gas has been severed from the CRU. CPAI's cost estimate was very thorough, including items such as timing of expenditures and contingencies for various components of the project. The estimate is sufficiently detailed to provide a valid basis upon which to assess the basis for CPAI's request. 4. The evidence presented demonstrates that a stand-alone production facility at GMTI in the current economic environment would not be pursued by CPAI. The reserves at GMTI would not be produced for the foreseeable future. 5. Failure to develop GMT1 would likely lead to a failure to develop the four GMTU other participating areas for the foreseeable future. 6. A waiver of the requirements of 20 AAC 25.228 that requires custody quality metering to occur before oil or gas is severed from a lease or unit is necessary in order to allow the maximization of recovery from GMTI. 7. Referring to the location of the CRU-to-GMT1 gas custody transfer meters, CPAI testified that a variance to the requirement to measure before severance from the property or unit where produced (i.e., CRU) would be simpler and cheaper. CPAI has not provided factual evidence in support of its assertions. 8. Assigning an allocation factor of 1.0 to the three phase separator and metering system at GMTI makes the assumption that the GMTI metering system is 100% accurate. Any error in that system would be applied to CRU production. This would result in one -unit over - reporting production while the other unit under -reports. Since the landownership of the two units is different this would result in landowners being over or under paid for royalties for production from their lands. Of the landowners only the ASRC has commented on the record in support of or opposing the proposed meter allocation factor for GMTI. 9. There is insufficient information available at this time to demonstrate that the mineral rights owners of the two units fully understand the implications of assigning a fixed allocation factor to one unit while the other unit has a floating allocation factor and thus the AOGCC needs to gather more information before a decision on the GMTI allocation factor can be made. 10. Additional information on the specifics of the meter system design is necessary before those components can be approved. NOW THEREFORE IT IS ORDERED: 1. CPAI's request for a waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from the GMTI to be based on a metering system that does not meet custody transfer quality standards is hereby APPROVED. Other Order 112 October 12, 2016 Page 4 of 4 2. CPAI's request for a waiver of the requirements of 20 AAC 25.228(a) to allow for the custody transfer metering of gas sold from CRU to GMTI at a point after the gas is severed from the CRU is hereby DENIED without prejudice to CPAI renewing the request when it can provide additional evidence in support of the request. 3. The specific design of the fiscal allocation metering system must be approved by the AOGCC before being installed and operated. The specific design for the gas measurement system to measure gas sold from the CRU to GMTI must be approved by the AOGCC before being installed. Refer to AOGCC Industry Guidance Bulletin 13-002 for details regarding the measurement application(s). DONE at Anchorage, Alaska and dated October 12, 2016. Cathy . Foerster Chair, Commissioner oe,<" Daniel T. Seamount, Jr. Commissioner AND APPEAL 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 AOGCC grants for good cause shown, a person affected by it may file with the AOGCC 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 AOGCC 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 AOGCC denies reconsideration, upon denial, this order or decision mid 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 AOGCC snails, OR 30 days if the AOGCC 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 AOGCC 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 AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(6), " [llhe questions reviewed on appeal are limited to the questions presented to the AOGCC 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 nm is not included in the period; the last day of the period is included, unless it falls on a weekend or stale holiday, in which event the period runs until 5:00 p.m. on the next day Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, October 12, 2016 9:19 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hyun, James J (DNR); Jacki Rose; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv, Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Delbridge, Rena E (LAS); Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: Other Order 112 Attachments: other112.pdf Please see attached. Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for a waiver of the requirements of 20 AAC 25.228(a) to provide custody transfer measurement of hydrocarbons prior to severance from the lease or unit. Jody J. Cotomhie AOyCC SpeciaCAssistant ACaska Oifand yas Conservation Commission 333 West y'' Avenue Anchorage, Alaska .995o1 office: (907) 793-1221 fax: (907) 2767542 Docket No. 0TH 16-005 Other Order No. 112 Greater Moose's Tooth Unit Greater Moose's Tooth 1Pad North Slope Borough, Alaska CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@aloska.aov. Bernie Karl Jack BoxHak1 a90083 K&K Recycling Inc. Gordon Severson P.O. Box 1P.O. Box 58055 3201 , A r Cir. Anchorage, AK 99519 Fairbanks, AK 99711 Anchorage, AK 99508-4336 Penny Vadla George Vaught, Jr. Darwin Waldsmith 399 W. Riverview Ave. P.O. Box 13557 P.O. Box 39309 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Ninilchik, AK 99639 Richard Wagner Misty Alexa Stephen Thatcher P.O. Box 60868 ConocoPhillips Alaska, Inc, ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 P.O. Box 100360 P.O. Box 100360 Anchorage, AK 99510 Anchorage, AK 99510 rll2i��c� \'2- W-- 2 20110 W--' INDEXES 11 hill' s ConocoP i p January 10, 2017 Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 JAN 10 2017 Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.263.4653 RE: GMTU and CRU Measurement Application Docket Number OTH-16-025; Other Order Nos. 112 and 112A Notice of Clarification Dear Commissioner Foerster: ConocoPhillips Alaska, Inc. (CPAI), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owners, submits this notice of clarification regarding both the Commission's December 1, 2016 letter denying reconsideration of Other Order No. 112, and Other Order 112A dated December 22, 2016. We submit this notice of clarification for the record due to our concern that misinterpretations or disagreements may arise from certain language used in the letter and Other Order 112A. In the letter denying reconsideration and in Other Order 112A, the word "sold" appears several times with respect to the gas going from the CRU to the GMTU. Use of the word "sold" clearly implies that gas from the CRU will be sold to the GMTU. Contrary that language, gas produced at GMTU and sent to CRU for processing will be returned to GMTU for use and injection without any sale. The terms "sold" and "sale" have significant meaning for fiscal purposes (e.g., tax and royalty) and CPAI's materials submitted in support of the application did not intend, provide or describe that gas sales would occur. The efficiencies of aligned ownership interests and inter -unit facility sharing are making GMT1 development possible by making it economically viable. Our application materials did not describe a gas sale, and introduction of the term "sold" may create significant confusion and result in complications with other agencies. CPAI wishes to correct any such confusion and avoid unnecessary complications therefore we submit this notice to clarify for the record that we have not proposed and do not intend that gas returned to the GMTU will have been sold anywhere in the process. If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Viator Project Integration Manager - Greater Mooses Tooth Unit ConocoPhillips Alaska 10 THE STATE FIA FIA�I GOVERNOR BILL WALKER December 1, 2016 Mr. Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Alaska Oil and Gas Conservation Commission Re: Greater Mooses Tooth Unit Off -Lease Measurement Application Application for Reconsideration Docket Number Oth-16-005; Other Order No. 112 Dear Mr. Viator: 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax 907.276.7542 www.00gcc.olaska.gov On November 2, 2016, the Alaska Oil and Gas Conservation Commission (AOGCC) granted ConocoPhillips Alaska, Inc.'s (CPAI) request to allow additional time to submit information in support of its application for reconsideration of the portion of Other Order No. 112 that denied CPAI's request to meter gas sold from the Colville River Unit (CRU) to the Greater Mooses Tooth Unit (GMTU) after the gas has been severed from the CRU. CPAI submitted this additional information on November 21, 2016. The AOGCC has reviewed the information provided by CPAI. Although installing the gas measurement system in the CRU instead of the GMTU may be more complicated and expensive, CPAI has not demonstrated that installing the gas measurement system in the CRU is impossible and thus would lead to cancellation of the Greater Mooses Tooth 1 development. CPAI's request for reconsideration to allow for off lease metering of gas sold from the CRU to the GMTU is DENIED. Sincerely, // P�fl-wi�F-'~-� CaFoerster Chair, Commissioner RI ConocoPhillips November 21, 2016 Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7'h Avenue Anchorage, AK 99501 Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.263.4653 RE: Greater Mooses Tooth Unit Off -Lease Measurement Application Application for Reconsideration Docket Number OTH-16-005; Other Order No. 112 Dear Commissioner Foerster: RECEIVED NOV 21 2016 ConocoPhillips Alaska, Inc. (CPAI), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owners, provides the enclosed attachment in support of CPAI's request for reconsideration of a portion of Other Order No. 112. In Order No. 112, the Commission denied CPAI's request for approval to install a CRU gas meter on the GMT1 pad. Following CPAI's appeal for reconsideration of that ruling, the Commission granted CPAI the opportunity to provide more documentation. CPAI is providing the attached document, GMT1 Measurement Application — Supplemental Support, as additional information that supports our original application. If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Viator Project Integration Manager- Greater Mooses Tooth Unit ConocoPhillips Alaska Attachment 1. GMT1 Measurement Application - Supplemental Support Conoc Phillips oma: 'aS �k r\\so�s�col/srat�on 0'r GMT!, Measurement sues Additional support details for COPA's request for AOGCC approval of Off -Lease Gas Measurement at GMTU November 21, 2016 J!. ® In Order No. 112, the Commission denied CPAI's request for approval to install gas measurement equipment on the GMTU pad. o CPAI submitted an appeal for reconsideration to clarify the significance of CD5 infrastructure additions on October 31, 2016. The AOGCC approved CPAI's request for reconsideration and a 20 -day extension to provide additional details. o The information on the following slides is provided as additional detail to support CPAI's request for approval to measure gas off -lease at GMT1. o The material contained in these slides will provide further detail on: • Current GMT1 design that is the basis for CPAI's requested approval • Technical reasoning that supports the current GMT1 design • CD5 Extension scope of work • Similar arrangement already approved between other North Slope units ConocoPhillips ® The GMT1 design provides for minimized gravel footprint and disruption to existing operations • GMT1 oil and gas production are measured at GMT1 after passing through a 3-phase production separator and then sent to the Alpine Central Facility (ACF) within the CRU via pipeline o After processing at the ACF, a portion of GMT1's gas is returned to GMT1 via two gas pipelines (Miscible Injection and Lift / Fuel gas) and measured upon arrival at GMT1. o Maintenance of the proposed gas meters is discussed within Attachment 2 of CPAI's measurement application ConocoPhillips ® Gas Metering (GMT1 vs CD5 pad): o Gas meters are constructed to API/AGA standards and local regulations Flow computer calculation of volume, mass, gravity, and composition will be in accordance with ANSI/API/AGA and local regulations o Gas samples will be taken in accordance with GPA/API standards and local regulations • Reporting to AOGCC will be per normal state regulations Gas measurement accuracy and uncertainty at GMT1 are equal to what they would be if measurement was located at CD5 (i.e. there is no change to the actual measurement value between these two locations) o Dedicated pipelines from CD5 to GMT1 do not distribute gas to any other locations o The amount of gas leaving CD5 will be the same amount arriving at GMT1 Measurement at GMT1 avoids added complexity with an installation at CD5 • New metering module required for measurement at CD5 ® Additional gravel due to code spacing issues is required for measurement at CD5 Uncertainty around ability or timing to get permit amendment for extra gravel at CD5 o Additional brownfield (near a live facility) installation scope increases execution risk Costs are minimized with measurement installation at GMT1 o Precedent at other North Slope units with similar measurement arrangement ConocoPhillips Meters installed at GMT1 to measure gas coming from the CRU via CD5 — — — — — — — — — — — — — — — — — — — — — — — •�� E I *CDS Wells I CDs Emergency Shutdown Valve I *CD5 Wells< 1 X, - - Pressure CDs Emergency I Control Shutdown Valve CDS Valve Production Heater Fuel Gas Pressure Meter Control Valve ---- ---------------J Miscible Lift/Fuel Injection Gas Pipeline Pipeline • Miscible Injection Gas and Lift / Fuel Gas are supplied to the CRU drillsites and GMT1 from the ACF via pipeline ConocoPhillips cmT1 C7 GMT1's scope will install • • • I Wells pipeline tie-ins at CD5 to the Miscible GMT1 Emergency Injection Shutdown Valve I existing MI and Lift/ Fuel I Meter I Gas pipelines, as well as th— GMM `� I C — - -- h4`— -� Wells two gas pipelines to GMT1 Lift Gas Pressure Lift 1 Fuel GMTL Emergency Meter Control Gas Shutdown Valve I There are no offtake points GMT1 Valve Meter I between CD5 pipeline tie-ins Production. Heater and GMT1 measurement Fuel Gas Pressure I Meter control I Valve I ACF—Alpine Central Facility L ---- ------------ ----------J CRU — Colville River Unit CD5 — Colville Delta 5 (drill site) GMT — Greater Mooses Tooth ConocoPhillips Installing gas meters at CD5 does not eliminate the need for the GMT1 metering module. There are other metering needs at GMT1 that require this module (fuel gas conditioning equipment, fuel gas meter and lift gas meter). ® Installing the CRU gas meters in an existing GMT1 module is a design optimization ConocoPhillips • Current GMT1 Tie -In Scope at CD5 is denoted by the colored items • Pipeline tie-ins • Piping • Valves • Access platform • No additional gravel required • Minimal impact to existing operations • Minimized cost GMT1 Tie-ins at CD5 ConocoPhillips • CPAI's CD5 Extension ("CD5X") project adds 12 new drilling slots that bring the total number of slots to 33 wells on CD5, which is full design capacity that the original design and permit approvals were based on. • This extension project does not require any new gravel. • The CD5X scope includes four (4) new pipe racks with each consisting of 3 well slots per rack for a total of 12 well slots o The scope also includes minor infrastructure upgrades within existing electrical and chemical injection modules • The CD5X project is at a different location on the drillsite where it isn't feasible to tie-in gas metering ConocoF hIllips CD5 Drillsite Layout & CD5 Extension Scop rl `e] CD5 Drillsite • The proposed GMT1 design is similar to the arrangement that has been approved by the AOGCC between CPAI's facilities at the Kuparuk River Unit (KRU) and Pioneer's (now Caelus) facilities at the Oooguruk Unit (OU) The following diagram is from slides presented during an AOGCC hearing in May 2008 showing gas measurement occurring on the downstream end of the pipeline from the KRU facilities (processed gas from CPAI being sent to Caelus) Description of Oooguruk - KRU Process J Fuel Injection and Lift G4 0o .rukPonds ODS Process Fuel Relnm Water M Rctnm Gas hR[? Lasses aroaucuan S�epermo Facilities Losse Lasses OTP M M KTC rn� C �J PIONEERN 10 Processed gas from KRU being sent to Caelus, measured at Caelus' operated facility ConocoPhillips o Installing gas measurement facilities at the CD5 drillsite would require the following incremental changes to the current GMT1 project Additional gravel footprint at CD5 (0.3 — 0.4 acres) Additional metering module (20 ft x 65 ft) Additional man-hours for engineering, fabrication and installation o These incremental changes will add approximately $10 million to the GMT1 project cost o The additional scope described above would increase the risk of GMT1 start-up delay Conoco`P fl ips Estimated 0.3-0.4 acres of new gravel New Metering Module (20 ft x 65 ft) • Fire Suppression System • i , . n ----------------------- * Full HVAC Miscible Lift I Fuel Injection Gas Pipeline Pipeline Miscible • Injection CDS Wells �"><'f 1 Litt I Fuel Gas CD5 Emergency Meter New Gravel at Shutdown Valve cos i I *CD5 Wells Pressure CD5 Emergency Control Shutdown Valve Valve CD5 Production. Heater Fuel Gas Pressure Meter Control Valve L----------------------- -------------------- — — — — —- GMTV X I Wells � I GMT1 Emergency Shutdown Valve I GMT1 V'V X I Wells Lift Gas Pressure GMT1 Emergency Meter Control Shutdown Valve GMT1 Valve Production ----I Heater I Fuel Gas Pressure Meter Control L -------- Valve ----------------------J Miscible Lift I Fuel Injection Gas Pipeline Pipeline New gas metering module on gravel expansion at CD5 pad, within the CRU (Note: pad size not to scale) ConocoPhillips Miscible �. Injection Meter 1 Litt I Fuel Gas Meter New Gravel at cos New gas metering module on gravel expansion at CD5 pad, within the CRU (Note: pad size not to scale) ConocoPhillips New module installed adjacent to current N''I GMT1 pipelines and valve tie-ins at CD5 Insufficient space in existing modules for gas metering and branch connections for Miscible Injection (MI) and Gas Injection (GI) lines are upstream of the CD5 modules at the pad edge Gravel pad expansion is anticipated to accommodate a new metering module 0.3-0.4 acres of gravel estimated Code -driven separation distance of 40 feet from Switchgear and Pigging modules ConocoPhillips © The proposed metering at GMT1 is equal in accuracy to a meter installation at CD5 measuring the same gas volume • The proposed metering arrangement for GMT1 is similar to the metering arrangement between CPAI (KRU) and Caelus (OU) ® The current GMT1 design requires less gravel footprint and thus imposes less impact to the environment o The current GMT1 design eliminates the need for another module and simplifies the brownfield work required at the CD5 drill site • The current GMT1 design is a lower cost option for gas measurement, given gas metering is already needed at GMT1 and has a module capable of accommodating these meters • A change to the GMT1 scope would result in cost increases and potential schedule impacts to the GMT1 project ConocoPhillips THE STATE GOVERNOR BILL WALKER November 2, 2016 Mr. Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Alaska Oil and Cas Conservation Commission Re: Greater Mooses Tooth Unit Off -Lease Measurement Application Application for Reconsideration Docket Number Oth-16-005; Other Order No. 112 Dear Mr. Viator: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 W W W.00gcc.alaska.gcv The Alaska Oil and Gas Conservation Commission (AOGCC) has received ConocoPhillips Alaska, Inc.'s (CPAI) October 31, 2016 Application for Reconsideration of the portion of Other Order No. 112 that DENIED CPAI's request to meter gas sold from the Colville River Unit (CRU) to the Greater Mooses Tooth Unit after the gas has been severed from the CRU. CPAI also requests an extension of time until November 21, 2016 to present new information it believes to be relevant to its reconsideration request. The AOGCC hereby grants CPAI's request for reconsideration and its request for an extension of time until November 21, 2016 to provide additional information. If you have any questions on this matter, please contact Mr. Dave Roby at dave.robv(a),alaska.eov or (907)793-1232. Sincerely, P��74—� Cathy . Foerster Chair, Commissioner ConocoPhillips October 31, 2016 RECEIVED Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 OCT 3 12016 AOGOO Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.263.4653 RE: Greater Mooses Tooth Unit Off -Lease Measurement Application Application for Reconsideration Docket Number OTH-16-005; Other Order No. 112 Dear Commissioner Foerster: ConocoPhillips Alaska, Inc. (CPAI), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owners, applies to the Commission for reconsideration of a portion of Other Order No. 112. In Order No. 112, the Commission denied CPAI's request for approval to install a CRU gas meter on the GMTU pad. The Commissioner denied CPAI's request without prejudice to renew the request. CPAI believes the Commission may have misunderstood the nature and significance of the post -hearing public announcement about CDS infrastructure additions, and wishes to present additional information that supports our request and explains the nature of the announced CD5 infrastructure expansion. In short, the CD5 expansion will add new drilling slots over and above the initial CD5 development, but these expansion slots were part of the original design and permit approvals and do not involve the addition of new gravel. That additional infrastructure does not impact the restrictions, complications, and costs that would be associated with putting a gas meter on the upstream end of a CD5 — GMT1 gas line instead of on the downstream side, where the meter can be incorporated into the original infrastructure design and construction on the GMT1 development site. Rather than requiring a new application and hearing on an issue that is already before the Commission in the proper context on the existing docket, CPAI asks the Commission to exercise its discretion to take this matter up on reconsideration. The CD5 announcement caused an unforeseen complication and, possibly, a misunderstanding. CPAI seeks permission to present new information in support of the request to clarify the post -hearing announcement, and we request an additional 20 days so that we can submit materials to the AOGCC by November 21, 2016. If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Viator Project Integration Manager - Greater Mooses Tooth Unit ConocoPhillips Alaska 11 RECEIVED ConocoPhillips June 2, 2016 Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7t" Avenue Anchorage, AK 99501 JUN 0 2 2016 AOGCC RE: Greater Mooses Tooth Unit Measurement Application Follow -Up Responses to May 3, 2016 Hearing Docket Number OTH-16-005 Dear Commissioner Foerster: Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.263.4653 ConocoPhillips Alaska, Inc. (CPAI), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owners presents the information in this letter and its attachment to address questions posed by the Commissioners at the May 3, 2016 hearing on GMTU and CRU measurement (Docket Number 0TH -16-005). CPA[ would first like to clarify for the Commissioners that we have cast our application as a request for an order under AS 31.05.030(c) and 20 AAC 25.505, which do not require an "equal or better" standard. CPAI strongly believes that our proposed measurement system provides a level of accuracy in standard volume units that could be substantially improved upon only by measurement and conversion to standard volume downstream of full processing facilities, which is cost prohibitive. CPAI would also like to address one of the statements made during the hearing on the need to prove equal or better accuracy variance for Coriolis meters. The regulation on custody transfer measurement, 20 AAC 25.228, does not directly require a particular type of meter or an accuracy standard. Instead, the regulation adopts by reference the 1998 version of the API Manual of Petroleum Measurement Standards (MPMS), which addresses Coriolis meters for allocation metering in Chapter 20.1, but does not address Coriolis meters for custody transfer or LACT metering service. In LACT measurement (stable fluids) service, Coriolis meters do provide equal to or better measurement accuracy when compared to turbine or positive displacement meters. As was described during the hearing, the main element of measurement uncertainty in the system we have proposed — which we believe overall to be a robust and accurate system — comes not from use of the Coriolis meter, but from the conversion of measured volumes to standard volumes for live fluids through the application of a shrinkage factor. Coriolis technology has been proven within the industry, as is evident by API's adoption of Chapter 5.6 in 2002 addressing Coriolis meters for custody transfer. While the AOGCC regulations have not been updated to adopt by reference post -1998 versions of the MPMS, the AOGCC can take note of the industry acceptance of Coriolis meters in liquid hydrocarbon service for custody transfer. Attachment 1 included with this letter covers the non -confidential questions raised by the Commission. Additionally, we plan to meet with AOGCC staff to provide additional confidential economic information to address the Commissioners' request for more detail on the economic rationale underlying our request. CPAI will provide the more detailed information in reliance on the AOGGC's assurance that the information will be held confidential under AS 31.05.035, 20 AAC 25.537 and other applicable law. If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Viator Project Integration Manager - Greater Mooses Tooth Unit ConocoPhillips Alaska Attachment 1. GMT1 AOGCC Hearing Follow -Up Responses a. Well test flow rate uncertainty estimate b. Improving proof test WP c. NSFMW 2014 Attachment 1 GMT1 AOGCC Hearing Follow -Up Responses The following information is based on questions raised by the AOGCC Commissioners during the May 3, 2016 hearing on ConocoPhillips Alaska, Inc.'s measurement application for the GMT1 development. Question 1: What is the expected API gravity for GMT1 oil? Answer: 430 Question 2: What is the expected GOR for GMT1 production? Answer: 1,385 scf/stb Question 3: What is the uncertainty value associated with the Colville River Unit (CRU) measurement? Answer: Since bringing the CD5 project online in late October 2015, the CRU uncertainty has a mean allocation factor of 0.99 with P10 and P90 ranges of 0.97 and 1.01, respectively. The median value over this time period is 0.99. Since November 2000, the CRU uncertainty has a mean allocation factor of 1.01 with P10 and P90 ranges of 0.95 to 1.08, respectively. The median value over this time period is 0.99. The following document provides uncertainty calculations for the CRU well test and allocation meters, which applies to all drillsites in CRU. r] Well Test Flow Rate Uncertainty Estimate Question 4: Can ConocoPhillips provide a summary of the history and considerations for not combining the Greater Mooses Tooth and Colville River Units into one large unit? If CPAI were to combine the units, would it remove the need for an AOGCC variance? Answer: The CRU was approved in 1998 by the State of Alaska (State) and the Arctic Slope Regional Corporation (ASRC). The CRU is comprised primarily of lands owned by the State and ASRC. Regular production from the CRU began in 2000. The Greater Mooses Tooth Unit (GMTU) was approved in 2008 by the Bureau of Land Management (BLM), and is comprised mostly of lands owned by the United States and administered by BLM. GMTU is not yet producing oil and gas on a sustained basis. The oil pools defined and approved by the AOGCC in connection with the CRU do not cover lands within the GMTU. Given the distinctions between the two existing units -- including their different history, land ownership, unit administrators, and regulatory regimes -- it is natural that they would be separate units. Additionally, each unit has been separately established, and attempting to combine the units at this late date, would be exceedingly difficult, if not impossible. The contractual obligations established by the two different unit agreements reflect the specific intentions and requirements of the State, ASRC, and BLM. Reaching alignment between the federal and state requirements could require various concessions that would be very difficult to obtain and could have significant impacts on existing infrastructure. In addition, the restructuring of these two large units into one unit would be time consuming, would present high chance of failure based on regulatory obstacles, would divert focus away from current major development projects, and would have a high manpower cost impact to the operator, other working interest owners, landowners, and regulatory agencies — all costs and impacts that are unnecessary to impose here. While it is theoretically possible that the units could be combined into one very large, diverse unit, CPAI is not aware of any precedent for such a combination. The question of whether combination of the units would remove the need for a variance from 20 AAC 25.228 presumes that a variance is required under present circumstances. As noted in the cover letter, CPAI has not asked for a variance, rather we have cast our application for an order under AS 31.05.030(c) and 20 AAC 25.505 instead, in part to avoid confusion about whether the "equal or better' standard for a variance under 20 AAC 25.228(j) applies. In our view, no variance is necessary because whether a "variance" is needed depends on whether the proposed system' complies with the 1998 version of the API Manual of Petroleum Measurement Standards (MPMS), which is ' To be clear, the system proposed by CPA[ is for on -unit (GMTU) measurement using an industry -accepted meter type, but at elevated temperature and pressure, upstream of processing facilities. The key question, in our view, is whether conversion of the metered volume to standard volume using a shrinkage factor is deemed acceptable to the AOGCC. CPAI submits that it should be acceptable because it provides for accurate measurement — indeed, the most accurate level that could reasonably be obtained at GMTU — even though it does not provide a level of accuracy that is equal to or better than converting metered volume to standard volume using a volume correction factor that would apply downstream of processing facilities. adopted by reference in 20 AAC 25.228(a). We acknowledge some uncertainty on this point, however, because the 1998 version of MPMS addresses Coriolis meters only as allocation meters, not as custody transfer meters. If a variance were necessary, combination of units could avoid the need for a variance because in that case AOGCC may deem the GMT1 meter to be an allocation meter that is referenced to the combined unit's LACT meter, which clearly complies with the 1998 MPMS. Note, however, that BLM's position has been that the GMT1 meter must be the sole determination of GMT1 volumes, without any adjustments, so even if the units were hypothetically combined and the Coriolis meter was deemed to be an acceptable allocation meter, the actual measurement system would be no different than the system currently proposed. Comment 5: The commission may request or require 3`d party review and sign -off on Shrinkage Factor matrix to ensure no CPA[ bias. Response: CPAI is proposing the following protocol that can later be translated into a documented procedure to ensure no CPAI bias with the Shrinkage Factor matrix: The Shrinkage Factor matrix will be updated as oil composition and/or operational conditions warrant. The matrix will be verified and amended by CPAI based on the following: • Operating pressure is outside of matrix range • Operating temperature is outside of matrix range • Dry oil density deviates by more than 10% from the process simulator conditions. Compositional sample analysis will be triggered by the following: • New production well brought online • Monthly composite samples show a dry oil density change of greater than 10% • Once per year during annual Preventative Maintenance (PM) Following receipt of a compositional analysis and update of the Shrinkage Factor matrix (if required), the new Shrinkage Factor matrix will be reviewed with an independent 3`d party, whom will be given access to both the HYSYS model and historical sampling results to verify that there is no CPAI bias with the matrix. Question 6: Can ConocoPhillips provide more detail on smart meter diagnostics technology? Answer: The following video link provides a high level overview of how MicroMotion Smart Meter Verification (SMV) works to identify potential measurement issues in a Coriolis meter. (https://www.youtube.com/watch?v=DKINaUrcki8) Additionally, the attached MicroMotion white paper titled "Allow Smart Meter Verification to Reduce your Proving and Proof -Test Costs" describes how the SMV technology provides robust in-situ verification of Coriolis performance. l Improving -Proof -Te st-W P-001540. pdf The gas orifice meter advanced DP Diagnostic system was developed in a coordinated effort with Swinton Technology, headquartered in the United Kingdom. The linked Swinton Technology Prognosis video provides a high level overview of how the jointly developed diagnostic application works. (https://www.youtube.com/watch?v=Y2ZSzSVe2cw) We have also provided a white paper presented at the North Sea Flow Measurement Workshop in October 2014 that provides additional details of the advanced DP meter diagnostics technology. rl NSFMW_2014.pdf Discussion 7: A question was raised by the Commissioners as to whether having oil in water and oil in gas analyses on the water and gas legs, respectively, is a prudent requirement or not. Response: CPAI would like to clarify some of the responses that were given during the hearing regarding oil in gas and oil in water measurement. Neither AOGCC regulations nor any governing industry standard require any particular approach or result. The approach proposed by CPA] is based on a system that is expected to separate oil and water to the extent that we are reasonably confident any carryover would be minimal and not require additional measurement. However, CPAI is prepared to take additional steps to address any potential AOGCC concerns. Liquid in Water Stream The production separator vessel is specified to produce a water outlet with less than 0.1% oil in water and currently includes a nucleonic level measurement device that will detect and control the oil -water interface in the vessel, further minimizing any potential oil leaving with the water stream. CPAI does not anticipate any significant amounts of oil in the water stream, but if measurement of oil content in the water stream is requested by AOGCC, we propose the following alternative water measurement technology compared to what was discussed during the hearing. Rather than include an oil -in -water analyzer with the previously proposed magnetic flowmeter, CPAI would propose installing a Coriolis flow meter on the water outlet of the production separator. This would allow the Operator to monitor changes in density that would indicate potential separation issues and oil in the water outlet. Additionally, CPAI would propose the addition of a spot sampling quill on the water outlet for any necessary sampling and analysis of the production separator water outlet stream. Liquid in Gas Stream For potential liquid carryover in the gas stream, the production separator vessel is being specified for less than 1 gallon of liquid carryover per MMSCF of gas. The DP Diagnostic system on the gas orifice meters will detect and alarm on liquid carryover. Operator alarms on density changes in the gas outlet would trigger operation or maintenance corrective actions as necessary. Attachment l.a Well test flow rate uncertainty estimate Project: Colville River Unit Well Test Measurement Application Project number: WNY.161847 Document: Standard Volume Measurement Uncertainty Estimate Revision: 0 Client: Alaska BU Prepared: R Pe ales Flo,, Me�ent Engineer Signed: Date: 11th May 2016 ConocoPhillips Subject: Well Test Non -Continuous Oil Measurement Uncertainty Case: Measurement Uncertainty Case for Well Test Measurement System 1.0 Measurement Uncertainty Estimate for a Well TestAppllcation 2.0 Well Test Allocation Methodology and Uncertainty 2.1 Test Separator Measurement Uncertainty 22 KWPS Method Uncertainty 2.3 KWPS Well Rate Correction Matrix Uncertainty 2.4 Corrected Production Well Rate Using Flowing Tube Pressure and Gas Lift Rate 1.0 Measurement Uncertainty Estimate for a Well Test Application This high level model describes the estimated range of uncertainty associated with determining continuous Net Standard Volume flow for production wells in the Colville River Unit Production Areas (PA). This well test methodology utilizes a two phase test separator for periodic testing of wells to measure actual production flow rates. Well production rates, covering periods between well tests, are determined using production flow curves and supporting measurements from Gas Lift and flowing tube pressure instrumentation. 2.0 Well Test Allocation Methodology and Uncertainty The well test and allocation methodology is based upon the use of dedicated test separators which are used to perform periodic well tests on the individual wells of a PA. The well test data is then used in conjunction with additional live measurements to estimate actual flowing production rates between well tests to account for any well decline. The overall process is described below along with an estimate of the associated measurement uncertainty. 2.1 Test Separator Measurement Uncertainty Wells are tested twice per month for up to twelve hours duration using a two phase test separator. The major components of the test separator measurement system include Coriolis meters on the liquid and gas legs, a phase dynamics water cut meter on the liquid leg and pressure and temperature transmitters installed on the separator vessel. The performance of these instruments will determine the overall uncertainty of the raw well test data. Uncertainty estimates for each device have been provided below. FTS oil 2% Oil metering uncertainty FTS -G,, 2510 Gas metering uncertainty ETS Water 2% Water metering uncertainty 2.2 KWPS Method Uncertainty 0 TS -Pressure �` ° FPS_Temperature 0.25% Pressure uncertainty Temperature uncertainty The KWPS software is an in-house COP developed system based upon industry standard inflow performance and hydraulic models. It is used to develop well correction curves based upon well test data. The method uncertainty estimate provided for the KWPS inflow performance and hydraulic models is provided below. EKWPS:= 2% 2.3 KWPS Well Rate Correction Matrix Uncertainty The uncertainty assigned to the KWPS developed well rate correction tables is a combination of the well test measurement uncertainties and the method uncertainty associated with the inflow performance and hydraulic models applied. EMatrix:= ETS_Oil2 + ETS_Gas2 + ETS_Water2� E"I'S_Pressuree + Fr5 Temperature + EKWPS2 EMatrix = 4.016-% 2.4 Corrected Production Well Rate Usina Flowinu Tube Pressure and Gas Lift Rate The KWPS well rate correction matrix provides a means of determining the actual flowing well rates based upon well test data. The matrix is employed against two measured parameters, namely flowing tube pressure and gas lift rate, which then interpolate within the matrix to determine the flowing oil rate. In this instance the uncertainty of the measured flowing tube pressure and the gas lift rate will have an impact upon the overall corrected well flow rate. EFTP := 0.25% Uncertainty in Flowing Tube Pressure EGLRate 2% Uncertainty in Gas Lift Rate 2 2 EWell_Rate:= EMatrix + EFTP + EGLRate EWell Rale = 4.493-% Attachment 1.b Improving proof test WP BY TIMOTHY J. CUNNINGHAM and TOM O'BANION, MICRO MOTION, INC. Allow Smart Meter Verification to Reduce your Proving and pWW.micromotion.com Proof -Test Costs Abstract Industry and agencies are dedicated to ensuring fair and safe measurement in numerous applications such as fiscal transfer of gases and liquids, environmental compliance and safety systems. Annual or more frequent proving of flowmeters and other devices is common. Coriolis meters are widely known for their stability and linearity over time, suggesting that proving intervals might be extended, reducing proving and proof -test costs. Smart Meter Verification uses on -board diagnostics to measure the flowtube stiffness, which is directly related to the flow calibration factor. Each verification checks meter stiffness and compares it to a factory baseline. If the stiffness is unchanged, the calibration factor is correct and the meter will meet its mass flow accuracy specification. Smart Meter Verification confirms the accuracy of the measurement and the integrity of the meter providing a means to reduce cost by extending proving intervals. Smart Meter Verification can be performed under flowing conditions in-situ without requiring any special process conditions. Recent technology advances in Smart Meter Verification allow the stiffness to be measured without interrupting the meter's process measurements, allowing its use in custodytransfer and safety system applications. User data from Smart Meter Verification will be compared with proving data to illustrate the stability of Coriolis calibration and stiffness. Examples of the acceptance of Smart Meter Verification by agencies such as the Canadian ERCB, ISO, USA EPA, Safety Instrumented Systems (IEC SIS), and AGA will be presented along with work -practice changes. Introduction Coriolis flowmeters are becoming increasingly common in precision flow measurement. Their high accuracy gas and liquid mass flow measurement, along with precise liquid density (concentration, API gravity, etc.), and high turn- down capability makes Coriolis meters a good choice for precision flow. Additionally, Coriolis acceptance is being Micro Motion WP -001540, Rev. BI02013 Micro Motion, Inc. All rights reserved. driven by the long term stability of their Flow Calibration Factor (FCF), which is a consequence of their lack of moving or wearing parts. To assure fair and safe measurement; flowmeters are commonly proven or proof -tested at regular intervals. Proving or validation compares the indicated flow measurement to a reference flow measurement. Proof testing is used for Safety Instrumented Systems (SIS) to detect failures within the Flowmeter that are not detected by device diagnostics. Flowmeters are also commonly verified by tracking a secondary variable that is highly correlated to the flow measurement. For example, orifice plates can be measured to verify accuracy. Other verification techniques include spindown tests for turbine meters and speed of sound and transducer gain checks for ultrasonic meters. Micro Motion Coriolis meters offer Smart Meter Verification, a non -intrusive methodology to verify flow tube stiffness. The verification can be done under flowing conditions, in-situ, with no interruption to the process measurements. This flow tube verification complements the long-term stability and linearity associated with Coriolis flowmeters. Flow tubes stiffness can be shown to directly correlate to the flow calibration factor. Verifying that the stiffness is unchanged from the factory baseline confirms that the FCF is still correct. Stable verification results suggest that the proving intervals might be extended. In SIS, proof test frequency is determined by reliability calculations for the given safety loop. The proof test must be performed at least as frequently as specified in the calculation in order to maintain the required safety integrity of the Safety Instrumented Function (SIF). Because of its simplicity, robustness, and usefulness, Smart Meter Verification is being implemented by users as part of their standard work practices for troubleshooting, ISO9001, and EPA Greenhouse Gas compliance. Efforts towards acceptance of Smart Meter Verification by other regulatory agencies such as USA's NIST, API, AGA and MID are planned in orderto enable otherwork practice changes. EMERSON. FI(ofess I'V;oI I"t1t't11f,161 MICRO MOTION WHITE TAPER Coriolis Flowmeter Background Coriolis flowmeter stability Coriolis meter history shows that there is little variation in the FCF overtime. For example, reference Coriolis meters are used to verify the accuracy of manufacturer's calibration facilities. These meters are checked against a gravimetric standard on a regular basis. Reference meters which are 10+ years old still have the same calibration as the day they were built. Long-term Frc:ng Dal for 5 Coriolis Oc--icters ------------ Page 2 of S Equation (1): /71 — FCF * Jt Equation (1) can be derived from first principles, for example starting with the Housner differential equation describing a fluid -conveying beam [1, 21. However, a much simpler dimensional analysis of Equation (1) shows that the FCF has units of stiffness. Rearranging Equation (1) Equation (2): FCF — I77 x 't x $c , + — -----+ shows that the units of the FCF are mass flow rate/time delay. This is shown dimensionally as r r •, . < :Mass - — - - - - - --''. *---t me Equad'o 3:F — ....... !I Date • ronih`, ear Figure 1. Long-term Coriolis Proving Data Coriolis meters are commonly proved in the field by comparing the calculated volumetric flow from the Coriolis meter to the standard volume of a prover [2, 3]. Figure 1 shows a plot of the meter factor from six Coriolis meters used in cavern storage. These meters have been in use for as long as 13 years. The meter factors show random variation and some bias in the meter factor. However, the provings generate a meter factor that has a constant mean value over the lifetime of the meter. The proving data say that the meter factor has the same average value as when it left the factory. A conservative estimate of the cost of the 375 provings in Figure 1 is $200,000 (assuming —$500/proving). Provings may be required by regulation or standard procedures. But the data shows that these provings added nothing to the accuracy of the Coriolis flow measurement. Coriolis flowmeter calibration factor and stiffness Smart Meter Verification uses the stiffness of the flow tubes as the secondary variable to verify the correctness of the Flow Calibration Factor (FCF). The FCF is the proportionality constant that relates the time delay,St, to the mass flow rate, m. For example, FCF is commonly expressed in units of (gm/ sec)/µ sec. In a consistent system of units, mass can be represented by force/(acceleration), taking advantage of Newton's Second Law. Plugging this into equation (3) Equation (4) Mass i i Force Acceleration Time Time Time Time Force (Length Time')` l Time Force ...... — StiNness,.,m, Time Length shows very simply that the flow calibration factor has units of stiffness (Force/Length). The equivalence of FCF and stiffness shows why stiffness is the secondary variable that is highly correlated to the FCF. The problem now becomes one of how to determine the stiffness of the flow tubes. Meter verification theory Smart Meter Verification uses techniques from Experimental Modal Analysis and Structural Dynamics theory to very accurately measure the stiffness of the Flow tubes using the embedded electronics and onboard pickoff and drive coil and magnets. ALLOW SMART METER VERIFICATION TO REDUCE YOUR PROVING AND PROOF -TEST COSTS Figure 2 shows a typical Coriolis mass flowmeter. The drive coil and magnet at the top center in-between the tubes is used to drive the Coriolis flowmeter at resonance. A feedback control system in the Flowmeter electronics applies a sinusoidal current to the drive coil to maintain resonance at a specific amplitude. The two pickoff coils and magnets produce a voltage in response to the resonance motion. The pickoffs are used as the feedback signal to control amplitude. The transmitter's digital signal processing uses the pickoff responses to estimate the frequency of vibration, used in the density measurement, as well as the time delay between the two pickoff sinusoids, St, needed for the mass flow measurement. Further details discussing the operation of a Coriolis flowmeter are given in Reference [3]. Figure 2. Typical Coriolis Flowmeter Smart Meter Verification runs on top of the standard Coriolis signal processing and drive control. A series of tones are added to the drive signal. These tones excite off -resonance responses in the two pickoffs. The embedded Flowmeter electronics measures these tonal inputs and responses to produce a Frequency Response Function (FRF). Smart Meter Verification does not require any special process con- ditions and does not interrupt the process measurement. A structural dynamics FRF can be modeled as a second order system with the parameters of stiffness (K), mass (M), and damping (C). Applying electromagnetic theory to the prob- lem, the FRF can be defined by pickoff voltagelinput current. Equation (5): FRF — H ( r) ) — X (rd) j ro F(ro)—Mro`+jCro+K Page 3 of 8 Smart Meter Verification results are based on fitting the measured FRF to the second order model to independently estimate K, M, and C. Figure 3 shows this graphically. The lowerfrequency portion of the FRF is dominiated by the stiffness. The higher frequency portion is dominated by the mass. These mass and stiffness lines, as they are called, are shown in the plot. The lines are actuallythe reciprocal of the mass and stiffness, called flexibility and inertance. The resonant frequency is determined bythe square root of the ratio of mass and stiffness. The height of the resonant peak is determined bythe non -dimensional damping coefficient �, which is related to the damping, C, by Equation (6). 10; v 10` 0 Frequency Response Function 10° 10' Frequency (Hz) le Figure 3. Nominal Frequency Response Function (FRF) C Equation (6): S 2x1K The embedded core processor performs the signal processing necessary to generate the FRF; curve fits the FRF to generate estimates for K, M, and C; and handles all of the bookkeeping to keep track of the results generated by Smart Meter Verification. MICRO MOTION WHITE FHPER Results Smart Meter Verification distills all of its results down to two simple numbers that it presents to the customer. Smart Meter Verification starts with the factory baseline verifications during the standard meter calibration process, which Micro Motion performs as part of its comprehensive diagnostic program. Each Smart Meter Verification measurement is normalized by the average of these stiff nesses and converted into a stiffness uncertainty, which is the percentage change in the measured stiffness from the factory baselines. Equation (7): Stiffness Stiffness;,,.�,,,� – '"111�' 1 , SAffness ,,,,.,,— ,,,_ f Normalizing the stiffness uncertainty in this way makes it easy to track any changes in the flowmeter by using a format that is convenient to view. (This stiffness uncertainty should not be confused with the term measurement uncertainty as it is used in metrological terms.) Meter Verification Stability -35 40 45 50 55 60 65 70 Meta, verdke. Counter Figure 4. Smart Meter Verification Stability The signal processing used in Smart Meter Verification has been designed to enhance the stability of the measurement. Each stiffness uncertainty measurement is the average of the stiffness estimates from many FRFs. In turn, each FRF that is fit is averaged from many individual FRF measurements. This averaging results in a very stable stiffness uncertainty estimate. In-line with standard measurement techniques, the variation in Smart Meter Verification uncertainty is several times better than the base Flow accuracy. Figure 4 shows a typical Smart Meter Verification uncertainty plot with a standard deviation of less than 0.01 % under laboratory conditions. Note that stiffness uncertainty is calculated for each of the two pickoffs, further Page 4 of 8 increasing the confidence in the measurement. Smart Meter Verification uncertainty variation is of course subject to field effects. The specification limits for stiffness uncertainty are set such that under the full range of field effects there is a 3a probability against giving a false alarm. Smart Meter Verification, specification limits, and field effects are discussed more fully in References [4] and 151. Smart Meter Verification Results Using the onboard electronics and pickoff and drive transducers to measure the stiffness means that the stiffness verification not only verifies the flow tube stiffness, it also confirms the integrity of the transducers and wiring and the transmitter hardware and software. Structural Integrity Normalized SNfness 0 Krmwx. , 3 2 i z -35 40 45 50 55 60 65 70 Meta, verdke. Counter Figure 4. Smart Meter Verification Stability The signal processing used in Smart Meter Verification has been designed to enhance the stability of the measurement. Each stiffness uncertainty measurement is the average of the stiffness estimates from many FRFs. In turn, each FRF that is fit is averaged from many individual FRF measurements. This averaging results in a very stable stiffness uncertainty estimate. In-line with standard measurement techniques, the variation in Smart Meter Verification uncertainty is several times better than the base Flow accuracy. Figure 4 shows a typical Smart Meter Verification uncertainty plot with a standard deviation of less than 0.01 % under laboratory conditions. Note that stiffness uncertainty is calculated for each of the two pickoffs, further Page 4 of 8 increasing the confidence in the measurement. Smart Meter Verification uncertainty variation is of course subject to field effects. The specification limits for stiffness uncertainty are set such that under the full range of field effects there is a 3a probability against giving a false alarm. Smart Meter Verification, specification limits, and field effects are discussed more fully in References [4] and 151. Smart Meter Verification Results Using the onboard electronics and pickoff and drive transducers to measure the stiffness means that the stiffness verification not only verifies the flow tube stiffness, it also confirms the integrity of the transducers and wiring and the transmitter hardware and software. Structural Integrity Normalized SNfness Meterved(cation Counter Figure 5. Stiffness Verification Results Since the Coriolis meter is expected to be unchanging, the stiffness change is normalized and plotted. There is inherent variation in the stiffness measurement, but the mean value of the stiffness change will not change if the meter is measuring correctly. Figure 5 shows some typical Smart Meter Verification results, again from a cavern storage meter. Stiffness verification was run without controlling the process in any way. Flow rate, density, and temperature were varying considerably over the six-month time span of the data. The data shows some random variation, but the mean stiffness is unchanged. Smart Meter Verification software provided by the manufacturer maintains a record of the zero and calibration parameters and tracks any changes to them. The verification results are stored in a database and the results can be printed in a report. o K� K� 3 z a a o e ■ edlA °A G 61®l -z .3 0 10 20 30 40 50 60 70 Meterved(cation Counter Figure 5. Stiffness Verification Results Since the Coriolis meter is expected to be unchanging, the stiffness change is normalized and plotted. There is inherent variation in the stiffness measurement, but the mean value of the stiffness change will not change if the meter is measuring correctly. Figure 5 shows some typical Smart Meter Verification results, again from a cavern storage meter. Stiffness verification was run without controlling the process in any way. Flow rate, density, and temperature were varying considerably over the six-month time span of the data. The data shows some random variation, but the mean stiffness is unchanged. Smart Meter Verification software provided by the manufacturer maintains a record of the zero and calibration parameters and tracks any changes to them. The verification results are stored in a database and the results can be printed in a report. ALLOW CORIOLIS SMART METER VERIFICATION TO REDUCE YOUR PROVING AND Page S of 8 PROOF -TEST COSTS Discussion Smart Meter Verification measures stiffness to ensure the integrity of the sensing element, the flow tubes. Additionally the electronics associated with the flow measurement need to be verified. Smart Meter Verification confirms the integrity of the flowmeter electronics by verifying the stiffness with the same transducers, analog electronics, digital electronics, and software used for the flow measurement. Any change in the electronics will cause the stiffness uncertainty to go out of specification. Therefore good stiffness uncertainty confirms both the sensing element and the electronics. Smart Meter Verification is unlike flowmeter validation methodologies such as proving, in which the output of the unit being tested is compared to a primary flow output. Smart Meter Verifications require several additional checks to confirm overall flowmeter performance. These checks include confirming the software configuration, the flowmeter's zero, and the proper functioning of the analog outputs. A complete verification might include checking the analog output functionality with the built-in diagnostic trim functions. Smart Meter Verification includes a built-in check of the software configuration, comparing it to the previously verified values. Additionally, Smart Meter Verification checks the current zero against the factory zero and the last -verified zero. Smart Meter Verification also provides a graphical output of the results and the ability to print a report of the current verification [6]. All of these features combine to completely check the performance of the entire flowmeter. A diverse range of meter verification uses has evolved since 2006. The most common is device and process troubleshooting, reflecting Coriolis wide -spread use in process control. More recently, Smart Meter Verification has seen adoption in more regulated applications such as fiscal transfer, safety systems, and the like. The remainder of this paperwill discuss several specific application types and the longerterm vision for Smart Meter Verification. Agency Approvals A number of agencies or regulatory bodies have endorsed or recognized Smart Meter Verification. The technology is widely known for stability and linearity overtime, suggesting that proving or proof -test intervals might be extended. These work practice changes can save time and money, while simultaneously assuring fair and safe measurement. Numerous other agencies have expressed interest in learning more about Smart Meter Verification, and conducting tests to further establish the correlation to meter performance. Canadian ERCB The Energy Resources Conservation Board (ERCB) is an independent, quasi-judicial agency of the Government of Alberta. It regulates the safe, responsible, and efficient development of Alberta's energy resources: oil, natural gas, oil sands, coal, and pipelines. Sections 2.5.2.1 and 2.6 of ERCB's Directive 17 states, "Internal metering diagnostics may be used to determine if the primary measurement element is within acceptable operating parameters and checked at the same required intervals as an internal inspection. Then internal inspection is not required until an alarm or error is generated bythe device or as recommended by the manufacturer. The operator must maintain documentation on the diagnostic capability of the measurement system..." Directive 17 allows Smart Meter Verification to be used to extend proving intervals, which can result in significant cost savings. For example, without Smart Meter Verification a meter might typically be proved 12 times per year. With Smart Meter Verification the proving interval can be extended until the verification triggers an alarm. Since Coriolis meters are not expected to change, that means that a verification alarm will most likely never be triggered. However, proving a Coriolis meter at the initial installation and thereafter on an annual basis would be a good conservative recommendation. Costs for a typical prove might be $200 plus technician time and mileage. A bill of $500 per prove would not be uncommon. With Smart Meter Verification, the total cost savings for the 11 proves obviated by meter verification would be $5,500] year. 1509001 The ISO 9000 family of standards are related to quality management systems and designed to help organizations ensure that they meetthe needs of customers and other stakeholders. Section 7.6 part a) enables the use of Smart Meter Verification as a complement to calibration: 7.6 Control of monitoring and measuring equipment The organization shall determine the monitoring and measurement to be undertaken and the monitoring and measuring equipment needed to provide evidence of conformity of product to determine requirements. The organization shall establish processes to ensure that monitoring and measurement can be carried out and are carried out in a manner that is consistent with the monitoring and measurement requirements. Where necessary to ensure valid results, measuring equipment shall: MICRO MOTION WHITE PER a) be calibrated or verified, or both, at specified intervals, or prior to use, against measurement standards traceable to international or national measurement standards; where no such standards exist, the basis used for calibration or verification shall be recorded (see 4.2.4); USA EPA for Greenhouse Gas Forty CFR part 98 drove numerous new or improved measurement points in order to comply with EPA regulations concerning emission of Greenhouse Gases. This regulation specified 1-3 year proving intervals for traditional flowmeters such as dpiorifice and turbine. For newer technologies such as Coriolis, advanced techniques such as Smart Meter Verification were recognized, if the manufacturer could prove a correlation to calibration or proving. For many users, Smart Meter Verification drove the technology selection to Coriolis [7). Safety Instrumented Systems (SIS) International Electrotechnical Commission (IEC) efforts to harmonize the global approach to Process Safety have driven users to invest heavily in education, training, and risk reduction. Coriolis is widely used in critical process control, and in certain SIS applications. The technology is inherently well suited to safety loops due to the simplicity of the sensor and power of the transmitter diagnostics. Proof -testing is a set of prescribed checks to detect failures within the meter. Of main concern are undetected failures that prevent the safety function from performing its intended function. High safety scores enable Micro Motion Coriolis to be "SIL -3 capable." 1.00E-02 0.00E-03 0.00E-03 7.00E-03 0.00E-03 p 5.00E-03 a 4.00E-03 , 3.00E-03 2.00E-03 1.00E-03 - O.00E+00 0 2 4 years Figure 6. 10 Proof -test frequency, or interval is determined by reliability calculations for the SIF. The graph above shows PFD (probability of failure on demand) for a Coriolis flowmeter, using values from the FMEDA. Page 6 of 8 Proof -testing is designed to drive DU (Dangerous Undetected) faults to a sufficiently low level, to satisfythe Risk Reduction required forthe SIF (SIL -2, SIL -3 etc). Exida analyzed Micro Motion Flowmeters [81, and produced the following Proof Test option table: Figure 7. Much as with partial -stroking of control valves, Smart Meter Verification enables a partial proof -test with the device in-line and operating. This assists with a user's goal of meeting both safety and availability needs while reducing expensive, wet calibrations. Users have cited costs in the $2000 to $5000 range for removal, cleaning, and calibration. AGA -17, Coriolis for Natural Gas Published in 2003, the original AGA -11 document described the use of Coriolis meters in the custody transfer of natural gas in the transmission industry. Since then, significant independent review was conducted and experience gained with the technology. Enough additional data and expertise had been gained to warrant an update [91 to add (among other topics) information on meter diagnostics and calibration/verification capabilities. "Proving" gas meters is problematic, as there are fewer options for field checks as compared to liquid meters. This, along with Coriolis' inherent stability overtime has led to more interest in in-situ verification. The AGA -11 revision will carry language such as: In the field, Smart Meter Verification consists of monitoring and evaluating metering conditions, meter diagnostic outputs and/ or ancillary devices of the system to determine if any changes to the meter performance are indicated and to determine the cause of the changes. The operator should consider design specific Smart Meter Verification procedures recommended by the manufacturer, and may include the following: P.WTW Upham C. P.I.r TYPO Pm TOOT D Pll. WPYIPK DOIecllm •�.NhOsnagrx Pn,ra} s+zHaM IM�[M 1 Ad,�W TPA3RN,M' 5F'. •<M1ed.i4lu�auma •Llrcdlyi0rtyaa<„ -erg rsnam: 'J er�img svv�vss:n -���«��emParaLe •uw�mx.ro�mnw _.sereem aya^a+nma-; sawo� Figure 7. Much as with partial -stroking of control valves, Smart Meter Verification enables a partial proof -test with the device in-line and operating. This assists with a user's goal of meeting both safety and availability needs while reducing expensive, wet calibrations. Users have cited costs in the $2000 to $5000 range for removal, cleaning, and calibration. AGA -17, Coriolis for Natural Gas Published in 2003, the original AGA -11 document described the use of Coriolis meters in the custody transfer of natural gas in the transmission industry. Since then, significant independent review was conducted and experience gained with the technology. Enough additional data and expertise had been gained to warrant an update [91 to add (among other topics) information on meter diagnostics and calibration/verification capabilities. "Proving" gas meters is problematic, as there are fewer options for field checks as compared to liquid meters. This, along with Coriolis' inherent stability overtime has led to more interest in in-situ verification. The AGA -11 revision will carry language such as: In the field, Smart Meter Verification consists of monitoring and evaluating metering conditions, meter diagnostic outputs and/ or ancillary devices of the system to determine if any changes to the meter performance are indicated and to determine the cause of the changes. The operator should consider design specific Smart Meter Verification procedures recommended by the manufacturer, and may include the following: ALLOW CORIOLIS SMART METER VE, CATION TO REDUCE YOUR PROVING AND Page 7 of S PROOF -TEST COSTS • Meter Transmitter Verification • Coriolis Sensor Verification • Temperature Verification • Meter Zero Verification This verification of parameters will direct the operator in determining if the meter requires re -zeroing, re -calibration (in- situ or in a Lab) or modifications to the installation. Conclusion Smart Meter Verification is a robust technology for in-situ verification of Coriolis flowmeters. It can be used with confidence as a cost-effective, robust, means of verifying Coriolis Flowmeter performance and safety. Agencies presently recognizing Smart Meter Verification include Canadian ERCB, US EPA 40 CFR part 98, ISO 9001, and the IEC for SIS applications. Future work with agencies such as NIST, AGA, API, and MID is planned. References [1 ] Effect of detector masses on calibration of Coriolis flow- meters, Lange U., Levien A., Pankratz T., Raszillier H., Flow Measurement Instrumentation, Volume 5 Number4,1994. [2] A Finite Element forthe Vibration Analysis of a Fluid conveying Timoshenko Beam, Stack C., Garnett R., Pawlas G., 34th SDM conference proceedings, 1993, AIAA [3] Coriolis Technology Creates Superior Meters, Stack C., Micro Motion White Paper WP -00510, www.micromotion. com, 2003. [4] Using Structural Integrity Meter Verification, Cunningham T., Stack C., Connor C., Micro Motion White Paper WP -00948, www.micromotion.com, 2007. [5] Using Structural Integrity Meter Verification to Track Corrosion in Coriolis Flowmeters, Cunningham T., Micro Motion White Paper WP -01196, www.micromotion. com, 2009. [6] An In -Situ Verification Technology for Coriolis Flowme- ters, Cunningham T., 7th ISFFM, August 2009. [71 Greenhouse Gas Compliance at a major SE USA Gas and Electric Utility (AN -001398a) and Costs of Greenhouse Gas compliance cut by half with Emerson Measurement Solution (AN -001403a), www.micromotion.com, 2011 [8] Safety Manual, pfn 20004482, Rev BA, www.micromotion.com, April 2011 [9] AGA Report No 11 Revised Measurement of Natural Gas by Coriolis Meter, Ms. Angela Floyd, ConocoPhillips Company, presented at TexasA&M Instrument Symposium, www.micromotion.com, 2012 MICRO MOTION WHITE PAPER )1NW W.micromotion.com ® 2013 Micro Motion, Inc, All rights reserved. The Micro Motion and Emerson logos are trademarks and service marks of Emerson Electric Co. Micro Motion, ELITE, MVD, ProLink, MVD Direct Connect, and PlantWeb are marks of one of the Emerson Process Management family of companies. All other trademarks are property of their respective owners. Micro Motion, Inc. USA Worldwide Headquarters 7070 Winchester Circle Boulder, Colorado USA 80301 T +1303-527-5200 T +1800-522-6277 F +1303-530-8459 Micro Motiori Micro Motion Europe Emerson Process Management Neonstraat 1 6718 WX Ede The Netherlands T +31 (0) 318 495 555 F +31 (0) 318 495 556 Page 8 of 8 Micro Motion supplies this publication for informational purposes only. While every effort has been made to ensure accuracy, this publication is not intended to make performance claims or process recommendations. Micro Motion does not warrant, guarantee. or assume anylegal liability forthe accuracy, completeness, timeliness, reliability, or usefulness of any information, product, or process described herein. We reserve the right to modify or improve the designs or specifications of our products at any time without notice. For actual product information and recommendations, please contact your local Micro Motion representative. Micro Motion Japan Emerson Process Management 1-2-5 Higashi 5hinagawa Shinagawa-ku Tokyo 140-0002 Japan T +813 5769-6800 F +813 5769-6840 Micro Motion Asia Emerson Process Management 1 Pandan Crescent Singapore 128461 Rebuplic of Singapore T +65 6777-8211 F +816770-8003 a EMERSON. Attachment l.c NSFMW 2014 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Advanced DP Meter Diagnostics - Developing Dynamic Pressure Field Monitoring (& Other Developments) Jennifer Rabone, Swinton Technology (UK) Bob Peebles & George Kidd, ConocoPhillips (US & UK) Andrey Safonov, IMS Group & Ilnur Khairullin, STP (Russia) Josh Kinney, CEESI (US) INTRODUCTION Differential Pressure (DP) meters have a full diagnostic suite. These diagnostics appeared suddenly and unexpectedly. Due to the DP meter's simplicity there was a long standing axiom that DP meters could have no diagnostics. For more than a century DP meter operators were unaware of the information contained in a DP meter's pressure field. Operators of DP meters traditionally knew of only a small proportion of the information available from each DP meter. However, DP meter technology has now evolved the ability to see and understand the pressure field. This crucial DP meter evolutionary step has diverted the DP meter from the slow road to obsolescence and placed it firmly back in the forefront of modern flow meter development. In one short evolutionary step the development of pressure field monitoring diagnostics transformed the DP meter from a `dumb' device into a `smart' device. Pressure field monitoring gave DP meter technology the capability to make complex discriminations it was entirely incapable of making before. The scale of the expansion of DP meter diagnostic capability has swept away a long held axiom regarding DP meters being an evolutionary dead end. The suddenness of this change has inevitably meant that many are yet to fully grasp the new potential of the DP meter. The importance of this development means that many are yet to fully grasp the likely long term consequences of this change. The development of pressure field monitoring has produced a multiplicative effect. It has not only exposed the potential for DP meters to have a robust, comprehensive and easily understandable diagnostic system, but also for new DP meter capabilities to be developed. DP meters that use these diagnostics are far more capable than those that don't. The diagnostics are powerful, comprehensive and are becoming established, but they are still developing on two fronts. First, the existing diagnostic concepts are now being applied to not just standard DP meters for serviceability checks, but specifically to expand the capabilities of DP meters in traditionally adverse flow condition applications. Secondly, the existing diagnostic suite is being developed. Whereas present techniques compare a 'static' instantaneous (or time averaged) pressure field picture to a fixed expected baseline, more advanced techniques are now being developed that also monitor the dynamic' pressure field fluctuations over time. This paper covers: • a review of the latest diagnostic suite (with some field trial results), • a review of new DP meter applications and capabilities that are now being researched and developed based on these DP meter pressure field monitoring techniques, • techniques specifically for monitoring known problems and trends, • new dynamic response diagnostics. 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 2 DP METER DIAGNOSTICS Swinton Technology partnered with DP Diagnostics to produce the generic DP meter diagnostic suite 'Prognosis' (see Steven [1, 2]). An overview of these patented 'pressure field monitoring' diagnostics is now given. For details the reader should refer to the descriptions given in by Steven [1, 2], Skelton et al [3] & Rabone et al [4]. v N d a Fig 1. Orifice meter with instrumentation sketch and pressure field graph. Figure 1 shows a sketch of a generic DP meter and its pressure field. The DP meter has a third pressure tap downstream of the two traditional pressure ports. This allows three DPs to be read, i.e. the traditional (Apt), recovered (AP,) and permanent pressure loss (APPPL) DPs. These DPs are relate by equation 1. The percentage difference between the inferred traditional DP (i.e. the sum of the recovered & PPL DPs) and the read DP is 6%, while the maximum allowed difference is 0%. DP Summation: AP, = AP, +APppL uncertainty t 0% --- (1) Traditional flow calculation: m..d = f,('AP,), uncertainty t x% --- (2) Expansion flow calculation: m.P = f,(AP,), uncertainty t y% --- (3) PPL flow calculation: mrrr. = frrL (APppL�, uncertainty t z% --- (4) Each DP can be used to meter the flow rate, as shown in equations 2, 3 & 4. Here m„od, MN, & mrrL are the mass flow rate predictions of the traditional, expansion & PPL flow rate calculations. Symbols f, f& f,,,, represent the traditional, expansion & PPL flow rate calculations respectively, and, x%,y%&z% represent the uncertainties of each of these flow rate predictions respectively. Inter -comparison of these flow rate predictions produces three diagnostic checks. The percentage difference of the PPL to traditional flow rate calculations is denoted as 1p%. The allowable difference is the root mean square of the PPL & traditional meter uncertainties, 0%. The percentage difference of the expansion to traditional flow rate calculations is denoted as A%. The allowable difference is the root mean square of the expansion & traditional meter uncertainties, �%. The percentage difference of the expansion to PPL flow rate calculations is denoted as x%. The allowable difference is the root mean square of the expansion & PPL meter uncertainties, v%. 2 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Reading these three DPs produces three DP ratios, the 'PLR' (i.e. the PPL to traditional DP ratio), the PRR (i.e. the recovered to traditional DP ratio), the RPR (i.e. the recovered to PPL DP ratio). DP meters have predictable DP ratios. Therefore, comparison of each read to expected DP ratio produces three diagnostic checks. The percentage difference of the read to expected PLR is denoted as a%. The allowable difference is the expected PLR uncertainty, a%. The percentage difference of the read to expected PRR is denoted as y%. The allowable difference is the expected RPR uncertainty, b%. The percentage difference of the read to expected RPR is denoted as 7%. The allowable difference is the expected RPR uncertainty, c%. L,1) Fig 2. Normalized Diagnostic Box (NDB) with diagnostic results These seven diagnostic results can be shown on the operator interface as plots on a graph. That is, we can plot (Figure 2) the following four co-ordinates to represent the seven diagnostic checks: (V10/o/0%, aO/ol a%) , (.1 %/�%, yO/olb%) , (X%1V/o,77%1cO/o) & (SO/o`BO/o,0). For simplicity we can refer to these points as (xi,yi), (x2,y2), (x3,y3) & (x4,0). The act of dividing the seven raw diagnostic outputs by their respective uncertainties is called 'normalisation'. A Normalised Diagnostics Box (or'NDB') of corner coordinates (1,1), (1,-1), (1,-1) & (-1,1) can be plotted on the same graph (see Figure 2). This is the standard user interface with the diagnostic system 'Prognosis'. All four diagnostic points inside the NDB indicate a serviceable DP meter. In this paper it will be shown that for the special case of monitoring the severity of a known problem, such as levels of contamination of a meter run or the liquid loading of a wet gas flow, the reference with which to compare the found performance is arbitrary. When monitoring changes in the severity of a problem, it is just as valid to use the meter performance at a known finite level of the problem as the reference as it is to use the correctly operating meter performance. In this scenario there is no need to normalise diagnostic data, as the uncertainty of the baseline diagnostic parameters is not relevant to the task at hand. How the diagnostic points move relative to changes in the known problem is what is important, not changes relative to the correctly operating meter baseline. Hence, for trend monitoring, there is no need to normalise the data. Without normalised data the NDB must be removed as it is then meaningless. In this case we can monitor 'raw', i.e. un -normalised, diagnostic points by plotting (Vl%,a%), (lO/o,yO/o), (,yO/o i7%) & (6%,0). In this case the correctly operating DP meter performance or the last read result are obvious candidates for the arbitrary diagnostic reference. 3 REVIEW OF SOME DP METER R&D PROJECTS BASED ON PRESSURE FIELD MONITORING The advent of DP meter pressure field monitoring diagnostics has allowed DP meters to be considered for applications where they (and all) meters may traditionally struggle. Research & development projects have grown from these DP meter diagnostics. A summary of some of these projects are given in Section 32"d International North Sea Flow Measurement Workshop 21-24 October 2014 3.1 Contamination Monitoring (by CEESI, DP Diagnostics, & Various Operators) Industrial gas flows can contaminate a meter run over time thus adversely affecting the flow meter. In 2009 Steven [2) showed with laboratory test results the effect on an orifice meter if the plate became contaminated. Contamination induced a negative flow rate prediction and the diagnostic system indicated that the meter output was in error. However, in real applications contamination coats the meter and meter run. Over the last few years CEESI has received multiple enquires regarding contaminated meter testing. In some of the projects the DP meter diagnostic system 'Prognosis' was included on orifice meters. Following an early client test where a heavy grease and soda bicarbonate mixture was used as a contaminant, CEESI has subsequently used this mixture as a default contaminate. Figure 3 shows the inside of a clean 4", sch 80, 0.500 senior fitting orifice meter. Figures 4 & 5 show two different levels of contamination applied 15D upstream and 8D downstream of a straight orifice meter run. Prognosis was applied using the ISO 5167 Part 2 derived baseline parameters. Fig 3. Clean Orifice Meter Contamination fpr 7 i `v Fig 5. Moderate Contamination 2.51 Orifice Meter Run Contamination Performance 15 ♦Baseline(Clean) ■ Light CoLrrination AModerate Contarrnnation 0 5 0.75 +1% 1.25 1.5 1.75 Mass Flow Rate ft1s) Fig 6. Orifice Meter Performance with varying Contamination Levels. 2.25 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Figure 6 shows the response of the orifice meter to different levels of contamination. These results were read from air flow at 30 Bar and 250C. The orifice meter's output is compared to the gas turbine meter reference flow rate of 0.35% uncertainty (see error bars on Figure 6 data). It is immediately notable that the contamination has a surprisingly small effect on the meter's performance. If we consider the orifice meter's overall flow rate prediction uncertainty to be 0.7% (i.e. API 14.3) we see that the clean orifice meter agrees with that specification. The light contamination had virtually no adverse effect. The heavier contamination had a noticeable but small effect, causing the meter to read a slightly lower flow rate, which only approached -1% bias at higher flow rates. -1, 1 1 1.1 ♦ Baseline (x1,yl ) ■ Baseline (x2,y2) ♦ Baseline (x3,y3) • Baseline (x4,0) ♦ Light Contamination (x1,x1) ■ Light Contamination (x2,y2) ♦ Light Contamination (x3,y3) s Light Contamination (x4,0) ♦ Moderate Contamination (xl,y1) ■ Moderate Contamination (x2,y2) ♦ Moderate Contamination (x3,y3) • Moderate Contamination (x4,0) Fig 7. Sample Prognosis Results, 3 Contamination Levels Superimposed on Graph. Figure 7 shows three sample Prognosis results; each are the maximum flow rates tested for the clean, light and heavier contaminations. The default Prognosis sensitivity settings of x=0.5%, y=2%, z=2%, a=4%, b=2.5%, C=3%& B =1% were used. None of the three examples show a diagnostic warning. However, if we consider Figure 6 this is not particularly surprising, as the contamination is not causing much of a flow rate prediction bias. Not one of the test results could be confirmed to be causing the orifice meter to be in error by greater than ±1%. Prognosis has been shown to be capable of seeing many flow rate prediction errors to within 1% of the actual flow rate, and most flow rate prediction errors to within 1% of the stated meter uncertainty. Therefore, here Prognosis is indicating no meter malfunction as the orifice meter is still giving the gas flow rate to <10/o. Prognosis looks for actual flow rate prediction errors, which is a subtle but important difference to looking for non-compliance with standard documents! An ISO non-compliant orifice meter can often still predict the correct flow rate (to within the meter's uncertainty). Figure 7 does show that the increasing contamination has an affect on the diagnostics. As the contamination increases the points (xi,yi), (x2,y2) & (x3,y3) diverge from the origin. The point (x4,0) remains close to the origin as it should, as the DPs are being correctly read. If it is known that the meter will suffer from a particular problem, Prognosis can be used to monitor that particular problem. If contamination is a constant concern Prognosis can monitor changing levels of contamination. If the system is to be used in this way, the operator can set Prognosis to show �W%,Gr%),(a°/qy%�,�%,r/%� &((5%,0). In practical terms this means setting the system sensitivity to x=1/,/2%, y=1/)/2%, z=1/v/2%, a=1%, b=1%, c=1% & 0 =1%. In this scenario the NDB has no meaning and can be ignored. Fig 7's results are re -plotted as Fig 7a. When monitoring specific issues, un -normalised data gives the most sensitive diagnostics. f r ♦ Baseline (x1,yl ) ■ Baseline (x2,y2) ♦ Baseline (x3,y3) • Baseline (x4,0) ♦ Light Contamination (x1,x1) ■ Light Contamination (x2,y2) ♦ Light Contamination (x3,y3) s Light Contamination (x4,0) ♦ Moderate Contamination (xl,y1) ■ Moderate Contamination (x2,y2) ♦ Moderate Contamination (x3,y3) • Moderate Contamination (x4,0) Fig 7. Sample Prognosis Results, 3 Contamination Levels Superimposed on Graph. Figure 7 shows three sample Prognosis results; each are the maximum flow rates tested for the clean, light and heavier contaminations. The default Prognosis sensitivity settings of x=0.5%, y=2%, z=2%, a=4%, b=2.5%, C=3%& B =1% were used. None of the three examples show a diagnostic warning. However, if we consider Figure 6 this is not particularly surprising, as the contamination is not causing much of a flow rate prediction bias. Not one of the test results could be confirmed to be causing the orifice meter to be in error by greater than ±1%. Prognosis has been shown to be capable of seeing many flow rate prediction errors to within 1% of the actual flow rate, and most flow rate prediction errors to within 1% of the stated meter uncertainty. Therefore, here Prognosis is indicating no meter malfunction as the orifice meter is still giving the gas flow rate to <10/o. Prognosis looks for actual flow rate prediction errors, which is a subtle but important difference to looking for non-compliance with standard documents! An ISO non-compliant orifice meter can often still predict the correct flow rate (to within the meter's uncertainty). Figure 7 does show that the increasing contamination has an affect on the diagnostics. As the contamination increases the points (xi,yi), (x2,y2) & (x3,y3) diverge from the origin. The point (x4,0) remains close to the origin as it should, as the DPs are being correctly read. If it is known that the meter will suffer from a particular problem, Prognosis can be used to monitor that particular problem. If contamination is a constant concern Prognosis can monitor changing levels of contamination. If the system is to be used in this way, the operator can set Prognosis to show �W%,Gr%),(a°/qy%�,�%,r/%� &((5%,0). In practical terms this means setting the system sensitivity to x=1/,/2%, y=1/)/2%, z=1/v/2%, a=1%, b=1%, c=1% & 0 =1%. In this scenario the NDB has no meaning and can be ignored. Fig 7's results are re -plotted as Fig 7a. When monitoring specific issues, un -normalised data gives the most sensitive diagnostics. 32"d International North Sea Flow Measurement Workshop 21-24 October 2014 Increasing Contamination t t6 t 0 1 ♦ Baseline (y/°�o a%) ■ Baseline (AO/o.yo/o) ♦ Baseline (;[°rgri%) * Baseline (S°%,o) ♦ Light Contamination (yr°/",a%) ■ Light Contamination (A%,y°io) ♦ Light Contamination (Xoio,noio) r Light Contamination (,5%,o) ® Moderate Contamination (v/oiaa% ■ Moderate Contamination (A%, y%) ♦ Moderate Contamination (X% r1%) • Moderate Contamination (,5%,o) Fig 7a. Sample Un -Normalised Results, 3 Contamination Levels on Graph This Operator / CEESI project to apply Prognosis to specifically monitor contamination levels is one example of how the advent of pressure field monitoring has not just created DP meter diagnostics but potentially expanding DP meter capabilities. 3.2 Erosion Monitoring (by RPSEA, Letton Hall Group, TUVNEL & DP Diagnostics) CL Third Downstream Pressure Tap Standard Throat Pressure Tap I 3 Inlet k -° I Presure Tap — Fig 8. Modified Venturi Meter. In 2011 the Lefton -Hall Group and DP Diagnostics met at ConocoPhillips Houston office to discuss a RPSEA funded project. Letton-Hall were investigating for RPSEA ways of identifying erosion in multiphase meters. A third pressure tap downstream of the Venturi meter throat was being considered. It was postulated that if this third tap was in a section likely to have a slower erosion rate than the throat section then pressure field monitoring could identify erosion. That is, the DP Diagnostics pressure field monitoring techniques were being considered as a component of this complex research. DP Diagnostics had previously shown that pressure field monitoring (i.e. 'Prognosis') was effective at monitoring DP meter erosion. For example, Steven (2] showed that Prognosis could see and trend orifice meter sharp edge erosion. However, multiphase flow meter erosion monitoring is a much more difficult task. There are multiple adverse effects on the Venturi meter, e.g. changing fluid properties & flow conditions, erosion and other unexpected issues. The patent holders DP Diagnostics gave RPSEA / Letton-Hall Group their blessing for the research. Figure 8 shows a design subsequently developed by TUVNEL / Letton-Hall in this RPSEA desktop exercise. The scope of this project was limited, and further work would be required to develop this idea. This project is another example of how 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 the advent of pressure field monitoring has not just created DP meter diagnostics but has potentially expanded DP meter capabilities. 3.3 Oil with Water Flow Metering (by CEESI & DP Diagnostics) Oil with water flow metering typically uses a volume flow meter in series with a mixer/ probe sample system. The flow meter gives the total flow rate, whilst the sample system gives the water cut. Combining these two values gives the oil and water flow rates. In order for this approach to give custody transfer flow rate prediction uncertainties, both the total flow rate and water cut predictions must have low uncertainties. It is therefore very desirable in custody transfer applications for the flow meter to have comprehensive diagnostics. Of the three commonly used flow meters for this application, all have their Flow rate prediction uncertainty and diagnostic capabilities adversely affected by the oil & water mix. The turbine meter has no diagnostics and the total flow rate prediction uncertainty expands considerably as the flow rate reduces and the oil & water separates (see Cousins et al [5]). The ultrasonic meter (USM) total flow rate prediction uncertainty is significantly higher at approximately 3% for oil with water flows compared to the homogenous oil flow uncertainty of < 0.2% (see Brown et al [6]). There is little in the literature with regard to a modern ultrasonic meter's diagnostic suite when the meter is used with oil with water flows. It is generally understood that the ultrasonic meter diagnostic suite would be significantly affected by the presence of water with the oil. The Coriolis meter total flow rate prediction uncertainty for oil with water flows is relatively good at approximately 0.5% (see Kegel et al [7]) but there is little in the literature regarding applying the Coriolis based diagnostics to the specific case of oil with water flows. Furthermore, Kegel [7] showed that water cut measurement via a Coriolis meter produced uncertainties well in excess of what would be acceptable for custody transfer metering. Hence, industry for the moment requires a sample system regardless of what flow meter is used. W&UR 2 6&$ec. Fig 9. Cone meter, 0.6 m/s, r+o 0.5. Fig 10. Cone meter 1.6 m/s, mm 0.2. CEESI and DP Diagnostics tested a clear body 6", 0.4830 cone DP meter in horizontal oil with water Flows (see Cousins et al [5]). Figures 9 & 10 show oil (dyed red) and water flowing through a cone meter. Note that the velocities are the average flow velocity and '6um is the ratio of water to total liquid mass flow. Figures 11 & 12 show the oil only and water only calibration results. The type of homogenous fluid had no effect on the DP meter performance. Figure 13 shows Prognosis calibration results. The meter was fully diagnostic ready when tested with oil and water mixtures. Cousins et al [5] discussed in detail the DP meter's response to use in oil with water flow metering applications. The DP meter had as good a performance in this application as turbine and ultrasonic meters. The Coriolis meter had the best flow rate prediction, but as with the turbine and ultrasonic meters the diagnostic I i 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 capability was adversely affected by the oil and water mixture. Only the DP meter had a fully serviceable diagnostic system when used with oil and water applications. 6". OA84 Beta Ratio Cone Meter 2- 49 1.75 oKr = 1.51q + (-3E-07'Re), +/-3% 1.5 i �� �..�..�,.� ♦Cd (Water) 1.25 OCd (O iIJ v 1 Cd = 0.791 + (-2E-08'Re), +/-1% • Kr (Water) 0.75 ❑ Kr (Oil) o ♦Kppl (VJeter) LL 0.5 Kpp1=02207+(1E-08'Re),+/-2.5% GKppl (D in 0.25 3�. A .6 gl !-Ca. 0 0 50000 100000 150000 200000 250000 300000 Reynolds Number Fig 11. 6", 0.4830 Cone Meter Flow Coefficients in Homogenous Liquid Flow, 1 6", 0.483 Beta Ratio Cone Meter 0.9 0.8 PLR = 0.739 + (-1E-07'Re), +1-4% +PLR (Water) 0 0.7 OPLR (Oil) 0.6 ■ P FIR (Water) 0.5 RPR = 0-347 + (2E -07`14e), +/-7% ❑ P RR (Oil) IL 0.4! 1 n♦ -r 0.3 0 e 9 Lis rr., _ ♦RPR (water) QRPR (00) 0.2 0.1 PRR = 0.255 + OE -07'11e). +/-6% 0 0 50000 100000 150000 200000 250000 300000 Reynolds Number Fig 12. 6", 0.4830 Cone Meter DP Ratios in Homogenous Liquid Flow. Water Data Point Re = 153.6e3 Oil Data Point Re = 121.3e3 Normalized Flow Comparison Fig 13. Examples of Baseline Diagnostic Results Figure 14 shows sample diagnostic results for the cone meter when it was used with various flow rates and water liquid ratios (i.e. 'WLR'). The diagnostics are immune to the fact that there is oil and water present. The DP meter has a diagnostics suite that is wholly unaffected by the oil and water mix. It is therefore fully available to clearly indicate the serviceability of the meter in an oil with water flow application. For example, Figure 15 shows a Prognosis results for the case of a correct and then incorrect discharge coefficient being entered. The flow is an oil with water flow (of WLR 23%). The actual input is Cd=0.791+ (-2e-8*Re) which as way of example was entered as Cd=0.791+ (-2e-7*Re) inducing a flow F, • (Xr>yt)water i e • (Xz>yz) water a. • A (X3 aV3) water a O (X4,0) water o (Xt>yr) 07 1e a € O (X -,Y2) ag G (X3>)r3) od Z 4 (X4,O) oil Normalized Flow Comparison Fig 13. Examples of Baseline Diagnostic Results Figure 14 shows sample diagnostic results for the cone meter when it was used with various flow rates and water liquid ratios (i.e. 'WLR'). The diagnostics are immune to the fact that there is oil and water present. The DP meter has a diagnostics suite that is wholly unaffected by the oil and water mix. It is therefore fully available to clearly indicate the serviceability of the meter in an oil with water flow application. For example, Figure 15 shows a Prognosis results for the case of a correct and then incorrect discharge coefficient being entered. The flow is an oil with water flow (of WLR 23%). The actual input is Cd=0.791+ (-2e-8*Re) which as way of example was entered as Cd=0.791+ (-2e-7*Re) inducing a flow F, 32"d International North Sea Flow Measurement Workshop 21-24 October 2014 rate prediction bias of -4.6%. Figure 15 shows Prognosis indicating a metering problem. Figure 16 shows Prognosis results for the case where the traditional DP reading is read correctly and then incorrectly. The flow is an oil with water flow (of WLR 6%). The actual traditional DP is 105.8"WC (26.3 kPa), but let us consider the case if the DP transmitter was, say, saturated at 100"WC (24.86 kPa). The induced flow rate prediction error would be approximately -2.8%. Figure 16 shows Prognosis indicating a metering problem. ♦ (Xl,yi) WLR 0.06, 1.6 ms ■ (X2,y2) WLR 0.06, 1.6 ms ♦ (X3,y3) WLR 0.06,1.6 ms o (X4,0) WLR 0.06,1.6 rrVs 0 (Xt,yt) WLR 0.23, 0.9 ms ❑ (X2,y2) WLR0.23, 0.9 ms P, (X3,y3) WLR 0.23, 0.9 rrys o(X4,0) WLR0.23.0.9ms Water in Oil Sample Results WLR 0.55, 0.6 ms 4VLR 0.05 0.6 m+s WLR 0.55, 0.6 ms WLR 0.55, 0.6 rn+s WL110.79, 1.6 ms WLR0.79, 1.6 ms WLR 0.79, 1.6 ms Normalized Flow Comparison Fig 14. Sample Data from a 6", 0.483(3 Cone Meter Tested with Oil with Water Flows. WLR 23%. Average Velocity 1.6 m/s 0 (X"V ❑ (X2oy] T A (X3: -E O (X4 0, • (Xr,yr ■ (X2'Y2 A (X3,y3 O (X<A) Fig 15. Incorrect Cd. Correct Operation Coned Operation Correct Operation', Issue WLR 6% Average Velocity 1.6 mis Fig 16. Incorrect DPt Read. This project is another example of how the advent of pressure field monitoring has not just created DP meter diagnostics but has potentially expanded DP meter capabilities. 3.4 Heavy Oil Flow Metering (by TUVNEL, DP Diagnostics & Swinton Technology) With much of the world's remaining hydrocarbon deposits held in heavy (highly viscous) oil, metering of heavy oil flows is becoming ever more important. However, it is a challenge to meter heavy oil flow. The high viscosity means that heavy oil production flows tend to have very low Reynolds numbers. Most flow meters have non-linear flow coefficients in low Reynolds number ranges. Hence, it is critical to know the viscosity and therefore the Reynolds number to low uncertainty, so that the flow coefficient and the flow rate can be known to low uncertainty. However, it is a challenging problem to know the viscosity of a heavy oil production flow, as viscosity changes significantly with temperature and composition. It was to this problem that the DP Diagnostics concept of DP meter pressure field monitoring was applied by TUVNEL & DP Diagnostics. In 2012 TUVNEL undertook a heavy oil research project under contract to the UK Government's Department for Innovation, Universities and Skills as part of the 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 National Measurement System's Engineering and Flow Programme. An 8", 0.60 Venturi meter with a downstream pressure tap (see Figure 17) was tested with Aztec fluid (viscosity 0.87 Pa.$). Figures 18 & 19 show the pressure field analysis, i.e. the Prognosis calibration results. As with all flow meter designs at this low Reynolds number range the Venturi meter is highly influenced by Reynolds number. All six diagnostic parameters are fitted to Reynolds number. It is this phenomena that allows Prognosis to be very useful with heavy oil flow. If a given meter is calibrated in heavy oil to characterize the Prognosis parameters then the Venturi meter with Prognosis can be used as a combined viscosimeter and a flow meter. Fi Oil Flow Facility (Flow Left to Right). 2 Sin, 0.6 Beta Venturi Meter 1.8 \.. Kr=f 1.62(Re) m 1.4 �� ♦ cd -� 1.2 xr ♦Kppl Cd=fl(Re) 0 1 v 0.8 �IIHIv Q 0.6 Kppl = If (Re) 0.4LL 0.2 0 0 200 400 600 800 1000 Reynolds Number Fig 18. 8", 0.60 Venturi Meter Flow Coefficients vs. Reynolds Number. 1 S", 0.6 Beta Venturi Meter + PLR 0.9 ■ PRR 07 PLR = f4 (Re) A RPR 20.690.5 0.sa90.5 RPR = fs(Re) 0.4 0.3 0.2 PRR = f f, (Re) _ 0.1 0 0 200 400 600 800 1000 1200 Reynolds Number Fig 19. 8", 0.60 Venturi Meter DP Ratios vs. Reynolds Number 10 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Figure 20 shows all TUVNEL heavy oil data applied to Prognosis for the case of known viscosities and the flow coefficients and DP ratios being fitted to the Reynolds number. In practice, while the operator knows the calibrated discharge coefficient and other diagnostic parameters relationships, the operator often struggles to know the actual fluid viscosity as the temperature and composition vary over time. It is here that Prognosis can become a significant benefit. Prognosis can tell the operator the viscosity thereby allowing the Reynolds number, discharge coefficient and flow rate to be derived. The following example shows this process. A ■ (xi Y7) 1,1 1,1 (x2 Y2) -- — — , (93 Y3) -1. 1 1,-1 O (xa , U) an Fig 21. 8", 0.60 Venturi Meter Fig 22. 8", 0.6(3 Venturi Meter I't Viscosity Guess 0.5 Pa. 2nd Viscosity Guess 0.5 Pa. 1,1 1,1 ♦ (x1 -Y0 • (X2'Y2) L (xs. Ys) 1,1 1,1 0N-0) A Fig 23. 8", 0.6(3 Venturi Meter 3'd Viscosity Guess 0.75 Pa. -1 11 Fig 24. 8", 0.60 Venturi Meter 41h Viscosity Guess 0.85 Pa. Consider a data point with a mass flow of 35.5 kg/s, a Reynolds number of 255, and a fluid viscosity (N) of 0.87 Pa.s. For a known viscosity this flow point is included in Figure 20. However, in the field the operator may not know the viscosity. Say a viscosity of 0.5 Pa. is assumed, then the flow rate prediction is 38.34 kg/s, which is an error of +7.9%. Figure 21 shows the Prognosis response. Accepting that the problem is an unknown viscosity then Prognosis is saying that viscosity is in error. The operator must iterate to find the correct viscosity. 11 A A, ♦ (A % All • (M At 0 +* Al $PA i rA ■ Fig 20. All TUVNEL 8", 0.60 Venturi Meter Prognosis Results. A ■ (xi Y7) 1,1 1,1 (x2 Y2) -- — — , (93 Y3) -1. 1 1,-1 O (xa , U) an Fig 21. 8", 0.60 Venturi Meter Fig 22. 8", 0.6(3 Venturi Meter I't Viscosity Guess 0.5 Pa. 2nd Viscosity Guess 0.5 Pa. 1,1 1,1 ♦ (x1 -Y0 • (X2'Y2) L (xs. Ys) 1,1 1,1 0N-0) A Fig 23. 8", 0.6(3 Venturi Meter 3'd Viscosity Guess 0.75 Pa. -1 11 Fig 24. 8", 0.60 Venturi Meter 41h Viscosity Guess 0.85 Pa. Consider a data point with a mass flow of 35.5 kg/s, a Reynolds number of 255, and a fluid viscosity (N) of 0.87 Pa.s. For a known viscosity this flow point is included in Figure 20. However, in the field the operator may not know the viscosity. Say a viscosity of 0.5 Pa. is assumed, then the flow rate prediction is 38.34 kg/s, which is an error of +7.9%. Figure 21 shows the Prognosis response. Accepting that the problem is an unknown viscosity then Prognosis is saying that viscosity is in error. The operator must iterate to find the correct viscosity. 11 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Try the higher viscosity of 1 Pa.s. Figure 22 shows the Prognosis result. A meter error is still shown and the pattern has inverted. This indicates that the viscosity value was increased too much. Trying the mid viscosity of 0.75 Pa.s gives Figure 23. A meter error is shown, but the points are getting closer to the NDB and the pattern has inverted back to indicating the viscosity input is now slightly too low. A further iteration to a viscosity of 0.85 Pa.s is shown in Figure 24. All points are now in the NDB. The estimated viscosity is 0.85 Pa.s, the associated Reynolds number is estimated at 262 and the flow rate is estimated at 35.46 kg/s, i.e. - 0.23% difference from the reference meter's value. Prognosis has estimated the viscosity, thereby allowing the Reynolds number, discharge coefficient and flow rate to be predicted with no external viscosity measurement required. Rabone et al [8] reports on this heavy (high viscosity) ail flow metering research. This project is another example of how DP meter pressure field monitoring has expanded DP meter capabilities. 3.5 Metering High CO2 Content Natural Gas Flows (by CEESI & DP Diagnostics) The natural gas production industry is encountering more high carbon dioxide (CO2) content natural gas flows. Also, around the world carbon capture projects are becoming a higher priority. There are two potential issues when metering high CO2 content gas flows. The first is that the gas exhibits some unusual properties that could potentially adversely affect gas meter performance. The second is that the gas / liquid phase boundary of CO2 is in the ranges of thermodynamic conditions that can be encountered in natural gas production. High carbon dioxide content natural gas flows may produce some liquid drop out. In this section the response of an orifice meter and its diagnostic system to high CO2 natural gas flows is discussed. The tests were carried out by CEESI with gaseous phase flow only. (The response of an orifice meter and its diagnostic system to two-phase / wet gas flow will be discussed in Section 3.5). Carbon dioxide has fluid properties that produce challenges for different gas meter types. Apart from the potential phase change issue, an Ultrasonic meter may have trouble with `wave energy absorption by molecular thermal relaxation'. That is, if the ultrasonic transducer frequencies coincide with the natural frequency for which CO2 absorbs wave energy the signal may be lost. It is the unusually low value of CO2's compressibility which has caused some concern regarding turbine and DP meters. Unusual compressibility effects could potentia//y cause different lift and drag forces on gas turbine blades, and biases on expansibility calculations on gas DP meters. In 2013 CEESI carried out a series of high CO2 content natural gas flow tests. The CEESI wet gas test facility was utilised. The thermodynamic conditions were set such that phase change would not be an issue. As the performance of all gas meters was questioned, one aspect of this test was to compare the performance of gas meters that operate by utilising different physical principles. Any adverse effects due to the presence of a high CO2 concentration should induce different problems on these different meter designs. Two of the gas meters chosen were an 8" turbine meter (Fig 25) with 0.75% mass flow rate prediction uncertainty and, an 8", 0.5640 orifice meter inclusive of pressure field monitoring (Fig 26) with 0.7% mass flow rate prediction uncertainty. Due to other client meters installed in the facility the orifice meter was installed > 200D downstream of the turbine meter. The Daniel Gas Chromatograph was calibrated with the appropriate test gas. AGA8 & RefProp software independently calculated the gas density from the GC 12 32"d International North Sea Flow Measurement Workshop 21-24 October 2014 output and read pressure & temperature. These density predictions agreed to < 0.02%. Standard natural gas (18mW) viscosity and isentropic exponents were used. As the turbine meter was the wet gas facility's normal primary reference gas meter, it was chosen as the arbitrary primary reference gas meter against which to compare the orifice meter. Fig 25. CEESI 8" Turbine Meter 3 2 r-1 Fig 26. CEESI 0.5640 Orifice Meter Orifice Meter Perofmance Relative to Turbine Meter *2%CO2, Orifice Nide ■ 5% COT., Orifice Mich A10%CO2, OfIfice NideT • 17% CO2 Orifice Hider x 22% CO2 Orifice NWer 0 32% CO2 Orifice Nid� +413%CO2 Orifice We; +1.026% ---------------- illy--------------- A�+V o oy G OD -1.02696 0 1000000 2000000 3000000 4000000 Reynods Number Fig 27. Orifice to Turbine Meter Flow Rate Prediction Comparisons The tests were conducted at 14 & 49 Bar(a), across 4e5 < Reynolds number < 4.5e6 with CO2 concentrations in a natural gas of 2% (i.e. baseline), 5%, 10%, 17%, 22%, 32% and 40%. Sample data showing the difference between the orifice meter and the turbine meter is shown in Figure 27. The dashed line represents the root mean square of the two meters' uncertainties (when both meters are operating correctly). The meters agreed within their respective uncertainties to 95% confidence. The two meters, using two different physical principles, tended to agree with each other across the range of CO2 concentrations tested. Changing the CO2 concentration had no noticeable effect on the performance of the meters. Hence, despite the aforementioned concerns, 13 I I 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 these tests suggest that turbine and orifice meters are suitable for use in natural gas and CO2 up to at least a CO2 concentration of 40%. Nominal 14 Bar(a) -1, 1 I 1, 1 ♦2% CO2, Re 1.9e6 ((xx1,yy21)) ♦ 2 % CO2: Re 1 9e6 (x3y31 :2% CO2, Re 1.9e6 h(x4.0} 5% CO2, Re 8.6e5 (x1,y1) ■5%CO2.Re 8.6e5 2.y2) ♦5%CO2, Re86e5 x3,p3 •5%CO2, Re 8.6e5 x4,0) ♦ 10% CO2, Re 6.9e5 1,y1 ■ 10% CO2, Re 6.9e5 x2,y2; ♦10%CO2,Re6.9e5 3.6v3) ♦ 10% CO2, Re 69e6 4,0) e22-' CO2,Re7.8e5x1.y1 ■22%CO2.Re7.8e5 2y2 ♦ 22% CO2, Re 7.8e5 z3,y3 • 22% CO2, Re 7.8e5 4,0) •40%CO2. Re 9.7e5 x1.y1) ■ 40% CO2, Re 9 7e5 2,y2 ♦40%CO2,Re9.7e5 3, 3 e40%CO2, Re 9.7e5 x4,0) -1, -1 1 1, -1 Fig 28. Sample 14 Bar(a) 8", 0.5640 Orifice Meter Prognosis Results for Varying CO2 Concentrations. Nominal 49 Bar(a) -1, 1 1 1, 1 .1 An ■ ee ♦2% CO2, Re 1.9e6 ((xx1,yy21)) ♦ 2 % CO2: Re 1 9e6 (x3y31 :2% CO2, Re 1.9e6 h(x4.0} 5% CO2, Re 8.6e5 (x1,y1) ■5%CO2.Re 8.6e5 2.y2) ♦5%CO2, Re86e5 x3,p3 •5%CO2, Re 8.6e5 x4,0) ♦ 10% CO2, Re 6.9e5 1,y1 ■ 10% CO2, Re 6.9e5 x2,y2; ♦10%CO2,Re6.9e5 3.6v3) ♦ 10% CO2, Re 69e6 4,0) e22-' CO2,Re7.8e5x1.y1 ■22%CO2.Re7.8e5 2y2 ♦ 22% CO2, Re 7.8e5 z3,y3 • 22% CO2, Re 7.8e5 4,0) •40%CO2. Re 9.7e5 x1.y1) ■ 40% CO2, Re 9 7e5 2,y2 ♦40%CO2,Re9.7e5 3, 3 e40%CO2, Re 9.7e5 x4,0) -1, -1 1 1, -1 Fig 28. Sample 14 Bar(a) 8", 0.5640 Orifice Meter Prognosis Results for Varying CO2 Concentrations. Nominal 49 Bar(a) -1, 1 1 1, 1 -1, -1 I 1, -1 ■ 2% CO2, Re 3.1e6 ♦2% CO2, Re 3.1e6 • 2% CO2, Re 3.1 e6 e 5% CO2, Re 3.2e6 ■ 5% CO2, Re 3.2e6 ♦ 5% CO2, Re 3.2e6 • 5% CO2, Re 3.2e6 ♦ 9% CO2, Re 3.4e6 ■ 9% CO2 Re 3.4e6 ♦ 9% CO2. Re 3.4e6 ■ 9% CO2, Re 3.4e6 ♦ 17% CO2, Re 3.7e6 ■ 17% CO2, Re 3 7e6 ♦ 17% CO2. Re 3.7e6 • 17% CO2, Re 3.7e6 ♦ 32% CO2, Re 3.3e6 ■ 32% CO2. Re 3.3e6 s32%CO2, Re 3.3e6 • 32% CO2. Re 3.3e6 Fig 29. Sample 49 Bar(a) 8", 0.5640 Orifice Meter Prognosis Results for Varying CO2 Concentrations. Figures 28 & 29 shows sample Prognosis results from the orifice meter. For all data taken, the diagnostic system `Prognosis' continued to operate normally for natural gas / CO2 mixture with CO2 5 40%. It is expected that all DP meters would give the same result. Therefore, DP meters used in high CO2 concentration natural gas flow applications operate to their normal uncertainty and through pressure field monitoring have a fully serviceable diagnostic system. This project is another example of how DP meter pressure field monitoring has expanded (or at least confirmed) DP meter capabilities. 3.6 Wet Gas Meter Developments (by DP Diagnostics, CEESI & Various Operators) Many natural gas wells produce wet gas flows. Wet gas flow is an extremely adverse Flow condition for any flow meter. However, the sophisticated multiphase wet gas meter technologies are not commercially viable for a huge number of 14 .1 -1, -1 I 1, -1 ■ 2% CO2, Re 3.1e6 ♦2% CO2, Re 3.1e6 • 2% CO2, Re 3.1 e6 e 5% CO2, Re 3.2e6 ■ 5% CO2, Re 3.2e6 ♦ 5% CO2, Re 3.2e6 • 5% CO2, Re 3.2e6 ♦ 9% CO2, Re 3.4e6 ■ 9% CO2 Re 3.4e6 ♦ 9% CO2. Re 3.4e6 ■ 9% CO2, Re 3.4e6 ♦ 17% CO2, Re 3.7e6 ■ 17% CO2, Re 3 7e6 ♦ 17% CO2. Re 3.7e6 • 17% CO2, Re 3.7e6 ♦ 32% CO2, Re 3.3e6 ■ 32% CO2. Re 3.3e6 s32%CO2, Re 3.3e6 • 32% CO2. Re 3.3e6 Fig 29. Sample 49 Bar(a) 8", 0.5640 Orifice Meter Prognosis Results for Varying CO2 Concentrations. Figures 28 & 29 shows sample Prognosis results from the orifice meter. For all data taken, the diagnostic system `Prognosis' continued to operate normally for natural gas / CO2 mixture with CO2 5 40%. It is expected that all DP meters would give the same result. Therefore, DP meters used in high CO2 concentration natural gas flow applications operate to their normal uncertainty and through pressure field monitoring have a fully serviceable diagnostic system. This project is another example of how DP meter pressure field monitoring has expanded (or at least confirmed) DP meter capabilities. 3.6 Wet Gas Meter Developments (by DP Diagnostics, CEESI & Various Operators) Many natural gas wells produce wet gas flows. Wet gas flow is an extremely adverse Flow condition for any flow meter. However, the sophisticated multiphase wet gas meter technologies are not commercially viable for a huge number of 14 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 economically marginal fields. Hence, operators seek to compromise between cost and capability by using the gas meter with the best wet gas flow performance. Like all gas meter technologies DP meters are significantly affected by the presence of liquids with gas flows. However, relative to other gas meter technologies the DP meter is reasonably resistant to the adverse affects of wet gas flow. It is for this reason that virtually all multiphase wet gas meter systems have a DP meter at the core of their design. It is also for this reason that operators chose DP meters for marginal wet gas flow production flows. Hence, multiple operators have approached DP Diagnostics / Swinton Technology regarding the potential of adding pressure field monitoring (i.e. Prognosis) to DP meters as an economically viable alternative to full wet gas metering systems. Figures 30a & 30b show sample photographs of wet gas flow (moving left to right) from a CEESI view port. Figure 30a shows stratified horizontal flow, where the pressure and gas velocity are relatively low and the phases are separated. Figure 30b shows mist flow, where the pressure and gas velocity are relatively high and the phases are mixed. Fig 30a. Stratified Flow Fig 30b. Annular Mist Flow Figure 26 shows an 8", schedule 40 orifice meter installed in the CEESI wet gas flow facility. Figure 31 shows CEESI sample wet gas flow Prognosis results when this orifice meter had a 0.689(3 plate installed. As the diagnostics are being used to monitor the level of liquid loading (i.e. Lockhart Martinelli parameter, Xu) this is a trending application and there is no need to normalise the data. Hence, the data is presented as (A%,y%), & (S%,0 CEESI 8", 0.689 Beta Orifice Meter Wet Gas Data Q 13 increasing liquid loading ■ ■ • -Q ♦ (10°.o,Lr°6) X1n=0.01 ■ (7,°'oy °io) xim=0.01 • (x%,?%o) Xkn=0.01 ♦ (WO/o,¢°/u) Xkn=0.05 ■ (2%,7%) Xkn=0.05 • �i0io,t]4'o) Xkn=0.05 (woo,aO6) Xlm= 0.1 • (),0 o' "40)x1n=al • (7%,17%) xkn=0.1 ♦ (V0/o,a06)X1n=014 ■ (ilor'o, y%) XIm=0.14 • (,Y%,rjoio) Xkn=0.14 Fig 31. Sample Prognosis Data Plot at 17.2 Bar(a) at 401C & 26.5 MMSCFD. 15 32"d International North Sea Flow Measurement Workshop 21-24 October 2014 mrr2poX"=— (5) mg Equation 5 defines the Lockhart Martinelli parameter. This is a measure of the liquid content of the wet gas flow. Note that m, & ", are the gas and liquid mass flow rates respectively, and pq & Ix are the gas and liquid densities respectively. Figure 31 shows that as the wet gas liquid content increases and decreases the diagnostic points diverge and converge respectively. The data presentation in Figure 31 is not the only way the diagnostic output could be presented. The six diagnostics (yi%,a%), (.i%,y%) & (^q%) may also be plotted relative to the parameter being trended; in this case the Lockhart Martinelli parameter. Figure 32 shows CEESI data for 17.2 Bar(a) at 400C & 26.5 MMSCFD plotted in this way. The data shown in Figure 31 is included in the larger data set shown in Figure 32. Figure 32 shows the orifice meter Prognosis system's sensitivity to wet gas flow. Each of the six diagnostic parameters are sensitive to changes in the liquid loading. As the Lockhart Martinelli parameter increases so does each diagnostic parameter. Figure 32 also indicates that the six diagnostic parameter vs. Lockhart Martinelli parameter relationships have different gradients. That is, the six diagnostics have different sensitivities to liquid loading changes. There are dedicated wet gas meter designs that use a Venturi meter in particular, coupled specifically with the PLR vs. Lockhart Martinelli parameter relationship to make a wet gas liquid loading monitor. The PLR vs. Lockhart Martinelli parameter relationship for this orifice meter is shown in Prognosis via a%. For the case of applying Prognosis to orifice meters, whereas the parameter a% is clearly sensitive to liquid loading, it is not the most sensitive, and therefore not the most useful of the diagnostic parameters for monitoring liquid loading. The most sensitive, and therefore most useful of the orifice meter diagnostic parameters for monitoring liquid loading are the DP ratios related to the recovered DP, i.e. y% & 77%. These two parameters are not only more sensitive to small changes in orifice meter liquid loading than the other parameters (including a%, i.e. the PLR), but also continue to see changes in liquid loading until higher Lockhart 16 30 CEESI 8", 0.689 Beta Orifice Meter Wet Gas Data 20 O d to p N 0.02 0.04 0 0.06 0.00 0.1 0.12 0.14 -10 C C m Q e � o -zo . • }r°10 o a% ❑ -30 ■ i:% ❑ y% Q A 0 A r18/0 -40 Q Lockhart Martinelli Parameter Fig 32. Alternative Prognosis Data Plot at 17.2 Bar(a) at 40°C & 26.5 MMSCFD. The data presentation in Figure 31 is not the only way the diagnostic output could be presented. The six diagnostics (yi%,a%), (.i%,y%) & (^q%) may also be plotted relative to the parameter being trended; in this case the Lockhart Martinelli parameter. Figure 32 shows CEESI data for 17.2 Bar(a) at 400C & 26.5 MMSCFD plotted in this way. The data shown in Figure 31 is included in the larger data set shown in Figure 32. Figure 32 shows the orifice meter Prognosis system's sensitivity to wet gas flow. Each of the six diagnostic parameters are sensitive to changes in the liquid loading. As the Lockhart Martinelli parameter increases so does each diagnostic parameter. Figure 32 also indicates that the six diagnostic parameter vs. Lockhart Martinelli parameter relationships have different gradients. That is, the six diagnostics have different sensitivities to liquid loading changes. There are dedicated wet gas meter designs that use a Venturi meter in particular, coupled specifically with the PLR vs. Lockhart Martinelli parameter relationship to make a wet gas liquid loading monitor. The PLR vs. Lockhart Martinelli parameter relationship for this orifice meter is shown in Prognosis via a%. For the case of applying Prognosis to orifice meters, whereas the parameter a% is clearly sensitive to liquid loading, it is not the most sensitive, and therefore not the most useful of the diagnostic parameters for monitoring liquid loading. The most sensitive, and therefore most useful of the orifice meter diagnostic parameters for monitoring liquid loading are the DP ratios related to the recovered DP, i.e. y% & 77%. These two parameters are not only more sensitive to small changes in orifice meter liquid loading than the other parameters (including a%, i.e. the PLR), but also continue to see changes in liquid loading until higher Lockhart 16 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Martinelli parameters, when the other parameters have gradually become insensitive to the increasing amounts of liquid. Therefore, orifice meters with pressure field monitoring software have been shown to be capable of monitoring changes in wet gas flow liquid loading up to moderate liquid loadings. The Prognosis system's use of alternative DP ratios to the standard singular PLR method used in some Venturi wet gas meter designs has been shown to be advantageous to orifice meters in wet gas flow service. Steven et al (9] reports in detail on the subject of wet gas flow orifice meter pressure field monitoring research. This project is yet another example of how DP meter pressure field monitoring has expanded DP meter capabilities. 4 RUSSIAN GOST APPROVAL FIELD TRIALS As part of the process to attain GOST approval in Russia, STP & IMS organised a Prognosis trial at the ConocoPhilips / Rosneft Polar Lights field. The test meter was a 4" paddle plate orifice meter in a flare gas application (see Figure 33). The available downstream tap was at 6.9D downstream of the plate, i.e. 0.9D downstream of the ideal location. The standard correction factor for the excess pipe length was applied, with an assumption made that the inside pipe condition was typical good quality pipe roughness. The Prognosis software was expanded to include the GOST orifice meter coefficients. The meter under test was assumed to be fully serviceable. ($ Testing took place in January 2014. The Prognosis software received from the flow computer the listed meter geometry (of inlet diameter of 102.26mm and orifice diameter of 44.45mm). The pressure of 2.4 Bar(a) and temperature of 710C produced a gas density of approximately 2 kg/m3. The Prognosis operators chose to set the sensitivity to x = 1%, y = 2.5%, z = 2.5%, a = 3%, b = 3.5%, c = 4.5%, d = 1%. Figure 34 shows the initial Prognosis response. The diagnostics indicated a significant error. The DP check was indicating the DP readings were correct. A list of potential problems that could cause that diagnostic pattern was listed. This included the comment that the orifice diameter may actually be lower than stated in the calculations. The plate was pulled and measured. It was discovered that the true inlet diameter was not 44.45mm as stated in the flow computer, but 38.1mm (i.e. the true beta was 0.3726, not the stated 0.4347). 17 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Tire pattern wrgrions that Lw meter may be over -reading. Possible issues include: Meter throat obstruction Orifice diameter entered falsely high Pipe M entered falsely low Wet gas or liquid carry over Increase in liquid loading (wet gas systems) Problem with Pressure Pon affecting two DPs Problem with one of the DP hrPms (if one DP Current IMlse Data DPt 4282.90 Pa DPr 581.14 Pa DPppl 371180 Pa DPtlnf 429294 Pa DP Sum % Diff erence 0.23 ♦ DPI vs DPppl ( 167, 3.07) ■ DPt vs DPr (-7.02,-13.71) ♦DPr vs DPppl (-634,-996) O OP Sum ( 0.23, 0.00) 0 F Fig 34. Prognosis Response at Polar Lights with Flow Computer Geometry Used. D Meter Afarm [Abrin 3] The pattern suggests a porenfal overreading bias. Possible Issues include: Orifice diameter entered falsely high Pipe 10 entered falsely low Meter contamination or liquid carry-over Meter throat obstruction Problem with Pressure ponaffecting two DPs Problem with one of the DP hiputs(if one OP is Current IrrUse Data DPI 4282.90 Pa DPr 581.14 Pa DPppl 371180 Pa DPtlnf 429294 Pa DPSum%Dltference 0.23 ♦ DPt vs DPppl ( 047, 0,85) ■ DR vs DPr (-2.37,-4.96) ♦ DPrvs DPppl (-214,-3.64) O DPSum ( 0.23, 0.00) —1 Fig 35. Prognosis Response at Polar Lights with Corrected Geometry Used. The archived Prognosis data was re -run using the correct orifice diameter. Figure 35 shows the shift in the diagnostic response. Although the diagnostics points are now much closer to the origin there is still a clear alarm that the meter has a significant problem. The operator therefore checked the meter run. Figures 36 & 37 show the views looking upstream & downstream respectively. The meter run is clearly not compliant with ISO 5167 nor GOST. There is significant weld beads and rust throughout the run. This will cause flow disturbance. DP Diagnostics has tested the effects of flow disturbances on orifice meters (e.g. Steven [2]) and the diagnostic plots presented are very similar to the pattern shown in Figure 35. The diagnostics were correctly indicating that the meter still had a problem. 18 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 iL Fig 36. Upstream Meter Run DP Diagnostics and Swinton Technology noted that this particular problem had not been included in the list of potential problems offered with that diagnostic alarm. With previous test data showing this result (Steven (2)) this was an over- sight and this problem will now be added to the software's list of potential problems. The field test of Prognosis had been successful, if not in the way originally planned. IMS continued to monitor the meter's diagnostic response which subsequently demonstrated consistency in the Prognosis output. 5 DEVELOPMENTS IN DP METER PRESSURE FIELD DYNAMIC RESPONSE The present DP meter diagnostic suite does not directly monitor the time dependent response of the DP signals and the associated diagnostic parameters. The present diagnostics compares either a single result, or a time averaged result from a given set of results recorded over a given period of time, to the fixed expected (calibration or standard) baseline. Time is only considered in the present DP meter diagnostic suite in two indirect ways: the averaging of multiple inputs read over a set span of time to give a single averaged diagnostic output, or, the act of the operator manually playing back, in chronological order, the archived individual diagnostic results in order to check for trending. However, there is further valuable information imbedded in monitoring the three DPs and the associated seven diagnostic checks relative to time. That is, there is value in monitoring both the instantaneous (or averaged) `static' pressure field diagnostic output (as is presently done) and the time dependent dynamic' response of the pressure field diagnostic output. This additional DP meter diagnostic approach can produce further discrimination regarding what adverse operating conditions the DP meter may be exposed to. Monitoring the DP meter's pressure field `dynamic' fluctuations is analogous to the USM's `turbulence' diagnostics. These USM diagnostics monitor the standard deviation (or `stability') of that meter's primary signals, i.e. the variation in time measurements. Likewise, DP meter `turbulence diagnostics' is the monitoring, cross referencing and analysis of the standard deviation (or `stability') of that meter's primary signals, i.e. the read DPs, and the associated diagnostic parameters. 19 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 The DP meter turbulence diagnostic technique is different to the existing DP meter diagnostic techniques in one very significant aspect. The existing diagnostics (reviewed in Section 2) could be described as "absolute diagnostics". Here, the meter output is compared to either a particular physical law, or, a calibration result that is guaranteed to low uncertainties to be the performance characteristic of the correctly operating meter system in the field. Either the metering system output is shown to agree with physical law and / or the guaranteed calibration results, or it does not agree. There is nothing subjective about this type of diagnostic check, It is an absolute pass or fail statement irrespective of any operator's opinion. However, the DP meter turbulence diagnostic methodology does not fall into this category. The DP meter turbulence diagnostic methodology could be described as a "relative diagnostic" method. Here, the system output is compared to the historical system output. There is no output guarantee fixed by either a particular physical law, or by any applicable laboratory calibration result. Unlike absolute diagnostics, relative diagnostics are subjective. Primary DP signal turbulence levels differ (by small to moderate amounts) for different DP flow meters and DP transmitters. Normal turbulence levels for one meter system is not necessarily normal turbulence levels for another nominally identical metering system, even in the same application. If a DP meter has DP signal turbulence levels calibrated at a laboratory, even when using the same DP transmitters the operator has no absolute guarantee that these levels will be representative of the correctly operating meter in the field. Many influences can affect the correctly operating system's DP signal standard deviation, such as different DP transmitters, slight differences in the pipe work etc. The DP meter turbulence diagnostic concept must have its baseline set by recording the values across a known period of actual meter operation in service. This subjective diagnostic method is therefore comparing the relative turbulence of `then and now', which is of course different to the absolute diagnostics comparing precise performance characteristics to absolute known performance requirements. The DP meter turbulence diagnostic method is an eighth DP meter diagnostic check. Unlike the existing seven diagnostics it is subjective, but it does give the meter operator extra useful information. Furthermore, by cross referencing this relative diagnostic method with the existing diagnostic suite it is possible to further distinguish between certain types of DP meter malfunction. The following is a discussion on the DP meter turbulence diagnostic method development and operation. 5.1 Pre -Existing DP Transmitter Internal Diagnostics Most DP transmitters have internal diagnostics. These diagnostics monitor the health of that DP transmitter. However, they are isolated to that DP transmitter. Multiple DP transmitters on a single DP meter do not presently communicate diagnostic results to each other, and they do not give any information with regard to the health of the DP meter system as a whole. No industrial Flow application produces a truly steady flow. Flows that are normally considered steady' have line pressures that vary only very slightly around an average value. The line pressure is typically significantly larger than the DPs produced by a DP meter. Therefore, even a slight rise and fall of pressure over time means that static pressure at each DP meter pressure port rises and falls significantly compared the DP being measured. With normal operation this has no adverse effect as all the meters' pressure ports have the same synchronized rising and falling line pressure. Figure 38 (simplified and exaggerated for clarity) shows a representation of this phenomenon. The high 20 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 and low pressure values at the meter's ports fluctuate in phase with the line pressure and a relatively steady DP with a low standard deviation is read. Figure 39 shows the effect of a pressure port becoming blocked, sealing the fluid in the impulse line at the pressure from when it was sealed. In the example shown in Figure 39 the low pressure port is blocked. The resulting DP reading no longer has the two ports' pressure variations cancelling out. Therefore, the DP's standard deviation becomes significantly higher. ,,Comast DPTransm wSystem Operation / � u — Law Ressure S —HiBa Pressu,e Low Pressure In ulse Llrte Blotl i Trapping Pressure at Set Value — Hgi Preaure L. Rtt.. BrocNeG tlme I nm. Fiq 38. Standard DP Readinq. Fiq 39. DP Readino with Blocked Port Modern DP transmitters compare actual to historical DP standard deviations to monitor for blocked impulse lines. This is a relative diagnostic check. There are various descriptions of this technique available in the literature (e.g. Wehr [10]). When a significant shift in standard deviation is noted, software in the DP transmitter head can check the individual pressure readings. Relative to each other, the more stable pressure signifies a blocked impulse line and the more unstable pressure signifies a clear impulse line. However, when a pressure port is noted as blocked these internal diagnostics cannot tell the operator the correct DP. A variant of the stand alone DP transmitter standard deviation diagnostics is the use of the single DP standard deviation to monitor wet gas flow. Because wet gas flow increases the standard deviation of a DP meter's DP readings, various projects have investigated this. For example, Wehr [11] assumed wet gas flow from the outset, significantly increased the frequency of the DP readings and attempted to relate the single DP transmitter's standard deviations to the wet gas liquid loading. 5.2 New Developments in DP Meter DP Signal Analysis Diagnostics 5.2.1 DP Meter Turbulence Diagnostics & Identifying Blocked Impulse Lines Theory The present DP meter diagnostic suite gives a generic alarm when an impulse line is blocked and the pressure in the impulse line is not representative of the pressure being produced by the pressure field. However, they do not specifically point to that particular problem being the cause of the alarm. The following discussion explains how that can be achieved. Figure 40 shows a simplified theoretical comparison between the three DP fluctuations if the DP meter with a downstream pressure tap is fully serviceable, and when each one of the impulse lines / ports becomes blocked. Moving clockwise around the graphs in Figure 40 shows the effect on the DP readings if for `steady flow' the upstream, downstream or mid -stream (or `throat') impulse lines become blocked. The top left graph shows that the three DP readings have relatively small DP standard deviations (i.e. fluctuations) when the single phase flow DP meter is fully operational. The other graphs show that when one impulse line is blocked the two DP transmitters 21 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 sharing that impulse line will, due to the effect shown in Figure 39, have a significantly increased DP standard deviation. The DP transmitter that does not utilise the blocked impulse line has no change in DP standard deviation. By comparing the relative DP standard deviations it is possible to identify that a particular impulse line may be blocked. No Port Blocked DPt DPr DPppI Upstream Port Blocked N Y C a Time Downstream Port Blocked DPt DPppl Time Fig 40. DP Transmitter Responses to Clear & Blocked Impulse Line Combinations. No internal diagnostics to individual DP transmitters are being used. Prognosis can read the three individual raw DP outputs (of DP transmitters with or without internal diagnostics) and inter -compare the three DP reading standard deviations. This is the inter -comparison of multiple DP transmitter information that has traditionally been kept isolated. This technique can identify a blocked impulse line. By identifying which impulse line is blocked the system also identifies which two impulse lines are serviceable. The associated read DP is confirmed as still valid. Through the appropriate flow equation (see equation set 2 through 4) the flow rate can be predicted. Traditionally, even with modern DP transmitter internal diagnostics, an identified blocked impulse line means the single DP reading is found untrustworthy and the meter system is out of service. This system will allow the meter to continue to operate until maintenance can be carried out. 5.2.2 DID Meter Turbulence Diagnostics & Identifying Wet Gas Flow Single Phase Flow DPt Wet Gas Flow N N E a DPr a DPr DPppI Time Time Fig 41. DP Transmitter Responses to Dry & Wet Gas Flow. The present DP meter diagnostic suite gives a generic alarm when the gas is wet. However, they do not specifically point to wet gas flow being the cause of the alarm. Figure 41 shows a simplified theoretical comparison between the three DP 22 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 fluctuations if the DP meter is encountering dry or wet gas flow. Wet gas flow causes all DP readings to have an increase in standard deviation. A DP meter could identify wet gas flow by comparing the present three DP reading standard deviations to historical dry gas flow baseline data. This then, is a relative diagnostic check. Figure 40 shows the effect on the three DP reading standard deviations if there is a blocked impulse line. Only two of the three DP readings have increased standard deviation. The effects a blocked impulse line and a wet gas flow have on the three DP standard deviations are different and therefore the DP meter relative turbulence diagnostic check could distinguish between the two. 5.2.3 DP Meter Turbulence Diagnostics Test Meter Data 8", 0;889 Beta Orifice Meter, 45 Bar & 49 MMSCFD 120 Throat Pressure Port Blocked at t =1837 sec 100 std dev 0.41 std dev 17.0 v 80 c 60 std dev. 0.12 std dev 0.12 4° 7. std dev 0.27 _ DPt 20—Dppl std dev 17.0 -•- DPr 1800 1820 1840 1860 1880 1900 1920 1940 time (sec) Fig 42. Orifice Meter Response to Blocked Mid -Stream ("Throat") Impulse Line. A CEESI 8", 0.68(3 orifice meter (see Figure 26) was in use with dry natural gas flow at 45 Bar(a) flowing 46 MMSCFD. The traditional, recovered and PPL DPs were read at approximately 84"WC, 38"WC & 46"WC. The standard deviations of these DPs were approximately 0.41, 0.27 & 0.12 respectively. This is shown in Figure 42. Then, at 1837 seconds into the data logging sequence the low pressure port (i.e. the mid -stream pressure port) was blocked by the shutting of a valve on that impulse line. The resulting effect is very obvious. The PPL DP continues to read the same DP at the same low standard deviation. The other two DPs begin to have drifting DPs (that follow the small natural line pressure fluctuation) and their respective standard deviations significantly increase to 17.0. When allowing for the fact that Figure 40 assumed a DP meter like a Venturi meter where the DPr > DPPPL and the orifice meter under tests has the opposite, i.e. DP, < DPPPL, Figure 42 shows the same reaction as expected for the blocked low pressure / midstream pressure port. The maximum & minimum variation of the traditional DP around the correct value of 84"WC is approximately 115"WC, which is a difference of +31"WC / +0.077 Bar, i.e. a line pressure variation of < 0.2%. The DP meter turbulence diagnostic method is very sensitive to blocked impulse lines. 23 32na International North Sea Flow Measurement Workshop 21-24 October 2014 8", 0.69 Beta Orifice Meter 45 Bar, 74 MMSCFD, Dry & then 60 bbls/MMSCFD 2101 200 � DPt (iPIJ' 190 Iso dry std. dev. 0.8 wet std. dev. 5.5 170 160 150 d 140 0 130 120 j{� r 110 100 dry std. dev. 0.24 wet std. dev. 0.58 90 DPr 80 wet std. dev. 1.26 70 dry std. dev. 0.35 700 720 740 760 780 800 820 840 time stamp (sec) Fig 43. Orifice Meter Response to Wet Gas Flow. The same CEESI 8", 0.680 orifice meter (see Figure 26) was tested with dry and wet natural gas flow. Figure 43 shows data at 45 Bar(a) & 74 MMSCFD. With dry gas the traditional, recovered and PPL DPs were read at approximately 172"WC, 96"WC & 76"WC. The standard deviations of these DPs were approximately 0.8, 0.24 & 0.35 respectively. This is shown in Figure 42. Then, at 770 seconds into the data logging sequence the liquid was injected at a rate of 60 bbls/MMSCFD (i.e. Xun of 0.12). As expected the DPs increased. With this wet gas flow the traditional, recovered and PPL DPs were read at approximately 203"WC, 87"WC & 116"WC. The standard deviations of these DPs were approximately 5.5, 1.26 & 0.58 respectively. This is also shown in Figure 42. Again, when allowing for the fact that Figure 41 assumed a DP meter like a Venturi meter where the DP, > DPPPL and the orifice meter under tests has the opposite, i.e. DPr < DPPPL, Figure 43 shows the same reaction as expected for the blocked low pressure / midstream pressure port. The DP meter turbulence diagnostic method is sensitive to, and can potentially identify wet gas flow. For all the DP meter turbulence diagnostic method can potentially identify wet gas flow, this relative diagnostic check is certainly is not as powerful as an absolute diagnostic check. Examples of the standard diagnostics reaction to wet gas flow are shown using data from this same 8" orifice meter in Section 3.5s Figures 31 & 32. Wet gas produces a strong diagnostic pattern that can be recognised as such. However, as this pattern is not unique to wet gas flow (i.e. there are a few meter malfunctions that can cause this pattern) and the addition of the DP meter turbulence diagnostic method can help identify wet gas flow. 24 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 If the operator was to use this relative check alone it is subjective if this is wet gas flow. Notice, that although all three DP values and their standard deviations rose, not all three DPs had similar increases in standard deviation. Whereas the traditional DP's standard deviation increased five fold, and the recovered DP standard deviation quadrupled the permanent pressure loss increased by just two and a half times. If there was no set of absolute diagnostic checks (i.e. the main diagnostics) with which to cross reference, would an operator truly see wet gas here? Or would the operator see a much bigger standard deviation on the traditional and recovered DPs compared to the PPL and falsely assume the relative check is showing a blocked mid -stream / throat impulse fine? This is an example of the reactive diagnostic check methods being subjective. Here, however, we can cross reference this relative check with absolute diagnostic checks. This means we can be reasonably confident of the correct prognosis. 5.2.4 Orifice Meter Turbulence Diagnostics Field Data ConocoPhillips (CoP) installed two Prognosis systems on the Jasmine development. The first system was installed on a 12", 0.6360 orifice meter with a downstream pressure tap 10D downstream of the plate. This first meter was installed on the gas flow leg out of the test separator. The sample data shown here from this meter had a pressure of 62.5 Bar(a), a temperature of 1170C, and a gas density of 44.4 kg/m3. The second system was installed on a 24", 0.6220 orifice meter with a downstream pressure tap 8D downstream of the plate. This second meter was installed on the gas flow leg out of the HP test separator. The sample data shown here from this meter had a pressure of 41 Bar(a), a temperature of 1020C, and a gas density was 30.0 kg/m3. Both orifice meters read the traditional & recovered DPs only. The PPL was inferred meaning the DP check diagnostic was not available. The standard appropriate correction factors for the non-standard downstream pressure tap locations were applied. Due to the high temperature expected ConocoPhillips knew both meters would be metering light water loading wet gas flows. The water content was captured using the Antoine calculation within the flow computer. Figures 44 & 45 show sample Prognosis results from the 12" and 24" orifice meters respectively. The Prognosis output is usually averaged over a period of time to give a clean result. In both these examples the sample data sets were recorded once a minute for three hours. The averaged results are shown on the left. The right hand graphs are the 180 individual results plotted together. Here we see that the minute by minute points are not even approximately steady. The averaged data gives a wet gas over -reading pattern as expected. But the averaging of the data gives perhaps a false view of the stability of the flow. It is only when looking at the 'raw' un -averaged minute by minute data that the unsteadiness of the diagnostic output becomes apparent. There are other orifice meter malfunctions that can cause a similar averaged diagnostic result (e.g. incorrect geometry keypad entry), but these tend to produce a pseudo -steady Prognosis response. The unsteadiness of this response is a strong marker of wet gas flow. The Prognosis co-ordinates are relatively unsteady because the DPs being read from the orifice meter are relatively unsteady, i.e. have a relatively high standard deviation. The traditional & recovered DP are not read at exactly the same time during each data sweep, so the out of phase nature of the DP readings coupled with the fact that both DPs have relatively high fluctuations gives this unsteady result. Note that the progressive data sweeps produced plots randomly in the spread of the data. There was no obvious time dependent pattern to the data. 25 I 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Figure 46 shows the 24", 0.6220 Orifice Meter HP Separator Gas Outlet DP Stability. Note the DPs are relatively unsteady (as shown in Figure 43 for sample laboratory data). If data acquisition was faster here a more rapid DP bounce would be revealed. This CoP Jasmine data shows the principle of DP meter turbulence diagnostic method in practice. DP Diagnostics and Swinton Technology will be adding this patent pending eighth DP meter diagnostic check to the next edition of the DP meter diagnostic software Prognosis'. I* (X1,Y1) E IN (x2,Y2) ♦ (x3,Y3) -------... (-1. 1) (1,-1) i e t Fig 44. Jasmine 12", 0.6360 Orifice Meter Test Separator Gas Outlet Diagnostics. ♦ (x1,yl) ■ (x2,Y2) - — ♦ (x3,y3) ,1) -1) i Fig 45. Jasmine 24", 0.622(3 Orifice Meter HP Separator Gas Outlet Diagnostics. 26 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 Fig 46. CoP Jasmine 24", 0.6220 Orifice Meter HP Separator Gas Outlet DP Stability. 5.2.5 Venturi Meter Turbulence Diagnostics DP Diagnostics / CEESI Laboratory Data Figure 47 shows a DP Diagnostics 6", 0.7(3 Venturi meter undergoing dry and wet gas flow testing at CEESI. Flow is from right to left. Note the three pressure ports and three DP transmitters. This CEESI test facility logged data once every six seconds. • (X"yl ) ■ (x2,Y2) * (x3,y3) C (x4,Y4) A a Net Gas Loop, with Prognosis Result. For a pressure of 35 Bar and a gas flow rate of 4.33 kg/s, Table 3 shows the traditional, recovered and PPL DP averaged values taken from dry and wet gas flow five minute (50 data point) tests. The DP standard deviations for both dry and for wet gas flow are also shown. The wet gas flow had a Lockhart -Martinelli parameter of 0.1 (which is in this case a liquid flow of 2.34 kg/s), which is a GVF of 98.2%. Lockhart -Martinelli Parameter (XLm 0 D Jasmine HP Sep Traditional DPt kPa soap 7.086 Standard Deviation of DPt % 0.142 1.062 asap 4.405 3.912 Standard Deviation of DPr % mm 3.158 PPL DP I kPa 0.353 3.189 35W 3aW % 0.951 2.448 eRl�li 2tW �eR(hj SOCO ssau 3mo soo 0 yid' yJ° B'0 6.pB o v ¢'f sP $ 4 4 ,$ a�'0 e$'� °l°llC• a� & (° (� C°�P' C (•�� s' sl \o1� 0 0+ o�' ° ��os�� � .1� Fig 46. CoP Jasmine 24", 0.6220 Orifice Meter HP Separator Gas Outlet DP Stability. 5.2.5 Venturi Meter Turbulence Diagnostics DP Diagnostics / CEESI Laboratory Data Figure 47 shows a DP Diagnostics 6", 0.7(3 Venturi meter undergoing dry and wet gas flow testing at CEESI. Flow is from right to left. Note the three pressure ports and three DP transmitters. This CEESI test facility logged data once every six seconds. • (X"yl ) ■ (x2,Y2) * (x3,y3) C (x4,Y4) A a Net Gas Loop, with Prognosis Result. For a pressure of 35 Bar and a gas flow rate of 4.33 kg/s, Table 3 shows the traditional, recovered and PPL DP averaged values taken from dry and wet gas flow five minute (50 data point) tests. The DP standard deviations for both dry and for wet gas flow are also shown. The wet gas flow had a Lockhart -Martinelli parameter of 0.1 (which is in this case a liquid flow of 2.34 kg/s), which is a GVF of 98.2%. Lockhart -Martinelli Parameter (XLm 0 D 0.1 Wet Traditional DPt kPa 4.752 7.086 Standard Deviation of DPt % 0.142 1.062 Recover DPr kPa 4.405 3.912 Standard Deviation of DPr % 0.154 3.158 PPL DP I kPa 0.353 3.189 Standard Deviation of DP I % 0.951 2.448 Table 3. DP Diagnostics 6", 0.7(3 Venturi Meter Data from CEESI Flow Tests. Figure 47 shows the standard Prognosis response to wet gas flow. The diagnostics are so sensitive to this moderate wet gas flow through a Venturi meter that the NDB is shrunk to a dot on the origin. The liquids presence causes the DPs to change and substantially increases all three DP standard deviations. This is an example of the Venturi meter DP standard deviations reacting to wet gas flow in a 27 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 similar way to the orifice meter (e.g. see Figure 43). This is another example of DP meter turbulence diagnostics. The existing diagnostic result in Figure 47 is averaged data and the pattern is the pattern produced by wet gas. However, the pattern is not unique to wet gas flow. There are a few other problems that could cause such a pattern. However, wet gas has the added signature of high standard deviation DPs. By combining the existing diagnostic suite and DP meter turbulence diagnostics it is possible to identify wet gas as the more likely causes of the issue than issues that create relatively stable DPs. However, just as was shown for the orifice meter, if the operator was to use this relative check alone it is subjective if this is wet gas flow. As with the orifice meter example all three Venturi DP standard deviations rose, but they did not have proportional increases. The traditional DP's standard deviation increased seven fold, the recovered DP standard deviation increased twenty fold, but the PPL standard deviation only slightly more than doubled. If there was no set of absolute diagnostic checks (i.e. the main diagnostics shown in Figure 47) with which to cross reference, would an operator truly see wet gas here? Or would the operator see a much smaller standard deviation on the PPL DP and falsely assume the relative check is showing a blocked mid -stream / throat impulse line? This is another example of the reactive diagnostic check methods being subjective. With Prognosis, however, we can cross reference this relative check with absolute diagnostic checks. This means we can be confident of the correct diagnosis. 5.2.6 Comparing Wet Gas & Blocked Impulse Line DP Standard Deviations Section 5.2.3 showed the response of an 8", 0.6890 orifice meter to a blocked impulse line (see Figure 42) and a wet gas flow (see Figure 43). It was then shown that if the DP meter turbulence diagnostic method was applied alone (without cross referencing this diagnostic with the existing diagnostic suite) it may be difficult to distinguish between a rise in DP standard deviations due to wet gas flow and due to a blocked impulse line. It is by cross referencing the existing diagnostic suite with this DP meter turbulence diagnostic method that produces a genuine advance. However, there is one other analysis technique that could improve the DP meter turbulence diagnostic method here. That is, take account of not just the relative magnitude of the 3 DP standard deviations but also the period of these DPs fluctuation. o Blocked Impulse Line 15 �i ❑ r' �ti� f f ca � /V V_,V� V V V � time V5 CL a Wet Gas Flow Fig 48. Different DP Meter Problems Produce Different DP Fluctuations. Most relatively steady gas flows have a line pressure that can rise and fall by a fraction of a percent over time. This variation in pressure is usually a long period / low frequency phenomenon that produces a relatively large DP fluctuation. Therefore, if a DP meter impulse line is blocked the variation in DPs associated with that impulse line will have a corresponding relatively large magnitude low frequency / long period fluctuation. Most relatively steady wet gas flows have DPs 28 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 that rise and fall by a few percent over time. This DP variation is caused by the relatively chaotic flow. This variation in DP is therefore a relatively small magnitude short period / high frequency phenomenon. This phenomena is evident when comparing Figure 42 for a dry gas blocked impulse line and Figure 43 for wet gas flow. Figure 48 shows a sketch highlighting this point. As this DP meter turbulence diagnostic method develops, the frequency / phase information can be taken into account to help distinguish between different problems. DP meter turbulence diagnostics that monitor not just the magnitude of the DP signal standard deviations, but also other information such as the period of the fluctuations, have an analogy with multiphase meter designs that use artificial intelligence / neural networks (e.g. Toral [12]). There is no technical reason why similar artificial intelligence / neural networks could not be developed for single phase meter diagnostics. However, there is a law of diminishing returns. Such a development would take a very considerable undertaking in time and in R&D costs and likely result in real but marginal gains in diagnostic prediction power. Currently DP Diagnostics and Swinton Technology are concentrating on simpler direct analysis of DP signal fluctuations as it has been shown that such a development offers an immediate and significant increase in the diagnostic suite's capability. 6 CONCLUSIONS DP meter diagnostics based on pressure field monitoring is now becoming widely accepted by the natural gas production industry. As a result of this the software `Prognosis' is now used by multiple operators and is being tested by 3rd parties, including STP & IMS in Russia. Industry is now becoming comfortable enough with the pressure field monitoring concept that it is not only being considered for generic DP meter diagnostics but also for developing new DP meter capabilities. In the last three years DP meter pressure field monitoring has been researched, and proven useful, for use with various adverse flow conditions that are traditionally challenging for all flow meter technologies. These research projects include the use of DP meters with pressure field monitoring to monitor: • contamination levels of DP meter runs, • erosion levels on multiphase meters, • oil with water flow metering, • heavy oil (high viscosity) Flow, • high content CO2 natural gas / CO2 mixtures, and • wet gas flow. The existing generic DP meter pressure field monitoring diagnostic suite is a very capable diagnostic tool. This existing diagnostic suite (without DP meter turbulence diagnostics) allows the system to identify a DP meter malfunction. The particular diagnostic pattern (i.e. combination of all diagnostic results together) which shows a meter malfunction also allows a 'short list' of potential problems to be produced, whilst discounting the malfunctions that could not produce that pattern. DP Diagnostics and Swinton Technology are continuing to develop and strengthen this diagnostic system. The addition of DP meter turbulence diagnostics will allow further discrimination of the diagnostic result. The present short list of possible malfunctions that could produce that diagnostic pattern will be further reduced as DP meter turbulence diagnostics rule out certain possibilities on that list and highlights others as still possible. 29 Mein Menu 32nd International North Sea Flow Measurement Workshop 21-24 October 2014 DP meter diagnostics have advanced significantly over a relatively short period of time. However, the possibilities offered by pressure field monitoring are so wide and diverse that it is expected that the DP meter diagnostic suite will continue to expand and improve steadily for the foreseeable future. 7 REFERENCES 1. Steven, R. "Diagnostic Methodologies for Generic Differential Pressure Flow Meters", North Sea Flow Measurement Workshop, October 2008, UK. 2. Steven, R. "Significantly Improved Capabilities of DP Meter Diagnostic Methodologies", North Sea Flow Measurement Workshop, October 2009, Norway. 3. Skelton M. et al, "Developments in the Self -Diagnostic Capabilities of Orifice Plate Meters", North Sea Flow Measurement Workshop, October 2010, UK. 4. Rabone J. et al, "DP Meter Diagnostic Systems - Operator Experience", North Sea Flow Measurement Workshop, October 2012, UK. 5. Cousins T. et al, "The Emperor's New Clothes - Oil with Water Metering?", North Sea Flow Measurement Workshop, October 2013, Norway. 6. Brown G. et al, "The Effect of Flow Conditions on Ultrasonic Meters in Low Velocity Oil / Water Flows", 6d' International South East Asia Hydrocarbon Flow Measurement Workshop, March 2007 7. Kegel T., et al "Coriolis Meter Testing Under Variable Water Cut, Oil Water Conditions", North Sea Flow Measurement Workshop, October 2014, UK. 8. Rabone J., et al "Prognosis Applied to High Viscosity Flows", South East Asia Hydrocarbon Flow Measurement Conference, March 2013. 9. Steven R., et al "Expanded Knowledge on Orifice Meter Response to Wet Gas Flow", North Sea Flow Measurement Workshop, October 2014, UK. 10. Wehr D. "Detection of Plugged Impulse Lines Using Statistical Process Monitoring Technology", Emerson Process Management, Rosemount Inc., website: h tto: //www2. emersonorocess. com/en -us/bran ds/rosemou nt/oressu re/oressu re- transmitters/3051s-advanced-diagnostics/Panes/index.asox 11. Wehr D. "Wet Gas Diagnostics with Intelligent Differential Pressure Transmitter", Emerson Process Management, Rosemount Inc., website: htto•//www2 emersonorocess com/en-us/brands/rosemount/pressure/oressure- transmitters/3051s-advanced-diagnostics/Pages/index.asox 12. Toral H., et al "Characterization of the Turbulence Properties of Wet Gas Flow in a V -Cane Meter with Neural Nets", North Sea Flow Measurement Workshop, October 2004, UK. 30 Anchorage Office • 3900 C SL suile 801 • Anchorage. Alaska 995035963 • 907.33. arctic .5">e ® regional corporation Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 JO • FAX 907.339.6028 • 1.800.770.2772 RE: Docket OTH-16-005 ASRC Comments to AOGCC Regarding Metering at Greater Moose's Tooth #1 Dear Ms. Foerster: Arctic Slope Regional Corporation (ASRC) urges AOGCC to approve ConocoPhillips Alaska, Inc. (COP) proposed hydrocarbon and production measurement and allocation system for Greater Moose's Tooth #1 (GMT1), the first drillsite within the Greater Moose's Tooth Unit (GMTU), located in the National Petroleum Reserve - Alaska (NPRA). ASRC is the majority mineral owner of the proposed Lookout Participating Area, the initial development from the GMT1 drillsite, and therefore has a significant economic interest in the GMT1 development. ASRC is also a co -manager, with the Bureau of Land Management and therefore has standing with respect to decisions regarding production measurements and allocations methodologies utilized at GMT1. ASRC's reasons to justify approval for the requested waiver are as follows: • ASRC has been actively involved in the technical discussions to meet the BLM metering requirements for GMT1 and we feel that COP has adequately presented its justification and methodology to BLM. • To optimize economic recovery, Greater Moose's Tooth Unit (GMTU) is designed as a satellite drillsite that will be produced through the Colville River Unit (CRU) Alpine Central Facility (ACF). Fluids produced at GMT1 will be measured through a 3-phase production separator that will allow for continuous measurement using a Coriolis meter and water cut analyzer. After separation, Fluids will be recombined and delivered to the ACF through a three phase pipeline system from GMT1 to the CD5 drill site in the CRU. • ASRC understands that the proposed production allocation system proposed by COP is different from what we are accustomed to in the CRU. As a mineral owner and Unit manager in the adjacent CRU ASRC is intimately familiar with the CRU allocation methodology and has been party to multiple redeterminations of production and allocation in the CRU since its start-up in 2000. We are also comfortable with the high-pressure separator and continuous metering approach proposed for GMT1. With recombination of GMT1 fluids prior to reaching the ACF, the GMT1 Fluids will have an effective allocation factor of 1.0 at the CRU LACT meter. Corporale Headquarters • PO Box 129 • Borrow, Alaska 99 72 3-01 29 • 907.852.8533 or 907.852.8633 • FAX 907.852.5733 • The designed oil measurement system meets both AOGCC standards for the CRU, a State and ASRC jointly managed unit, and BLM standards for the GMTU, a federal and ASRC jointly managed unit, without economic waste. ASRC has no objection to the proposal for off -unit measurement of CRU gas at GMTU. • ASRC feels that any effect on State royalty through the CRU allocation methodology will be minimal and will be offset by the benefit of having more gas delivery to the CRU from GMT) for enhanced oil recovery efficiency. • ASRC is a mineral owner in both CRU and GMTU. As such ASRC currently receives royalty from production in the CRU and will receive royalty from GMT1. The State of Alaska currently receives royalty from production from the CRU and is entitled to receive 50% of the federal royalty from GMT). • Whether or not the proposal is deemed to meet the API standard adopted in 20 AAC 25.228(b), ASRC feels that approval of the metering system is certainly within the AOGCC's authority to adapt orders to provide for the metering of oil and gas under AS 31.05.030(c)(6). ASRC feels that COP has a metering design that protects royalty interests in both units. Thank you for your time and consideration of our comments.. Sincere) Iresa m Senior Vice President Resource Development 2 4 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Wednesday, June 01, 2016 1:14 PM To: Viator, Brandon S (Brandon.S.Viator@conocophillips.com) Cc: Colombie, Jody J (DOA) Subject: RE: Extension of deadline to submit additional information for Docket CO 16-005 Brandon, the referenced docket above should be 0TH 16-005, not CO 16-005. Dave Roby (907)793-1232 CONFIDENTIALITY NOTICE., This e-mail message, including any atlachmenis, contains information from the Alaska Oil and Gas Conservation. Commission (AOGCC), State of Alaska and is for the sole use of the intended recipfent(s). II may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violale state or federal law. If you are an unintended recipient of this e-mail, please delele it without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.aov. From: Roby, David S (DOA) Sent: Wednesday, June 01, 2016 11:16 AM To: Viator, Brandon S (Brandon.S.ViatorCabconocophillips.com) Subject: Extension of deadline to submit additional information for Docket CO 16-005 Brandon, The Commissioners have extended the deadline for providing the additional information requested at the May 3, 2016, hearing on the above referenced docket to the close of business on Friday June 10th. Regards, Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete if, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending i1 to you, contact Dave Roby at (907)793-1232 or dave.roby@alaska.gov. 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: Cathy Foerster, Chair 3 Daniel T. Seamount 4 In the Matter of the Application of ) 5 ConocoPhillips, Alaska, Inc., for a Waiver ) 6 of the requirements of 20 AAC 25.228(a) to ) 7 allow for final custody transfer metering ) 8 of hydrocarbons sold from the Greater ) 9 Mooses Tooth unit to occur off unit and to ) 10 allow for the final custody transfer ) 11 metering of gas sold from the Colville ) 12 River unit to the Greater Mooses Tooth ) 13 unit to occur after the gas is severed from ) 14 the Colville River unit. ) 15 ) 16 Docket No.: OTH16-005 17 ALASKA OIL and GAS CONSERVATION COMMISSION 18 Anchorage, Alaska 19 May 3, 2016 20 9:00 o'clock a.m. 21 PUBLIC HEARING 22 BEFORE: Cathy Foerster, Chair 23 Daniel T. Seamount 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Mr. Goltz 4 Remarks by Mr. Viator 5 Remarks by Ms. Hosack 2 M 11 19 I P R O C E E D I N G S 2 9:04:04 3 (On record - 9:01 a.m.) 4 CHAIR FOERSTER: I'll call this hearing to 5 order. Today is May 3, 2016, it is 9:01 a.m. We are 6 in the offices of the Alaska Oil and Gas Conservation 7 Commission at 333 West Seventh Avenue in Anchorage, 8 Alaska. To my left is Dan Seamount, I'm Cathy 9 Foerster. 10 Today's hearing is on docket number OTH 16-005, 11 the Application of ConocoPhillips, Alaska, Inc., for a 12 waiver of the requirements of 20 AAC 25.228(a) to 13 provide custody transfer measurement of hydrocarbons 14 prior to severance from the lease or unit. 15 ConocoPhillips, Alaska by letter dated February 26, 16 2016 requests the Alaska Oil and Gas Conservation 17 Commission issue a waiver from the requirements of 20 18 AAC 25.228(a) to allow for final custody transfer 19 metering of hydrocarbons sold from the Greater Mooses 20 Tooth unit to occur off unit and to allow for the final 21 custody transfer metering of gas sold from the Colville 22 River unit to the Greater Mooses Tooth unit to occur 23 after the gas is severed from the Colville River unit. 24 Computer Matrix will be recording today's 25 proceedings and you can get a copy of the transcript 3 1 from them. 2 We have three people from Conoco who intend to 3 testify today. Are there any other parties planning to 4 testify? 5 (No comments) 6 CHAIR FOERSTER: Okay. If you're testifying 7 please keep in mind that you must speak into the 8 microphones so that the people in the back of the room 9 can hear you and so that the court reporter can capture 10 what you say. And please remember to reference your 11 slides so that someone reading this record 10 years 12 form now will understand what you're referring to. So 13 if the slides are numbered as you go to a new slide say 14 now we're looking at slide number 1, you know, for 15 example or if they're not a title would be fine. 16 I don't need to read the ground rules for the 17 misbehavers, do I, do we have any misbehavers in the 18 audience. Okay. Well, we'll just skip those then. 19 Dan, do you have anything to add? 20 COMMISSIONER SEAMOUNT: Question, how much time 21 are you going to take in your testimony today do you 22 estimate? 23 MR. GOLTZ: Half an hour maybe..... 24 COMMISSIONER SEAMOUNT: Okay. 25 MR. GOLTZ: .....or maybe 45 minutes. El 1 CHAIR FOERSTER: Okay. And is any of the 2 testimony confidential? 3 MR. GOLTZ: No. 4 CHAIR FOERSTER: Thank you. All right. I 5 assume you are the three Conoco folks that will 6 testify. 7 MR. GOLTZ: Yes. 8 CHAIR FOERSTER: So let's swear you all in 9 together. If you would say your name for the record 10 just one, two, three and then I'll do the swear in. 11 MR. VIATOR: Brandon Viator. 12 MS. HOSACK: Jody Hosack. 13 MR. GOLTZ: And Jon Goltz. 14 CHAIR FOERSTER: Is your mic on? 15 MR. GOLTZ: It's on. 16 CHAIR FOERSTER: Okay. Thank you. Raise your 17 right hand. 18 (Oath administered) 19 MR. GOLTZ: I do. 20 MS. HOSACK: I do. 21 MR. VIATOR: I do. 22 CHAIR FOERSTER: Okay. Well, let's start with 23 the first person who wants to testify and do you want 24 to be recognized as an expert in any area..... 25 MR. GOLTZ: No. 1 CHAIR FOERSTER: .....that's relevant today? 2 Okay. Then just give your name, who you represent and 3 proceed with your testimony. 4 MR. GOLTZ: Okay. Thank you and good morning. 5 My name is Jon Goltz, my last name is spelled G -O -L -T- 6 Z. I'm in-house legal counsel for ConocoPhillips, 7 Alaska. And as already mentioned I have with me at the 8 table are Brandon Viator and Jody Hosack. I'll suggest 9 that they be qualified as experts to speak to 10 substantive issues right after my brief introductory 11 remarks. 12 In the audience we also have with us another 13 ConocoPhillips employee, Bob Peebles, who could be 14 available to testify on specific technical issues if it 15 turns out that those are of interest to the 16 Commissioners. 17 We are here to support ConocoPhillips' 18 application for approval of a proposed system for 19 measuring oil and gas production from the planned GMT1 20 development and as an ancillary matter gas that will 21 flow from the Colville River unit to the GMT1 22 development in the Greater Mooses Tooth unit. Our 23 application addresses the standards for custody 24 transfer that are codified at the Commission's 25 regulation at section 228 and we will speak to those rl 1 standards here today. As the technical standards -- 2 experts will explain the standards adopted in section 3 228 apply to custody transfer measurement of pipe line 4 quality oil downstream of processing facilities. Our 5 plan is to measure live oil upstream of processing 6 facilities and we therefore ground our request not just 7 in section 228 because we do believe we meet most and 8 arguably all of those standards, but also in Alaska 9 statute 31.050.30, subsection (c), under which the 10 Commission has the authority to issue orders 11 appropriate to carry out the Alaska Oil and Gas 12 Conservation Act including measurement of oil and gas. 13 Our proposal is in some ways similar to the 14 Oooguruk unit where oil and gas are measured prior to 15 processing at the Kuparuk River unit facilities, 16 although we are proposing a different kind of 17 measurement system than Oooguruk. We intend to show 18 that our proposal involves a robust, accurate method 19 for measuring GMT1 production before it gets commingled 20 with CRU production and is processed in CRU facilities. 21 The key bit of context which our project integration 22 manager will address is that GMT1 is a modest 23 development that would not on its own support the 24 development of processing facilities. 25 We want to acknowledge that the Commission has 7 1 adopted a guidance bulletin that we are aware of 2 describing information required for measurement 3 approval and that requires some detailed information 4 such as serial numbers on specific equipment that is 5 not available today. But we are seeking approval now 6 so that we can proceed with the engineering and 7 procurement for the project. Brandon will speak to the 8 schedule that we have. 9 Finally as you know the Greater Mooses Tooth 10 unit is a federally administered unit, administered by 11 the BLM and they have a regulatory role here too. 12 ConocoPhillips has worked with both the BLM staff and 13 the AOGCC staff going back as far as 2013 to come up 14 with a metering system that we think is both 15 economically viable and approvable by both the BLM and 16 the AOGCC. Our applications for approval are 17 simultaneously pending before both regulatory agencies. 18 So unless the Commissioners have any questions 19 about these introduction remarks, Brandon Viator will 20 proceed with an overview of our proposed system. 21 CHAIR FOERSTER: Do you have any questions, 22 Commissioner Seamount? 23 COMMISSIONER SEAMOUNT: I have none. 24 CHAIR FOERSTER: Okay. Nor do I. So, Mr. 25 Viator, what area would you like to be recognized as an N I expert in? 2 MR. VIATOR: Oil and gas developments. 3 CHAIR FOERSTER: Okay. Engineering? 4 MR. VIATOR: Yes, ma'am. 5 CHAIR FOERSTER: Okay. So give us your 6 qualifications, education, your experience that..... 7 MR. VIATOR: I have a bachelor's degree in 8 chemical engineering from Texas A&M University and I've 9 been working in the oil and gas industry for 15 years 10 all of which has been with ConocoPhillips. I'm a 11 licensed professional engineer and I'm also a certified 12 project management professional. I've been..... 13 CHAIR FOERSTER: Is your license in Alaska? 14 MR. VIATOR: No, ma'am, it is in Texas. 15 CHAIR FOERSTER: Texas. Okay. So was mine.f 16 MR, VIATOR: I have worked both domestic and 17 international assignments holding roles as process 18 engineer, project engineer, project manager, asset 19 manager and project integration manager all prior to my 20 current role which is the project integration manager 21 for the Greater Mooses Tooth unit. And in the last 10 22 years I've been working on oil and gas developments in 23 those roles. 24 CHAIR FOERSTER: All right. Commissioner 25 Seamount, do you have any questions for this Aggie? W 1 COMMISSIONER SEAMOUNT: I have none. I -- and 2 I have no complaints considering he went to the better 3 school. 4 CHAIR FOERSTER: I don't have any problems 5 either and we recognize you as an expert in project 6 development engineering so please proceed with your 7 testimony and don't forget about identifying your 8 slides. 9 MS. HOSACK: May I go ahead and qualify as an 10 expert now as well? 11 CHAIR FOERSTER: Oh, you might as well. Go 12 ahead. 13 MS. HOSACK: So my name is Jody Hosack, I am 14 ConocoPhillips' instrumentation and flow measurement 15 technical authority. I'd like to be qualified as an 16 expert in instrumentation and flow measurement. So I 17 have a bachelor's of science degree from -- with -- in 18 control systems engineering from Montana Tech of the 19 University of Montana. I'm also a registered 20 professional engineer in the state of Alaska. I've 21 worked in the Alaska oil and gas industry for 18 years 22 the last eight of which have been ConocoPhillips. And 23 I've held the instrumentation and flow measurement 24 technical role -- technical authority role for the last 25 six years. 10 1 CHAIR FOERSTER: Who were you with before 2 Conoco? 3 MS. HOSACK: I was with various engineering 4 firms that supported the oil and gas industry up here 5 in Anchorage. 6 CHAIR FOERSTER: Okay. Commissioner Seamount, 7 do you have any questions? 8 COMMISSIONER SEAMOUNT: I have no questions 9 or..... 10 CHAIR FOERSTER: Nor do I. We're both 11 comfortable with both of you as experts in those areas. 12 BRANDON VIATOR 13 previously sworn, called as a witness on behalf of 14 ConocoPhillips, Alaska, testified as follows on: 15 DIRECT EXAMINATION 16 MR. VIATOR: Thank you. So we'll start with 17 slide three which is the agenda to give you a brief 18 overview of what we'll talk about today. I'll go 19 through a quick background on the GMT1 project in 20 measurement design and then we'll touch on the key 21 highlights that we would like to discuss regarding the 22 metering application. We'll then go through the key 23 regulations that we believe apply that Jon mentioned in 24 his opening and touch on the elements of our design 25 which may not strictly conform with the rules as 11 1 they're written. And then we will go through the 2 economic analysis of installing a production facility 3 at GMT1 and then wrap things up with a status of where 4 we are in the project and summary of today's 5 discussion. 6 So moving to slide number 4, to start out with 7 a high level overview in the map you'll see the various 8 units across the North Slope. The units that are 9 highlighted in bold lettering are ones where 10 ConocoPhillips has a working interest and the two that 11 we'll be discussing today are colored in the darker 12 color as the Greater Mooses Tooth unit and the Colville 13 River unit. Also noted on the map is the NPR-A line 14 noted by the black and white dashed line that runs 15 vertically through the map. 16 I'm not going to run through all the points on 17 the bottom of this slide, but wanted to highlight a few 18 key items. That this is the first development for the 19 Greater Mooses Tooth unit and we are leveraging off of 20 the Alpine existing infrastructure and the CD5 design 21 work. The construction seasons for the Greater Mooses 22 Tooth unit are envisioned to span two seasons starting 23 at the end of this year in the fourth quarter of 2016 24 and then again the next winter in 2017 running through 25 2018 with an expectation of first oil in December, 12 1 2018. 2 The next slide is slide number 5 and what we 3 wanted to do is highlight the ownership and working 4 interests for the CRU and the Greater Mooses Tooth 5 unit. So on the top of the slide and on the right in 6 blue are highlighting the Colville River unit and in 7 green on the bottom is the Greater Mooses Tooth unit. 8 So I'll start with the working interest owners are well 9 aligned in both units with ConocoPhillips and Anadarko 10 being the primary owners or working interest owners 11 with the caveat being in the Colville River unit for 12 the CD3 development Petro -Hunt does have a small 13 working interest and that is less than one-tenth of one 14 percent. 15 So on the Colville River unit starting with the 16 map on the top right the lands noted in yellow are 17 lands that are -- where the state of Alaska owns the 18 surface and subsurface rights. on the bottom left the 19 small portion of lands in the southwest of the Colville 20 River unit are BLM lands where they own surface and 21 subsurface. To the right of that, primarily in the 22 east of the unit we have lands in brown with the hash 23 marks that run from the bottom left to the top right 24 are owned by Kuukpik on the surface and ASRC on the 25 subsurface. And then that leaves us with the lands in 13 1 the middle with the hashmarks that are running from the 2 top left to the bottom right where they are owned by 3 Kuukpik on the surface, but a mixture of ASRC and state 4 for the subsurface. 5 In the Greater Mooses Tooth unit we have the -- 6 in the blue boxes are the BLM lands owned as surface 7 and subsurface and then the boxes in brown are to 8 denote the selected or conveyed lands that are owned by 9 the Kuukpik on the surface and ASRC on the subsurface. 10 So moving on to slide number 6 we are proposing 11 today a measurement design that has evolved through 12 multiple discussions with various stakeholders 13 including state and federal agencies that has resulted 14 in a design of a three phased production separator and 15 associated metering that we believe achieves a high 16 level of hydrocarbon measurement accuracy within a cost 17 that allows the GMT1 project to remain viable. Our 18 design also allows for the efficient use of existing 19 infrastructure that helps us to reduce cost and limit 20 the gravel footprint, air emissions and other 21 environmental impacts. The proposed design is also 22 consistent with the 2012 NPR -A integrated activity plan 23 EIS where GMT1 was evaluated as a satellite development 24 relying on the Alpine central facilities for processing 25 and it also complies with the IAP stipulation E-5 14 1 requiring the sharing of facilities with existing 2 development in order to minimize project footprint. 3 Moving on to slide number 7, this slide is 4 intended to give an overview of the relationship 5 between the two units and how the measurement is 6 arranged. The green ovals are to note where we had 7 measurement taking place. 8 And we'll start with the Greater Mooses Tooth 9 unit and the three phase production separator where we 10 will have measurement for the oil, the gas and the 11 water. And we consider this to be the point of custody 12 transfer. Those fluids will be then recombined after 13 measurement and travel to the Colville River unit where 14 they will be commingled with fluids from CD5, CD4, CD2, 15 CD3 and CD1, all being processed at the Alpine central 16 facility. At this facility the production fluids will 17 be stripped of their gas and water where the oil can be 18 stabilized and then that oil will be sold and go on to 19 the Alpine pipe line which will eventually make its way 20 to TAPS. 21 From the CRU we will have gas and water that 22 will be sent back to the Greater Mooses Tooth unit. 23 The gas will go in two separate lines, one carrying the 24 fuel gas and lift gas or used as fuel gas and lift gas 25 and the other line used as miscible injection gas. 15 I Those will then be metered whenever they arrive on the 2 unit. And then the lift gas and fuel gas will then 3 each individually be measured as they split and go to 4 their respective users. The water will also be 5 measured at the Greater Mooses Tooth unit. 6 Part of highlighting in this chart is to show 7 the off lease measurement of the gas which is one of 8 our requests for waiver. The other item to here is as 9 this being the point of custody transfer is the 10 envision that, you know, this is essentially receiving 11 an allocation factor of one where the Greater Mooses 12 Tooth unit will be kept whole in relation to the LACT 13 metering at the CRU. 14 Moving on to slide number 8 we have a 15 simplified process flow diagram of the three phase 16 separator. So I'll start with the orange lines coming 17 off the top which are the gas. We have dual gas 18 measurement with two different size (indiscernible) 19 meters, four inch and six inch, to allow us to capture 20 the range of production that could come through the gas 21 side for those will be measured. And then coming off 22 the middle we have the oil leg that will go through or 23 have a slipstream for the composite sampler. There 24 will also be a Phase Dynamics water cut meter on that 25 line to measure the oil -- the water in oil and then 16 1 those streams will go through the Coriolis meters, dual 2 meters, both four inch. And then coming off the bottom 3 of the three phase separator we have the water leg that 4 will go through a mag meter and be measured. And then 5 all three fluids will be recombined going into our 6 production line that will be sent on to CD5 and then 7 eventually to the Alpine central facility. 8 The next slide is slide number 9. This slide 9 is to give a little bit more detail into what happens 10 at the Alpine central facility. The lines that are 11 noted in the dotted lines in various colors indicate 12 where there's -- the project is in development and not 13 in service yet and then the solid lines are for 14 everything that is in service. I've highlighted here 15 where -- the Lookout PA which is associated with the 16 Greater Mooses Tooth 1 development. Also a note of 17 reference at the bottom. In slide number 20 there is a 18 reference with all the acronyms and also a table that 19 shows which PAs belong to which drill sites. 20 So starting with the inlet separator we have 21 all of the production from the various drill sites 22 commingling and coming into the Alpine central facility 23 into an inlet separator. Those fluids then -- you have 24 the gas phase coming off the top which will go through 25 additional gas processing and gas enrichment. And then 17 1 that gas will then either be sent as gas enrichment 2 back to the PAs or be used as lift gas and injection 3 gas also coming back to the PAs and those lines are 4 noted in red. 5 The liquid line from the inlet separator then 6 goes through oil processing where the water will be 7 dropped out and the oil stabilized. The oil and the 8 condensate from the stabilizer will then be sent on to 9 the sales meter and on to the Alpine pipe line. The 10 water does have the ability to switch between produced it water and seawater being sent back to the different 12 drill sites so we do have an inlet supply of seawater 13 into the Alpine central facility noted in the line 14 coming across the top and then we have the flexibility 15 to send either produced water or seawater back to the 16 drill sites depending on our needs. But the blue line 17 show going back to each of the drill sites. 18 CHAIR FOERSTER: So what do NK, FN and FK stand 19 for? 20 MR. VIATOR: So those are also defined on that 21 reference sheet in the back, but this is..... 22 CHAIR FOERSTER: I didn't see them there. 23 MR. VIATOR: There's a -- it's within the 24 table. So this is Nanuq..... 25 CHAIR FOERSTER: Oh, gotcha. IU 1 MR. VIATOR: .....Nanuq Kuparuk..... 2 CHAIR FOERSTER: Okay. 3 MR. VIATOR: .....for NK, Fiord Nechelik for REWWOM 5 CHAIR FOERSTER: Thank you. 6 MR. VIATOR: Okay. Any other questions before 7 I move on? 8 (No comments) 0 JODY HOSACK 10 previously sworn, called as a witness on behalf of 11 ConocoPhillips, testified as follows on: 12 DIRECT EXAMINATION 13 MS. HOSACK: For slide 10 I'd like to briefly 14 discuss the differences between LACT quality 15 measurements of stable fluids and that of the 16 measurement of live fluids. So for -- in order to get 17 LACT quality measurement at GMT1 we would require a 18 processing fluid or processing facility to get to 19 stable fluids. And then stable fluids are converted 20 from a observed volume to a -- to standard conditions 21 or a standard volume through the application of a 22 volume correction factor. API, they have developed 23 these empirical values and they're standardized in API 24 MPMS, chapter 11. For GMT1 with the use of a three 25 phase separator we're actually proposing single phase, 19 1 live oil measurement at the drill site. Live oil is 2 oil that -- or live fluids are oil that's at elevated 3 pressures and temperatures and at GMT1 it would not 4 have gone through any other processing other than the 5 three phase separator. 6 Live fluids are converted from observed volumes 7 to standard volumes through the application of a 8 shrinkage factor. Shrinking factors account for the 9 loss of light in hydrocarbons based on phase change or 10 the volume changes that are associated with volt, 11 pressure and temperature affects on the fluids. The 12 shrinkage factors are derived from PBT testing or 13 equations of state modeling and the application of the 14 shrinkage factor, this last bullet on slide 10, it 15 actually contributes approximately 2 percent to the 16 overall measurement uncertainty for our proposed 17 application. And because of this the application of 18 the shrinkage factor is actually the largest 19 contributor to that uncertainty calculation that was 20 provided in the application. 21 So for slide 11 this illustrates the flow 22 calculation sequence that would be implemented in the 23 flow computer at GMT1. Starting at the top we have the 24 mass output of the Coriolis meters. Once you've 25 combined that with the observed densities from the no] I Coriolis meters you will get your calculated observed 2 volumes. The Phase Dynamics meters on the oil leg 3 would be used to determine your water cut and that 4 would be subtracted out of your -- your water cut 5 volumes would be subtracted out of your observed 6 volumes to get to your net observed volume. Now this 7 is where for GMT1 we would apply our shrinkage factor 6 in order to get to our net standard volume of oil for 9 the drill site. 10 Slide 12, this is where the -- we're going to 11 be developing a shrinkage factor matrix that will use 12 the compositional oil analysis and our process modeling 13 software to develop this shrinkage factor matrix. The 14 matrix would be applied on the flow computer for a 15 standard volume determinations and it's going to be 16 developed across a range of operating pressures and 17 temperatures. The flow computer will do the two way 18 linear interpolations so at a given pressure and 19 temperature it'll determine which shrinkage factor to 20 apply to the volume calculations. 21 As necessary we will update the shrinkage 22 factor matrix by taking the new compositional data for 23 the oil and rerunning it through our process modeling 24 software in order to make sure that we're staying on 25 top of this matrix. I just want to point out that this 21 1 methodology of applying a shrinkage factor is identical 2 to the way we apply shrinkage factor to the current CRU 3 well test and allocations. So there's really nothing 4 new as far as how we do this. 5 For slide 13 our proposed measurement system 6 along with robust operation and maintenance plans we 7 feel we achieve the high measurement certainty. Our 8 maintenance plans include things like advanced 9 diagnostics, calibrations and visual inspections of the 10 metering equipment. 11 So to talk about measurement point here for the 12 oil Coriolis gas meters we will be implementing smart 13 meter verification. That is an automatic diagnostic 14 application that checks the internal -- it's an 15 internal diagnostic, checks how the meter is working 16 and it also -- it can be done without disrupting the 17 process flow. So this is an online diagnostic 18 application. 19 We will be scheduling the smart meter 20 verification monthly and this will compare the online 21 Coriolis meter to the factory baseline value. If 22 there's any deviations outside of manufacturer's 23 tolerances this would correct -- flag the meter for 24 corrective maintenance actions on the Slope, to figure 25 out what might be wrong with it. Additionally the 22 1 Coriolis meters, each one will be removed from service 2 every year and they will be shipped off to an 3 accredited flow test facility to get calibrated. 4 For the gas measurement we are putting in AGI 5 compliant orifice meter runs. On those we will be 6 deploying a continuous DP diagnostic application 7 software that will monitor -- it's a dynamic pressure 8 sensing monitor that will warn -- reliably warn if you 9 have problems with your orifice meter run. So it will 10 be able to detect plugged impulse tubing lines, worn or 11 bent plates, that type of thing, which again like the 12 Coriolis meters if there's any deviations outside of 13 manufacturer's tolerance that would flag corrective 14 maintenance. Additionally every year we will be 15 pulling out the orifice plate for inspection and we 16 will also be doing a full baroscope inspection on the 17 entire meter run. 18 For the Phase Dynamics water cut analyzer and 19 the secondary instruments that are used for pressure 20 and temperature measurements we will be calibrating 21 those quarterly and additionally the Phase Dynamic will 22 also be cross verified with our sampling, our flow 23 proportional sampling results every month. 24 So for slide 14 as far as sampling we are 25 sampling -- we have a sampling plan for both the oil 23 1 and the gas streams. for the oil stream we have -- 2 we're installing a fast loop flow proportional sampling 3 system that would aligned to the in service Coriolis 4 meter. The samples that we -- monthly samples taken to 5 do -- to analyze for the composite measurement of the 6 oil such that we can compare that to the online 7 parameters that we're seeing within our flow meters. 8 If there's any discrepancies between the samples and 9 what we're seeing online obviously that would again 10 trigger an investigation to resolve the issue. As 11 necessary these oil sample results will also be used to 12 tune the shrinkage factor matrix that I described 13 earlier. 14 For the gas measurement sampling each gas 15 measurement -- each gas meter will have a dedicated 16 flow through spot sampling station which we will take 17 monthly gas samples for compositional and BTU analysis. 18 MR. VIATOR: On slide 15 I wanted to highlight 19 the regulation, the Alaska Administrative Code 25.288 20 and the elements that we think we comply with and then 21 the few items that we are discussing on the waiver. So 22 the checkmarks in green indicate those elements of this 23 regulation where we believe we comply with and don't 24 have any concerns. But element number (a) where things 25 need to be measured prior to severance from the unit, 24 1 as we pointed out, you know, so the produced oil and 2 gas streams will be measured prior to leaving GMT1, 3 it's the gas stream leaving the Colville River unit and 4 coming back to GMT1 that will be measured off lease at 5 GMT1. And the usage of shrinkage factors is not 6 necessarily applicable for custody transfer, but it 7 does comply with section -- chapter 20.1 as a valid 8 method for allocation metering. So it's still within 9 the realm of API and MPMS. 10 For items (g) and (h), those get to the 11 discussion on proving and then provers being used for 12 certification. So what we have proposed for the oil 13 meters is the use of advanced monthly verification, the 14 smart meter verification supported by annual meter 15 calibration. We do believe that that is -- falls into 16 the realm of being equal to or better than the noted 17 proving methodologies. And then we are compliance with 18 the gas meter calibration requirements so don't have 19 any concerns there. 20 Item (j) relates to, you know, upon request the 21 Commission having the authority to approve a variance 22 if equal or improve accuracy. So we are requesting 23 approval for the commission's discretion to off lease 24 measurement and for custody transfer metering. 25 Slide number 16 relates to the AOGCC industry 25 1 guidance bulletin 13-002. Again the elements 2 highlighted in green or checked in green are things 3 that we have provided and are known, but the other 4 items at this time, the things circled in blue, we 5 don't have those details available, they will come once 6 we have the manufacturer's selected and receive their 7 details. So other than those items noted above, you 8 know, the remaining details that are required are not 9 available at this time so we physically can't provide 10 them. 11 CHAIR FOERSTER: But you don't expect any 12 compliance issues with them? 13 MR. VIATOR: No, ma'am. 14 CHAIR FOERSTER: Okay. 15 MR. VIATOR: And these items, you know, we'll 16 -- we do plan to install in 2018 with the start up as 17 noted in fourth quarter 2018, but the exact 18 installation date hasn't been defined at this time, but 19 it will be some time in that last year of construction. 20 Slide number 17 gets to the economic analysis 21 of a production facility and the reasoning driving us 22 to not having a process facility and being able to 23 measure in accordance with custody transfer 24 requirements for LACT metering. On the right we've 25 noted the premises that we've used for this analysis. 0XI 1 So we have assumed a 10 percent discount rate and are 2 using a January 1, 2016 .4 present value date. We are 3 utilizing the Alaska Department of Revenue fall, 2015 4 price forecast. And this assumes a 100 percent working 5 interest. The capital cost for the production facility 6 was estimated at $500 million. Expense for operating 7 cost is estimated at $45 million per year and we also 8 believe there would be a four year project delay moving 9 first oil to 2022. That would be associated with 10 reopening the permitting and additional engineering 11 that would be needed. 12 So what we can see here is for with these 13 assumptions, you know, the project as it stands and 14 proposed today having a value related to 100 percent, 15 with the investment alone of the $500 million for the 16 production facility that alone takes it to -- erodes 17 all of the value and takes it to a negative project and 18 one that we would not be able to proceed with. You 19 further add on the operating costs, that erodes more 20 value and then the four year delay would add additional 21 decrease in value to the project where overall the 22 project would have a negative 300 percent MPV value 23 relative to our starting point. So this would be 24 something that ConocoPhillips just wouldn't be able to 25 continue with on the GMT1 project if we were to achieve 27 1 LACT metering. 2 So slide number 18 is the last slide that I 3 have and really just kind of a status and summary. So 4 the Greater Mooses Tooth 1 project is currently 5 finishing up detailed engineering. We've started 6 elements of our procurement process and we are still 7 working on finalizing the production separator details 8 that may come out of this hearing and our discussions 9 with the BLM. 10 So as Jon mentioned in the opening we are 11 requesting both BLM and AOGCC approvals now for 12 measurement so that we can finalize this design and 13 move forward with the procurement process for the 14 necessary equipment. And again we've presented a 15 design concept, a metering philosophy that we believe 16 is one that is economically viable and can be accepted 17 by the agencies and then also knowing that we do have 18 the request for the off lease measurement for the CRU 19 gas going back to the Greater Mooses Tooth 1. 20 CHAIR FOERSTER: Thank you. 21 MR. VIATOR: Yeah. 22 CHAIR FOERSTER: Do you have any questions at 23 this time, Commissioner Seamount? I'd like to suggest 24 that we take a brief recess and let our intelligent 25 staff turn our curiosity questions into intelligent M 1 ones if that's okay with you? 2 COMMISSIONER SEAMOUNT: That's fine. 3 CHAIR FOERSTER: Okay. All right. It is 9:40 4 and we're going to take a 20 minute recess and 5 reconvene at 10:00. We're recessed. 6 (Off record - 9:40 a.m.) 7 (On record - 10:06 a.m.) 8 CHAIR FOERSTER: Back on the record at 10:06, 9 we apologize for taking an extra five minutes. 10 All right. Commissioner Seamount, would you 11 like -- do you have any questions? 12 COMMISSIONER SEAMOUNT: Yes, I'll start with 13 some simple ones, I'm the geologist here then more 14 complicated ones I'll send over to the engineer since 15 she's more experienced at this sort of thing. 16 Is it Mr. Viator? 17 MR. VIATOR: Yes, sir. 18 COMMISSIONER SEAMOUNT: Viator. Okay. Let's 19 look at slide number 4. It's a map and it shows the 20 Greater Mooses Tooth unit and it shows it to be much 21 larger than the Colville River unit. And it's in red. 22 Is that your anticipated area of production or does it 23 include some protection acreage in there? 24 MR. VIATOR: The Greater Mooses Tooth unit is 25 not just GMT1, you know, there's other potential 29 1 participating areas within that unit. But GMT1 only 2 includes the Lookout PA. 3 COMMISSIONER SEAMOUNT: Okay. So that big old 4 red blob there where it's not really red on the screen, 5 but a lot of that includes exploration acreage; is that 6 correct? 7 MR. VIATOR: Yes. 8 COMMISSIONER SEAMOUNT: Okay. Now the Bear 9 Tooth unit to the northwest, are you going to be 10 requesting the same sort of approval of operations as 11 you are today? 12 MR. VIATOR: I don't believe we could make that 13 statement at this time. We haven't done a sufficient 14 amount of thought on those developments and how we 15 would approach those, but I don't believe that we cold 16 say with any certainty that we would do them the same 17 as GMT1 or that we would do them different. 18 COMMISSIONER SEAMOUNT: Okay. What's the 19 gravity of the oil we're talking about today? 20 MR. VIATOR: I don't have that information. 21 CHAIR FOERSTER: All right. Well, we'll leave 22 the record open for -- at the end of the hearing we'll 23 decide on the amount of time you'll need to answer any 24 questions you can't answer today and we'll just leave 25 the record open to allow you to answer questions that im 1 you don't have, you know, the answer now. 2 COMMISSIONER SEAMOUNT: I assume you don't know 3 what the GOR is either? 4 MR. VIATOR: I would need to confer. I have an 5 idea, but I'd rather confer before giving you an 6 incorrect answer. 7 COMMISSIONER SEAMOUNT: Okay. When you ship 8 off the Coriolis meter how are you going to do that and 9 where is it going? 10 MS. HOSACK: We haven't actually determined 11 where we will be sending it yet. We'll be sending it 12 to an accredited facility for the calibration, but we 13 anticipate every six months essentially one of the 14 meters will be removed from service, crated up and then 15 shipped off to the facility. We will have a third 16 meter that's essentially a standby meter that will 17 replace the one that's being sent off site for 18 calibration. So it'll be three meters that rotate 19 through the two metering stations. 20 COMMISSIONER SEAMOUNT: Okay. Now if this is 21 not approved, you talked about a four year delay, 22 where's the delay going to be, what's that going to 23 encompass? 24 MR. VIATOR: Well, the -- I guess the first 25 response to that is, you know, if we were to do the 31 1 processing facility we really would not even proceed 2 with the project. When we did this evaluation 3 previously the four year delay would come in the form 4 of needing to go back through the SEIS project and 5 reopen that, doing the evaluations of what 6 environmental impacts might be as well as engineering 7 design and going back to the engineering phase, 8 reopening that and the delays associated with 9 procurement and engineering design. 10 COMMISSIONER SEAMOUNT: So are you saying that 11 you would just completely give up on the project? 12 MR. VIATOR: At this time, yes, sir. 13 COMMISSIONER SEAMOUNT: And would that include 14 all projects to the west? 15 MR. VIATOR: Not necessarily, but we would need 16 a sufficient amount of development resource that would 17 support the processing facility. 18 CHAIR FOERSTER: So you might put GMT1 on hold 19 and do more exploration to get a larger conglomerate 20 before you proceeded? 21 MR. VIATOR: We would have to really evaluate 22 that, I can't say that with certainty. 23 COMMISSIONER SEAMOUNT: Okay. Those are the 24 simple questions. I'll flip it over to Chair Foerster. 25 CHAIR FOERSTER: And mine are going to be kind 32 I of in a stream of consciousness format and I'm not 2 going to follow a logical thought process, it's just as 3 I had the questions I wrote them down and I'm just 4 going to ask them that way. You talk about a shrinkage 5 factor matrix, who's going to oversee that and make 6 sure, you know, that it's accurate, unbiased, it's 7 appropriate? 8 MS. HOSACK: We do have a position that we're 9 planning to fill that's not filled yet that will be 10 overseeing the regulatory aspects of the metering 11 systems for both the state and the BLM. So I would 12 imagine that position would be doing that along with 13 probably our production engineers that are monitoring 14 the day to day production..... 15 CHAIR FOERSTER: Okay. Well..... 16 MS. HOSACK: .....from the drill site. 17 CHAIR FOERSTER: All right. We'll likely -- if 18 we approve this request we'll likely require that you 19 had a third party outside source, you know, for review. 20 And we've done that for others who've come to us with 21 things like this so put that into your thinking that if 22 this gets approved you're going to have to find an 23 outside, unbiased third party that's willing to sign 24 off and say this doesn't have a Conoco bias to it. 25 MS. HOSACK: Okay. 33 1 CHAIR FOERSTER: Okay. So just put that into 2 your thoughts. Are you getting positive vibes from the 3 BLM, you think they're going to approve? 4 MR. VIATOR: Yes. I mean, in our discussions 5 that we've had they haven't indicated any major 6 concerns and where we're at today with the design is 7 really what they were wanting. 8 CHAIR FOERSTER: Okay. And do you see any 9 issues with them? 10 MR. VIATOR: No, ma'am. 11 CHAIR FOERSTER: We always try to be consistent 12 and fair and reasonable and treat everybody the same so 13 we're looking back on other situations we've had like 14 this. And you mentioned Oooguruk, but in a more recent 15 one we required more detail on the economic analysis. 16 Would -- of course it was held confidential, but would 17 you be willing to sit down with our engineers and 18 provide more detail on your economic analysis of the 19 project? 20 MR. VIATOR: I think we'd want to discuss that 21 internally, but I would think that we'd be able to get 22 to some..... 23 CHAIR FOERSTER: okay. 24 MR. VIATOR: .....arrangement. 25 CHAIR FOERSTER: That might be a requirement. 34 1 MR. VIATOR: Yeah. 2 CHAIR FOERSTER: Is this system substantially 3 different from what you use at Colville River? 4 MR. VIATOR: We have the -- the test separators 5 that we're having at GMT1 are the same that are used in 6 the Colville River unit, but the Colville River unit 7 doesn't have a production separator. 8 CHAIR FOERSTER: So what's the uncertainty in 9 measurements that you got at CRU, you're talking about 10 a 2 percent here, what are you seeing at the CRU? 11 MS. HOSACK: I mean, over time the allocation 12 system at CRU has -- it's centered right around one or 13 the life of the facilities there at Alpine. 14 CHAIR FOERSTER: 1 percent uncertainty? 15 MS. HOSACK: Well, the allocation factor of 16 one. I'm sorry. So it's -- I don't think we have 17 actual -- I mean, I'm not certain of the..... 18 CHAIR FOERSTER: Did you get..... 19 MS. HOSACK .....uncertainty calcs for that. 20 CHAIR FOERSTER: .....would you write -- make 21 -- if you've got somebody taking a list of questions 22 that remain unanswered..... 23 MS. HOSACK: Okay. 24 CHAIR FOERSTER: .....add that to it. I think 25 that would be a good thing for maybe Mr. Goltz to do or 35 1 somebody to do. I think the people in the back of the 2 room are probably doing that too. 3 Can you characterize where you get the 2.1 4 percent from, some more details on where those 5 uncertainties reside and then how they'll change over 6 time? 7 MS. HOSACK: So the uncertainty calculation was 8 -- the full uncertainty calculation was provided in the 9 application. Again the largest contributor is the 10 shrinkage factor to that. I don't remember the 11 specific numbers off the top of my head, but the meter 12 itself, the Coriolis meters, the uncertainties for the 13 Phase Dynamic were accounted for in the calculation 14 over the range of operating pressures and temperatures 15 that -- and flow rates that we're anticipating. 16 CHAIR FOERSTER: Okay. So why are you assuming 17 an allocation factor of one for meter? 18 MR. VIATOR: The Greater Mooses Tooth unit 19 being located in the federal lands, you know, is really 20 a requirement from the BLM that it be kept whole. 21 CHAIR FOERSTER: Okay. And why are you 22 measuring the gas sent to GMT at GMT rather than CRU, 23 that's one of the things you're asking for a variance 24 on so why do you need that variance? 25 MR. VIATOR: The split off for the gas line 36 I coming from the ACF that eventually goes to GMT, the 2 last T in the line is going out to CD5 so that's where 3 we would have to put the meter. And the difficulty 4 with installing the metering in a brownfield situation 5 at CD5 where it wasn't planned for another module the 6 cost associated with installing it at CD5 and the 7 complexity and potential impact on maintenance and 8 access to our existing wells over there, we thought 9 that it was much simpler to have it in the design from 10 the beginning at GMT1, it would be less cost and there 11 would be no difference in the accuracy of the meter. 12 CHAIR FOERSTER: So even though API recognizes 13 your Coriolis meter as acceptable our current 14 regulations do not. So that does require a variance 15 and it requires an equal or better accuracy variance so 16 we do need some details on you from that. Would you 17 need any of these variances if you just combined the 18 two units? 19 MR. VIATOR: If the units were combined then 20 the GMT1 development would be just like any of the 21 other CRU developments and only need the allocation. 22 CHAIR FOERSTER: So you wouldn't need any 23 custody transfer variances, you'd just need allocation? 24 MR. VIATOR: Okay. 25 CHAIR FOERSTER: Did you consider combining the 37 I units? 2 MR. VIATOR: In this development the decision 3 to have the units separate was already made by the time 4 we started to do the metering design. So it wasn't -- 5 it was considered and I've said as the basis that they 6 would be separate units. 7 CHAIR FOERSTER: Why was that done, do you 8 know? 9 MR. VIATOR: I don't have the full history, but 10 we can talk about that and..... 11 CHAIR FOERSTER: Okay. If you can give us some 12 historical perspective..... 13 MR. VIATOR: Yeah. 14 CHAIR FOERSTER: .....on that and it's one of 15 the things that we'll leave the record open for that 16 would be good. 17 We're going to need a lot more detail on the 18 smart diagnostics in order to buy off on that and so 19 can you provide that to our technical staff? 20 MS. HOSACK: Yes, we have no problem providing 21 that. Do you want it for both the Coriolis meter as 22 well as the gas meters or..... 23 CHAIR FOERSTER: Yes. 24 MS. HOSACK: Both of them. Okay. 25 CHAIR FOERSTER: Yes. so how will you account W 1 for entrained oil in the water stream? 2 MS. HOSACK: So right now we are planning to 3 just use the level measurement in the vessel to make 4 sure we're not pushing oil out the water leg, 5 significant quantities of it. The vessel is being 6 sized for -- to ensure that we have enough residence 7 time, that we get good separation and we're not pulling 8 oil. 9 CHAIR FOERSTER: So the answer is you're going 10 to assume there isn't any? 11 MS. HOSACK: We don't have provisions to 12 monitor that in this current design. 13 CHAIR FOERSTER: Okay. So the answer to my 14 question is yes, you're going to assume there isn't any 15 oil carried over into the water. Okay. And so how are 16 you going to account for entrained oil in the gas 17 stream? 18 MS. HOSACK: We don't have any provisions for 19 accounting for that..... 20 CHAIR FOERSTER: Okay. 21 MS. HOSACK: .....either. 22 CHAIR FOERSTER: Okay. All right. As an 23 instrumentation and measurement expert do you think 24 that's a sound choice? 25 MS. HOSACK: We probably should, yes, include 39 1 some method of determining that. 2 CHAIR FOERSTER: Okay. 3 MS. HOSACK: In the..... 4 CHAIR FOERSTER: So..... 5 MS. HOSACK: ..... waterstream for sure..... 6 CHAIR FOERSTER: So it wouldn't be unreasonable 7 of us..... 8 MS. HOSACK: .....might be more complicated, 9 but..... 10 CHAIR FOERSTER: .....to make that a constraint 11 of approval if as an expert you think that you probably 12 should have done that? 13 MS. HOSACK: On the water leg, yes, I 14 would..... 15 CHAIR FOERSTER: Okay. 16 MS. HOSACK: .....I would agree. 17 CHAIR FOERSTER: Okay. You say you'll have 2.1 18 percent uncertainty and what would be the uncertainty 19 required by our regs, it's a lot tighter than that, 20 isn't it, in our regulations for custody transfer 21 metering? 22 MS. HOSACK: I personally don't remember seeing 23 any targets on uncertainty within the reqs, but 24 generally custody transfer is 0.35 percent typical. 25 CHAIR FOERSTER: Okay. So our variance does EM 1 state that we grant a variance if you can provide equal 2 or greater accuracy and so how do you address that 2.1 3 is not equal or greater to 0.3? 4 MR. GOLTZ: If I might interject on that issue. 5 That's one of the reasons why we are suggesting that 6 the Commission issue an order that's not necessarily 7 strictly under section 225 including the variance 8 provision in subsection (j). The Commission does have 9 authority to approve a measurement system that's an 10 adequate measurement system even if doesn't conform to 11 228. 12 CHAIR FOERSTER: Okay. Okay. Did I leave any 13 simple questions for you? 14 COMMISSIONER SEAMOUNT: No. 15 CHAIR FOERSTER: Okay. Does Conoco have 16 anything else that they would like to say before we 17 invite anyone else in the audience to talk? 18 MR. VIATOR: No. 19 CHAIR FOERSTER: Okay. Is there anyone else 20 who wishes to testify? 21 (No comments) 22 CHAIR FOERSTER: Any of the people that work 23 for these folks who think they didn't represent you 24 well? 25 (No comments) 1 CHAIR FOERSTER: All right. So let's talk 2 about -- how long do you think you'll need to provide 3 answers to the unanswered questions. 4 MR. GOLTZ: Well, I -- what I would most like 5 to do is run through my list to make sure that I..... 6 CHAIR FOERSTER: Okay. Make sure it's 7 accurate. That's a good idea. 8 MR. GOLTZ: .....that we've got it right and 9 then I'll..... 10 CHAIR FOERSTER: Okay. Because I've got a list 11 of..... 12 MR. GOLTZ: .....think about an answer. 13 CHAIR FOERSTER: Okay. Go ahead. 14 MR. GOLTZ: I had down a request to identify 15 the gravity of the oil, number 1; number 2, the GOR; 16 three, a detailed analysis you indicated would be part 17 of the discussion with the engineers that would 18 potentially include additional economic information 19 that the Commission would hold confidential; four, 20 identification of the measurement uncertainty that we 21 experience at the Colville River unit; five, there's a 22 question that maybe we need to fill out a little bit 23 more about whether a variance would be necessary if the 24 units were combined and related to that was some more 25 information about the history of how these units came 42 I to be created as separate units; and a request for more 2 information on the smart diagnostics both on the 3 Coriolis and the gas meters. 4 CHAIR FOERSTER: Uh-huh. 5 MR. GOLTZ: I think we might also need to 6 explain a little bit better in our response how we 7 accounted for oil that might be entrained in a water 8 leg or in a gas leg as well. That's all I've 9 identified as questions. 10 CHAIR FOERSTER: And did -- I may have missed 11 it, did you include in there a review in greater detail 12 of the economics? 13 MR. GOLTZ: Yes, I do have that. 14 CHAIR FOERSTER: Okay. 15 MR. GOLTZ: I think that'll -- I expect that to 16 be kind of a discussion about what might be expected by 17 the Commission. At this point I don't know what 18 additional information we might provide..... 19 CHAIR FOERSTER: That could be..... 20 MR. GOLTZ: .....but we're happy to..... 21 CHAIR FOERSTER: .....just a discussion between 22 you and our staff. 23 MR. GOLTZ: Okay. 24 CHAIR FOERSTER: Okay. So to get through all 25 of this do you think leaving the record open for a 31 1 month would be sufficient, too much? 2 MR. GOLTZ: I think that's reasonable. 3 CHAIR FOERSTER: Okay. All right. So let's 4 see today is May 3rd, we'll leave the record open until 5 June 3rd for providing additional information to our 6 staff. 7 Is that okay with you, Commissioner Seamount? 8 COMMISSIONER SEAMOUNT: Yeah. 9 CHAIR FOERSTER: Okay. All right. If there's 10 no one else wishing to testify and Conoco has -- feels 11 like they said all they want to say then I will adjourn 12 this hearing at 10:26. The record stays open until 13 June 3rd. 14 (Hearing adjourned 10:26 a.m.) 15 9:43:11 16 (END OF REQUESTED PORTION) 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) 3 )ss 4 STATE OF ALASKA ) 5 6 I, Salena A. Hile, Notary Public in and for the 7 state of Alaska, residing in Anchorage in said state, 8 do hereby certify that the foregoing matter: Docket 9 No.: OTH 16-005 was transcribed to the best of our 10 ability; Pages 02 through 45; 11 IN WITNESS WHEREOF I have hereunto set my hand 12 and affixed my seal this 11th day of May 2016. 13 14 15 Salena A. Hile 16 Notary Public, State of Alaska 17 My Commission Expires: 09/16/2018 18 45 TRANSCRIPT OF PUBLIC ..HARING 5/3/2016 DOCKET NO OTH-005 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: Cathy Foerster, Chair Daniel T. Seamount In the Matter of the Application of ) ConocoPhillips, Alaska, Inc., for a Waiver ) of the requirements of 20 AAC 25.228(a) to ) allow for final custody transfer metering ) of hydrocarbons sold from the Greater ) Mooses Tooth unit to occur off unit and to ) allow for the final custody transfer ) metering of gas sold from the Colville ) River unit to the Greater Mooses Tooth ) unit to occur after the gas is severed from ) the Colville River unit. ) Docket No.: OTH 16-005 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska May 3, 2016 9:00 o'clock a.m. PUBLIC HEARING BEFORE: Cathy Foerster, Chair Daniel T. Seamount Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC, _.TARING 5/3/2016 DOCKET NO OTH-005 2 (Pages 2 to 5) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net Page 2 Page 4 1 TABLE OF CONTENTS 1 from them. 2 Opening remarks by Chair Foerster 03 2 We have three people from Conoco who intend to 3 Remarks by Mr. Goltz 06 3 testify today. Are there any other partes planning to 4 Remarks by Mr. Viator 11 4 testify? 5 Remarks by Ms. Hosack 19 5 (No comments) 6 6 CHAIR FOERSTER: Okay. If you're testifying 7 7 please keep in mind than you most speak into the 8 8 microphones w that the people in the back of the room 9 9 can hear you and so Thal the court reporter can capture 10 10 what you say. And please remember to reference your I l 11 slides so that someone reading this record 10 years 12 12 form now will understand what you're referring to. So 13 13 if the slides are numbered as you go to a new slide say 14 14 now were looking at slide number 1, you know, for 1s 15 example or if theyre not a title would be fine. 16 16 I don't need to read the ground Nies for the 17 17 misbehavers, do 1, do we have any misbehavers in the 18 18 audience. Okay. Well, we' 11 just skip those then. 19 19 Dan, do you have anything to add? 20 20 COMMISSIONER SEAMOUNT: Question, how much time 21 21 are you going to take in your testimony today do you 22 22 estimate? 23 23 MR. GOLTZ: Half an hour maybe..... 24 24 COMMISSIONER SEAMOUNT: Okay. 25 25 MR. GOLTZ: ..... or maybe 45 minutes. Page 3 Page 5 1 PROCEEDINGS 1 CHAIR FOERSTER: Okay. And is any of the 2 9:04:04 2 testimony confidential? 3 (On record - 9:01 a.m.) 3 MR GOLTZ: No. 4 CHAIR FOERSTER: I'll call this hearing to 4 CHAIR FOERSTER: Thank you. All right. I s order. Today is May 3, 2016, it is 9:01 a.m. We are 5 assume you are the three Conoco folks that will 6 in the offices of the Alaska Oil and Gas Conservation 6 testify. 7 Commission at 333 West Seventh Avenue in Anchorage, 7 MR GOLTZ: Yes. 8 Alaska. To my left is Dan Seamount, I'm Cathy 8 CHAIR FOERSTER: So let's swear you all in 9 Foerster. 9 together. Ifyou would say your name for the record 10 Today's hearing is on docket number OTH 16-005, 10 just one, two, three and then I'll do the swear in. 11 the Application of ConocoPhdlips, Alaska, Inc., for a 11 MR VIATOR: Brandon Viator. 12 waiver of the requirements of 20 AAC 25.228(a) to 12 MS. HOSACK: Jody Hosack. 13 provide custody transfer measurement of hydrocarbons 13 MR GOLTZ: And Jon Goltz. 14 prior to severance from the lease or unit. 14 CHAIR FOERSTER: Is your mic on? is ConwcoPhillips, Alaska by letter dated February 26, 15 MR GOLTZ: It's on. 16 2016 requests the Alaska Oil and Gas Conservation 16 CHAIR FOERSTER Okay. Thank you. Raise your 17 Commission issue a waiver from the requirements of 20 17 right hand. 1.8 AAC 25.228(a) to allow for final custody transfer 18 (Oath administered) 19 metering of hydrocarbons sold from the Greater Mooses 19 MR GOLTZ: I do. 20 Tooth unit to occur off unit and to allow for the final 20 MS. HOSACK: I do. 21 custody transfer teetering of gas sold from the Colville 21 MR VIATOR: I do. 22 River unit to the Greater Mouses Tooth unit to occur 22 CHAIR FOERSTER: Okay. Well, let's start with 23 after the gas is severed from the Colville River unit. 23 the fust person who wants to testify and do you want 24 Computer Matrix will be recording today's 24 to be recognized as an expert in any area..... 25 proceedings and you can get a copy of the transcript 25 MR GOLTZ: No. 2 (Pages 2 to 5) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net TRANSCRIPT OF PUBLIC __CARING 5/3/2016 DOCKET NO OTH-005 3 (Pages 6 to 9) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 6 Page 8 1 CHAIR FOERSTER .....that's relevant today? 1 adopted a guidance bulletin that we are aware of 2 Okay. Thenjusl give your name, who you represent and 2 describing information required for measurement 3 proceed with your testimony. 3 approval and that requires some detailed information 4 MR GOLTZ: Okay. Thank you and good morning. 4 such as serial numbers on specific equipment that is 5 My name is Jon Goltz, my last name is spelled G -O -L -T- 5 not available today. But we are seeking approval now 6 Z. I'm in-house legal counsel for Cormed'hillips, 6 so that we can proceed with the engineering and 7 Alaska. And as already mentioned I have with me at the 7 procurement for the project. Brandon will speak to the 8 table are Brandon Viator and Jody Hosack. IT suggest 8 schedule that we have. 9 that they be qualified as experts to speak to 9 Finally as you know the Greater Mooses Tooth 10 substantive issues right alter my brief introductory 10 unit is a federally administered unit, administered by 11 remarks. 11 the BLM and they have a regulatory role here we, 12 In the audience we also have with us another 12 ConocoPhillips has worked with both the BLM staff and 13 Con"Phillips employee, Bob Peebles, who could be 13 the AOGCC staff going back as far as 2013 to come up 14 available to testify on specific technical issues if it 14 with a metering system that we think is both 15 turns out than those are of interest to the 15 economically viable and approvable by both the BLM and 16 Commissioners. 16 the AOGCC. Our applications for approval are 17 We are here to support CormcoPhillips' 17 simultaneously pending before both regulatory agencies. 18 application for approval of a proposed system for 18 So unless the Commissioners have any questions 19 measuring oil and gas production from the planned GMTI 19 about these introduction remarks, Brandon Viator will 20 development and as an ancillary matter gas that will 20 proceed with an overview of our proposed system. 21 Flow from the Colville River unit to the GMT] 21 CHAIR FOERSTER: Do you have any questions, 22 development in the Greater Mooses Tooth unit. Our 22 Commissioner Senatorial? 23 application addresses the standards for custody 23 COMMISSIONER SEAMOUNT: I have none. 24 transfer that are codified at the Commission's 24 CHAIR FOERSTER: Okay. Nor do 1. So, Mr. 25 regulation at section 228 and we will speak to those 25 Viator, what area would you like to be recognized as an Page 7 Page 9 1 standards here today. As the technical standards — 1 expert in? 2 experts will explain the standards adopted in section 2 MR VIATOR Oil and gas developments. 3 228 apply to custody transfer measurement o£pipe line 3 CHAIR FOERSTER: Okay. Engineering? 4 quality oil downstream of processing facilities. Our 4 MR VIATOR: Yes, ma'am. 5 plan is to measure live oil upstream of processing 5 CHAIR FOERSTER Okay. So give us your 6 facilities and we therefore ground our request notjust 6 qualifications, education, your experience that..... 7 in section 228 because we do believe we meet most and 7 MR VIATOR: I have a bachelor's degree in s arguably all o£those standards, but also in Alaska s chemical engineering from Texas A&M University and I've 9 statute 31.050.30, subsection (c), under which the 9 been working in the oil and gas industry for 15 years 10 Commission has the authority to issue orders 10 all of which has been with ConecoPhillips. I'm a 11 appropriate to carry out the Alaska Oil and Gas 11 licensed professional engineer and Aran also a certified 12 Conservation Act including measurement of oil and gas. 12 project management professional. I've been.... 13 Our proposal is in some ways similar to the 13 CHAIR FOERSTER: Is your license in Alaska? 14 Ooogurk unit where oil and gas are measured prior to 14 MR VIATOR: No, ma'am, it is in Texas. 15 processing at the Kuparuk River unit facilities, 15 CHAIR FOERSTER.- Texas. Okay. So was m]ne.f 16 although we are proposing a different kind of 16 MR VIATOR: I have worked both domestic and 17 measurement system than Ooogurk. We intend to show 17 international assignments holding roles as process 18 that our proposal involves a robust, accurate method is engineer, project engineer, project manager, asset 19 for measuring GMTI production before it gets comuningled 19 manager and project integration manager all prior to my 20 with CRU production and is processed in CRU facilities. 20 current role which is the project integration manager 21 The key bit of context which our project integration 21 for the Greater Mouses Tooth unit. And in the last 10 22 manager will address is that GMT] is a modest 22 years I've been working on oil and gas developments in 23 development that would not on its own support the 23 these rotes. 24 development ofprocessing frcilifies. 24 CHAIR FOERSTER: All right. Comumissioner 25 We want to acknowledge that the Commission has 25 Seamount, do you have any questions for this Aggie? 3 (Pages 6 to 9) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC __rARMG 5/3/2016 DOCKET NO OTH-005 4 (Pages 10 to 13) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net Page 10 Page 12 1 COMMISSIONER SEAMOUNT: I have none. I -- and 1 they're written. And then we will go through the 2 I have no complaints considering he went to the better 2 economic analysis of installing a production facility 3 school. 3 at GMTI and then wrap things up with a status of where 4 CHAIR FOERSTER: 1 don't have any problems 4 we are in the project and smmnary of today's 5 either and we recognize you as an expert in project 5 discussion. 6 development engineering so please proceed with your 6 So moving to slide number 4, to start out with 7 testimony and don't forget about identifying your 7 a high level overview in the map you'll see the various 8 slides. 8 milts across the North Slope. The units that are 9 MS. HOSACK: May 1 go ahead and qualify as an 9 highlighted in bold lettering are ones where 10 expert now as well? 10 ConocoPhillips has a working interest and the two that 11 CHAIR FOERSTER: Oh, you might as well. Go 11 we'll be discussing today are colored in the darker 12 ahead. 12 color as the Greater Mouses Tooth unit and the Colville 13 MS. HOSACK: So my name is Jody Hosack, l am 13 River unit. Also hated on the map is the NPR -A line 14 Con000Phillips' instrumentation and Flow measurement 14 noted by the black and white dashed line that mns 15 technical authority. I'd like to be qualified as an 15 vertically through the map. 16 expert in instrumentation and flow measurement. So 1 16 I'm not going to tun through all the points on 17 have a bachelor's of science degree from -- with -- in 17 the bottom of this slide, but wanted to highlight a few 18 control systems engineering from Montana Tech of the 16 key items. That this is the first development for the 19 University of Montana. I'm also a registered 19 Greater Mooses Tooth unit and we are leveraging off of 20 professional engineer in the slate of Alaska. I've 20 the Alpine existing infrastructure and the CDS design 21 worked in the Alaska oil and gas industry for 18 years 21 work. The construction seasons for the Greater Mooses 22 the last eight of which have been Conc ooPhillips. And 22 Tooth unit are envisioned to span two seasons starling 23 I've held the instrumentation and flow measurement 23 at the end of this year in the fourth quarter of 2016 24 technical role -- technical authority role for the last 24 and then again the next winter in 2017 muting through 25 six years. 25 2018 with an expectation of first oil in December, Page 11 Page 13 1 CHAIR FOERSTER: Who were you with before 1 2018. 2 Conoco? 2 The next slide is slide number 5 and what we 3 MS. HOSACK: I was with various engineering 3 wanted to do is highlight the ownership and working 4 foss that supported the oil and gas industry up hem 4 interests for the CRU and the Greater Mouses Tooth s in Anchorage. 5 unit. So on the lop of the slide and on the right in 6 CHAIR FOERSTER: Okay. Commissioner Seamounl, 6 blue are highlighting the Colville River unit and in 7 do you have any questions? 7 green on the bottom is the Greater Mooses Tooth unit. a COMMISSIONER SEAMOUNT: 1 have no questions 8 So I'll start with the working interest owners are well 9 or..... 9 aligned in both units with ConocoPhillips and Anadarko 10 CHAIR FOERSTER: Nor do I. We're both 10 being the primary owners or working interest owners 11 comfortable with both of you as experts in those areas. 11 with the caveat being in the Colville River unit for 12 BRANDON VIATOR 12 the CD3 development Petro -Hunt does have a small 13 previously sworn, called as a witness on behalf of 13 working interest and that is less than one-tenth of one 14 ComeoPhillips, Alaska, testified as follows on: 14 percent. 15 DIRECT EXAMINATION 15 So on the Colville River unit starting with the 16 MR. V IATOR: Thank you. So we'll start with 16 map on the top right the lands noted in yellow are 17 slide three which is the agenda to give you a brief 17 lands that are -- where the state of Alaska owns the 18 overview of what we'll talk about today. I'll go 18 surface and subsurface rights. On the bottom left the 19 through a quick background on the GMTI project in 19 small portion of lands in the southwest of the Colville 20 meashhrehnent design and then well touch on the key 20 River unit are BLM lands where they own surface and 21 highlights that we would like to discuss regarding the 21 subsurface. To the right of that, primarily in the 22 metering application Well then go through the key 22 east of the unit we have lands in brown with the hash 23 regulations that we believe apply that Jon mentioned in 23 marks that tun from the bottom left to the top right 24 his opening and touch on the elements of our design 24 are owned by Kuukpik on the surface and ASRC on the 25 which may net strictly conform with the rules as 25 subsurface. And then that leaves us with the lands in 4 (Pages 10 to 13) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net i TRANSCRIPT OF PUBLIC--"ARING 5/3/2016 DOCKET NO OTH-005 5 (Pages 14 to 17) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 14 Page 16 1 the middle with the hashmarks that are running from the 1 Those will then be metered whenever they arrive on the 2 top left to the bottom right where they are owned by 2 unit. And then the lifl gas and fuel gas will then 3 Kuukpik on the surface, but a mixture of ASRC and state 3 each individually be measured as they split and go to 4 for the subsurface. 4 their respective users. The water will also be 5 In the Greater Mouses Tooth unit we have the — 5 measured at the Greater Mooses Tooth unit. 6 in the blue boxes are the BLM lands owned as surface 6 Part of highlighting in this chart is to show 7 and subsurface and then the boxes in brown are to 7 the off lease measurement of the gas which is one of 6 denote the selected or conveyed lands that are owned by a our requests for waiver. The other item to here is as 9 the Kuukpik on the surface and ASRC on the subsurface. 9 this being the point of custody transfer is the 10 So moving on to slide number 6 we are proposing 10 envision that, you know, this is essentially receiving 11 today a measurement design that bas evolved through 11 an allocation factor of one where the Greater Mooses 12 multiple discussions with various stakeholders 12 Tooth unit will be kept whole in relation to the LACT 13 including state and federal agencies that has resulted 13 metering at the CRU. 14 in a design of a three phased production separator and 14 Moving on to slide number 8 we have a 15 associated metering that we believe achieves a high 15 simplified process flow diagram of the three phase 16 level of hydrocarbon measurement accurucy within a cost 16 separator. So I'll start with the orange lines coming 17 [bat allows the GMTI project to remain viable. Our 17 off the top which are the gas. We have dual gas is design also allows for the efficient use of misting 18 measurement with two different size (indiscernible) 19 infrastructure that helps us to reduce cost and limit 19 meters, four inch and six inch, to allow us to capture 20 the gravel footprint, air emissions and other 20 the range of production that could come through the gas 21 environmental impacts. The proposed design is also 21 side for those will be measured. And then coming off 22 consistent with the 2012 NPR -A integrated activity plan 22 the middle we have the oil leg that will go through or 23 EIS where GMTI was evaluated as a satellite development 23 have a slipstream for the composite sampler. There 24 relying on the Alpine central facilities for processing 24 will also be a Phase Dynamics water cut meter on that 25 and it also complies with the LAP stipulation E-5 25 line to measure the oil -- the water in oil and then Page 15 Page 17 1 requiring the sharing of facilities with existing 1 those streams will go through the Coriolis meters, dual 2 development in order to minimize project footprint. 2 meters, both four inch. And then coming off the bottom 3 Moving on to slide number 7, this slide is 3 of the three phase separator we have the water leg that 4 intended to give an overview of the relationship 4 will go through a mag meter and be measured. And then 5 between the two units and how the measurement is 5 all three fluids will be recombined going into our 6 arranged. The green ovals are to note where we had 6 production line that will be sent on to CD5 and then 7 measurement taking place. 7 eventually to the Alpine central facility. 8 And we'll start with the Greater Mouses Tooth 6 The next slide is slide number 9. This slide 9 unit and the three phase production separator where we 9 is to give a little bit more detail into what happens 10 willhave measurement for the oil, the gas and the 10 at the Alpine central facility. The lines that are 11 water. And we consider this to be the point of custody 11 noted in the dotted lines in various colors indicate 12 transfer. Those fluids will be then recombined after 12 where there's -- the project is in development and net 13 measurement and travel to the Colville River unit where 13 in service yet and then the solid lines are for 14 they will be commingled with fluids from CD5, CD4, CD2, 14 everything that is in service. Pve highlighted here 15 CD3 and CDI, all being processed at the Alpine central 15 where -- the Lookout PA which is associated with the 16 facility. At this Facility the production fluids will 16 Greater Mouses Tooth 1 development. Also a note of 17 be stripped of thew gas and water where the oil can be 17 reference at the bottom. In slide number 20 there is a is stabilized and then that oil will be sold and go on to 18 reference with all the acronyms and also a able that 19 the Alpine pipe line which will eventually make its way 19 shows which PAs belong to which drill sites. 20 to TAPS. 20 So starting with the inlet separator we have 21 From the CRU we will have gas and water that 21 all of lite production from the various drill sites 22 will be seat back to the Greater Mooser Tooth unit. 22 commingling and corning into the Alpine central facility 23 The gas will go in two separate lines, one carrying the 23 into an inlet separator. Those fluids then -- you have 24 fuel gas and lift gas or used as fuel gas and lift gas 24 the gas phase coming off the top which will go through 25 and the other line used as miscible injection gas. 25 additional gas processing and gas enrichment. And then 5 (Pages 14 to 17) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net I TRANSCRIPT OF PUBLIC --,TARING 5/3/2016 DOCKET NO OTH-005 6 (Pages 18 to 21) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 18 Page 20 1 (hat gas will then either be sent as gas enrichment 1 live oil measurement at the drill site. Live oil is 2 back to the PAs or be used as lift gas and injection 2 oil that -- or live fluids are oil lhafs at elevated 3 gas also coming back to the PAs and those lines are 3 pressures and temperatures and at GMTI it would not 4 noted in red. 4 have gone through any other processing other than the 5 The liquid line from the inlet separator then 5 three phase separator. 6 goes through oil processing where the water will be 6 Live fluids are convened from observed volumes 7 dropped out and the oil stabilized. The oil and the 7 to standard volumes through the application of a s condensate from the stabilizer will then be sent on to a shrinkage factor. Shrinking factors account for the 9 (be sales meter and on to the Alpine pipe line. The 9 loss of light in hydrocarbons based on phase change or 10 water does have the ability to switch between produced 10 the volume changes that are associated with volt, 11 water and seawater being seat back to the different 11 pressure and temperature affects on the fluids. The 12 drill sites so we do have an inlet supply of seawater 12 shrinkage factors are derived from PBT testing or 13 into the Alpine central facility noted in the line 13 equations of state modeling and the application of the 14 coming across the top and then we have the flexibility 14 shrinkage factor, this last bullet on slide 10, it 15 to send either produced water or seawater back to the 15 actually contributes approximately 2 percent to the 16 drill sites depending on our needs. Bm the blueline 16 overall measurement uncertainty for our proposed 17 show going back to each of the drill sites. 17 application And because of this the application of 18 CHAIR FOERSTER: So what do NK, FN and FK stand 16 the shrinkage factor is actually the largest 19 for? 19 contributor to that uncertainty calculation that was 20 MR. VIATOR: So (hose are also defined on that 20 provided in the application 21 reference sheet in the back, but this is..... 21 So for slide 11 this illustrates the flow 22 CHAIR FOERSTER: 1 didn'tsee them there. 22 calculation sequence that would be implemented in the 23 MR. VIATOR: There's a -- IN within the 23 flow computer at GMTI. Starting at the top we have the 24 table. Sothis is Nanuq..... 24 mass output of the Coriolis meters. Once you've 25 CHAIR FOERSTER: Ob, Somas. 25 combined that with the observed densities from the Page 19 Page 21 1 MR VIATOR: ..... Nanuq Kupamk..... 1 Coriolis meters you will get your calculated observed 2 CHAIR FOERSTER: Okay. 2 volumes. The Phase Dynamics meters on the oil leg 3 MP, VIATOR: ..... for NK, Fiord Nechelik for 3 would be used to determine your water cut and that 4 FN. 4 would be subtracted out of your -- your water cut 5 CHAIR FOERSTER: Thank you. 5 volumes would be subtracted out of your observed 6 MR VIATOR: Okay. Any other questions before 6 volumes to gel to your net observed volume. Now this 7 1 move on? 7 is where for GMT] we would apply our shrinkage factor a (No comments) a in order to get to our net standard volume of oil for 9 JODY HOSACK 9 the drill site. 10 previously sworn, called as a witness on behalfof 10 Slide 12, this is where the -- we're going to 11 Corhocol billips, testified as follows on: 11 be developing a shrinkage factor matrix that will use 12 DIRECT EXAMINATION 12 the compositional oil analysis and our process modeling 13 MS. HOSACK: For slide 10 I'd like to briefly 13 software to develop this shrinkage factor matrix. The 14 discuss the differences between LACT quality 14 matrix would be applied on the flow computer for a 15 measurements of stable fluids and that of the 15 standard volume detenninations and its going to be 16 measurement of live fluids. So for — in order to get 16 developed across a range of operating pressures and 17 LACT quality measurement at GMT I we would require a 17 temperatures. The flow computer will do the two way 18 processing fluid or processing facility to get to le linear interpolations so at a given pressure and 19 stable fluids. And then stable fluids are converted 19 temperature itll determine which shrinkage factor to 20 from a observed volume to a — to standard conditions 20 apply to the volume calculations. 21 or a standard volume through the application of 21 As necessary we will update the shrinkage 22 volume correction factor. API, they have developed 22 factor matrix by taking the new compositional data for 23 these empirical values and they're standardized in API 23 the oil and contorting it through our process modeling 24 MPMS, chapter 11. For GMTI with the use of a three 24 software in order to make sure that we're staying on 25 phase separator we're actually proposing single phase, 25 top of this matrix. I just want to point out that this 6 (Pages 18 to 21) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC --.TARING 5/3/2016 DOCKET NO OTH-005 7 (Pages 22 to 25) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 22 Page 24 1 methodology of applying a shrinkage factor is identical 1 and the gas streams. for the oil stream we have -- 2 to the way we apply shrinkage factor to the current CRU 2 we're installing a fast loop flow proportional sampling 3 well test and allocations. So there's really nothing 3 system that would aligned to the in service Coriolis 4 new as far as how we do this. 4 meter. The samples that we — monthly samples taken to 5 For slide 13 our proposed measurement system 5 do — to analyze for the composite measurement ofthe 6 along with robust operation and maintenance plans we 6 oil such that we can compare that to the online 7 feel we achieve the high measurement certainty. Our 7 parameters that we're seeing within our flow meters. a maintenance plans include things like advanced 8 Iftheres any discrepancies between the samples and 9 diagnostics, calibrations and visual inspections of the 9 what we're seeing online obviously that would again 10 metering equipment. 10 trigger an investigation to resolve the issue. As 11 So to talk about measurement point here for the 11 necessary these oil sample results will also be used to 12 oil Coriolis gas meters we will be implementing smart 12 tune the shrinkage factor matrix that I described 13 meter verification, That is an automatic diagnostic 13 earlier. 14 application that checks the internal -- it's an 14 For the gas measurement sampling each gas 15 internal diagnostic, checks how the meter is working 15 measurement — each gas meter will have a dedicated 16 and it also -- it can be done without disrupting the 16 flow through spot sampling station which we will take 17 process flow. So this is an online diagnostic 1/ monthly gas samples for compositional and BTU analysis. 16 application, 16 MR VIATOR: On slide 15 1 wanted to highlight 19 We will be scheduling the smart meter 19 the regulation, the Alaska Administrative Code 25.288 20 verification manthly and this will compare the online 20 and the elements that we think we comply with and then 21 Coriolis meter to the factory baseline value. If 21 the few items that we are discussing on the waiver. So 22 there's arty deviations outside of manufacturer's 22 the checkmarks in green indicate those elements of this 23 tolerances this would correct -- flag the meter for 23 regulation where we believe we comply with and deal 24 corrective maintenance actions on the Slope, to figure 24 have any concerns. But element number (a) where things 25 out what might be wrong with it. Additionally the 25 need to be measured prior to severance from the unit, Page 23 Page 25 1 Coriolis meters, each one will be removed from service 1 as we pointed out, you know, so the produced oil and 2 every year and they will be shipped off to an 2 gas streams will be measured prior to leaving GMT 1, 3 accredited flow test facility to get calibrated. 3 it's the gas stream leaving the Colville River unit and 4 For the gas measurement we are putting in AGI 4 coining back to GMTI that will be measured off lease at 5 compliant orifice meter runs. On those we will be 5 GMTI. Arid the usage of shrinkage factors is not 6 deploying a continuous DP diagnostic application 6 necessarily applicable for custody transfer, but it 7 software that will mankor -- it's a dynamic pressure 7 does comply with section — chapter 20.1 as a valid a sensing monitor that will warn -- reliably wam if you 6 method for allocation metering. So its still within 9 have problems with your orifice meter ran. So it will 9 the realm of API and MPMS. 10 be able to detect plugged impulse tubing lines, worn or 10 For items (g) and (b), prose get to the I bent plates, that type of thing, which again like the 11 discussion on proving and then provers being used for 12 Coriolis meters if there's any deviations outside of 12 certification. So what we have proposed for the oil 13 manufacturer's tolerance that would flag corrective 13 meters is the use ofadvanced monthly verification, the 14 maintenance. Additionally every year we will be 14 smart meter verification supported by annual meter is pulling out the orifice plate for inspection and we 15 calibration. We do believe that that is — falls into 16 will also be doing a full baroscope inspection on the 16 the realm of being equal to or better than the noted 17 entire meter ran. 17 proving methodologies. And then we arecompliance with is For the Phase Dynamics water cut analyzer and is the gas meter calibration requirements so don't have 19 the secondary instruments that are used for pressure 19 any concerns there. 20 and temperature measurements we will be calibrating 20 Item 0) relates to, you know, upon request the 21 those quarterly and additionally the Phase Dynamic will 21 Commission having the authority to approve a variance 22 also he cross verified with our sampling, our flow 22 if equal or improve accuracy. So we are requesting 23 proportional sampling results every month 23 approval for the Commission's discretion to off lease 24 So for slide 14 as far as sampling we are 24 tneasurennent and for custody transfer teetering. 25 sampling -- we have a sampling plan for both the oil 25 Slide number 16 relates to the AOGCC industry 7 (Pages 22 to 25) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net I TRANSCRIPT OF PUBLIC ..BARING 5/3/2016 DOCKET NO OTH-005 8 (Pages 26 to 29) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 26 Page 26 1 guidance bulletin 13-002. Again the elements 1 LACT metering. 2 highlighted in green or checked in green are things 2 So slide number 18 is the last slide that I 3 that we have provided and are known, but the other 3 have and reallyjust kind of a status and summary. So 4 items at this time, the things circled in blue, we 4 the Greater Mouses Tooth I project is currently 5 dont have those details available, they will come once s finishing up detailed engineering. We've started 6 we have the manufacturer's selected and receive their 6 elements of our procurement process and we are still 7 details. So other than those items noted above, you 7 working on finalizing the production separator details 8 know, the remaining details that are required are not a that may come out of this hearing and our discussions 9 available at this time so we physically can't provide 9 with the BLM. 10 them. 10 So as Jon mentioned in the opening we are 11 CHAIR FOERSTER: But you don't expect any 11 requesting both BLM and AOGCC approvals now for 12 compliance issues with them? 12 measurement so that we can finalize this design and 13 MR. VIATOR: No, ma'am. 13 move forward with the procurement process for the 14 CHAIR FOERSTER: Okay. 14 necessary equipment. And again we've presented a is MR. VIATOR: And these items, you know, we'll 15 design concept, a metering philosophy that we believe 16 -- we do plan to install in 2018 with the start up as 16 is one that is economically viable and can be accepted 17 rated in fourth quarter 2018, but the exact 17 by the agencies and then also knowing [bat we do have 18 installation date hasn't been defined at this time, but 18 the request Cor the off lease measurement for the CRU 19 it will be some time in that last year of construction. 19 gas going back to the Greater Mouses Tooth 1. 20 Slide number 17 gets to the economic analysis 20 CHAIR FOERSTER: Thank you. 21 of a production facility and the reasoning driving us 21 MR VIATOR: Yeah. 22 to not having a process facility and being able to 22 CHAIR FOERSTER: Do you have any questions at 23 measure in accordance with custody transfer 23 this time, Commissioner Seamounl? I'd like o suggest 24 requirements for LACT metering. On the right we've 24 that we take a brief recess and let our intelligent 25 noted the premises that we've used for this analysis. 25 stafflum our curiosity questions into intelligent Page 27 Page 29 1 So we have assumed a 10 percent discount rate and are 1 ones if that's okay with you? 2 using a January 1, 2016.4 present value date. We are 2 COMMISSIONER SEAMOUNT: That's fine. 3 utilizing the Alaska Department of Revenue fall, 2015 3 CHAIR FOERSTER: Okay. All right. It is 9:40 4 price forecast And this assumes a 100 percent working 4 and we're going to take a 20 minute recess and 5 interest. The capital cost for the production facility 5 reconvene at 10:00. We're recessed. 6 was estimated at $500 million. Expense for operating 6 (Offrecord - 9:40 am) 7 cost is estimated at $45 million per year and we also 7 (On record - 10:06 a.m) 8 believe there would be a four year project delay moving 8 CHAIR FOERSTER: Back on the record at 10:06, 9 first oil to 2022. That would be associated with 9 we apologize for taking an extra five minutes. 10 reopening the pertaining and additional engineering 10 All right. Commissioner Scamoma, would you 11 that would be needed. 11 like -- do you have any questions? 12 So what we can see here is for with these 12 COMMISSIONER SEAMOUNT: Yes, I'll start with 13 assumptions, you know, the project as it stands and 13 some simple ones, I'm the geologist here then mire 14 proposed today having a value related to 100 percent, 14 complicated ones I'll send over to the engineer since 15 with the investment alone of the $500 million for the 15 she's more experienced at this sort of thing. 16 production facility that alone takes it to -- erodes 16 Is it Mr. Viator? 17 all of the value and takes it to a negative project and 17 MR. VIATOR: Yes, sir. 18 one that we would not be able to proceed with. You 1e COMMISSIONER SEAMOUNT: Viator. Okay. Let's 19 further add on the operating costs, that erodes room 19 look at slide number 4. Its a map and it shows the 20 value and then the four year delay would add additional 20 Greater Mouses Tooth unit and it shows it to be much 21 decrease in value to the project where overall the 21 larger than the Colville River unit. And it's in red. 22 project would have a negative 300 percent MPV value 22 Is that you anticipated area of production or does it 23 relative to our starting point So this would be 23 include soma protection acreage in Were? 24 something that ConocoPhillips just wouldn't be able to 24 MR. VIATOR: The Greater Manses Tooth unit is 25 continue with on the GMTI project if we were to achieve 25 notjust GMT], you know, there's other potential 8 (Pages 26 to 29) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..CARING 5/3/2016 DOCKET NO OTH-005 9 (Pages 30 to 33) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 30 Page 32 1 participating areas within that unit. But GMT] only 1 processing facility we really would not even proceed 2 includes the Lookout PA 2 with the project. When we did this evaluation 3 COMMISSIONER SEAMOUNT: Okay. So that big old 3 previously the four year delay would come in the form 4 red blob there where it's not really red on the screen, 4 of needing to go back through the SEIS project and 5 but a lot of that includes exploration acreage; is that 5 reopen that, doing the evaluations of what 6 correct? 6 environmental impacts might be as well as engineering 7 MR. VIATOR: Yes. 7 design and going back to the engineering phase, a COMMISSIONER SEAMOUNT: Okay. Now the Bear a reopening that and the delays associated with 9 Tooth mit to the northwest, are you going to be 9 procurement and engineering design. 10 requesting the same son of approval of operations as 10 COMMISSIONER SEAMOUNT: So are you saying that 11 you are today? a you would just completely give up on the project? 12 MR. VIATOR: I don't believe we could make that 12 MR. VIATOR: At this time, yes, sir. 13 statement at this time. We haven't done a sufficient 13 COMMISSIONER SEAMOUNT: And would that include 14 amount of thought on those developments and how we 14 all projects to the west? 15 would approach those, but 1 dont believe that we cold 15 MR. VIATOR: Not necessarily, but we would need 16 say with any certainly that we would do them the same 16 a sufficient amount of development resource that would 17 as GMTI or that we would do them different. 17 support the processing facility. 16 COMMISSIONER SEAMOUNT: Okay. What's the 18 CHAIR FOERSTER: So you might put GMTI on hold 19 gravity of the oil were talking about today? 19 and do more exploration to get a larger conglomerate 20 MR. VIATOR: 1 don't have that information. 20 before you proceeded? 21 CHAIR FOERSTER: All right. Well, well leave 21 MR. VIATOR: We would have to really evaluate 22 the record open for -- at the end of the hearing well 22 that, 1 can't say that with certainly. 23 decide on the amount of time you ll need to answer any 23 COMMISSIONER SEAMOUNT: Okay. Those are the 24 questions you can't answer today and we'll just leave 24 simple questions. I'll flip it over to Chair Foersler. 25 the record open to allow you to answer questions that 25 CHAIR FOERSTER: And mine are going to be kind Page 31 Page 33 1 you don't have, you knew, the answer now, 1 of in a stream of consciousness format and I'm not 2 COMMISSIONER SEAMOUNT: I assume you dont know 2 going to follow a logical thought process, ifsjust as 3 what the GOR is eitheO 3 1 bad the questions I wrote them down and i'mjust 4 MR. VIATOR: I would need to confer. I have an 4 going to ask (hem that way. You talk about a shrinkage 5 idea, but I'd rather confer before giving you an 5 factor matrix, who's going to oversee that and make 6 incorrect answer. 6 sure, you know, that it's accurate, unbiased, ifs 7 COMMISSIONER SEAMOUNT: Okay. When you ship 7 appropriate? a off the Coriolis meter how are you going to do that and a MS. HOSACK: We do have a position that we're 9 where is it going? 9 planting to fill that's acct filled yet dial will be 10 MS. HOSACK: We haven't actually determined 10 overseeing the regulatory aspects of the metering 11 where we will be sending it yet. We'll be sending it 11 systems for both the state and the BLM. So I would 12 to an accredited facility for the calibration, but we 12 imaghle that position would be doing that along with 13 anticipate every six months essentially one of the 13 probably our production engineers that are monitoring 14 meters will be removed from service, crated up and then 14 the day to day production..... 15 shipped off to the facility. We will have a third 15 CHAIR FOERSTER: Okay. Well..... 16 meter that's essentially a standby meter that will 16 MS. HOSACK: .....from the drill site. 17 replace the one that's being sent off site for 17 CHAIR FOERSTER: All right. Well likely -- if is calibration. So it'll be three meters that rotate 18 we approve this request well likely require that you 19 through the two metering stations 19 had a third party outside source, you know, for review. 20 COMMISSIONER SEAMOUNT: Okay. Now if this is 20 And we've done that for others who've come to us with 21 not approved, you talked about a four year delay, 21 things like this so put that into your thinking that if 22 where's the delay going to be, what's that going to 22 this gets approved you're going to have to fund an 23 encompass? 23 outside, unbiased third parry that's willing to sign 24 MR. VIATOR: Well, the -- I guess the first 24 off and say this down[ have a Conoco bias to it. 25 response to (bat is, you know, if we were to do the 25 MS. HOSACK: Okay. 9 (Pages 30 to 33) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..CARING 5/3/2016 DOCKET NO OTH-005 10 (Pages 34 to 37) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 34 Page 36 1 CHAIR FOERSTER: Okay. Sojust put that into 1 somebody to do. I think the people in the back of the 2 your thoughts. Are you getting positive vibes from the 2 room are probably doing that too. 3 BLM, you think they're going to approve? 3 Can you characterize where you get the 2.1 4 MR. VIATOR: Yes. I mean, in our discussions 4 percent from, some more details on where those 5 that we've had they haven't indicated any major 5 uncertainties reside and then how they'll change over 6 concerns and where we're at today with the design is 6 time? 7 really what they were wanting. 7 MS. HOSACK: So the uncertainty calculation was a CHAIR FOERSTER: Okay. And do you see any 8 — the full uncertainty calculation was provided in the 9 issues with them? 9 application. Again the largest contributor is the 10 MR VIATOR No, ma'am 10 shrinkage factor to that. 1 don't remember the 11 CHAIR FOERSTER: We always try to be consistent 11 specific numbers off the top of my head, but the meter 12 and fair and reasonable and treat everybody the same so 12 itself, the Coriolis meters, the uncertainties for the 13 we4e looking back on other situations we've had like 13 Phase Dynamic were accounted for in the calculation 14 this. And you mentioned Oooguruk, but in a more recon 14 over the range of operating pressures and temperatures 15 one we required more detail on the economic analysis. 15 that -- and Row rates that we're anticipating. 16 Would -- of course it was held conhden6al, but would 16 CHAIR FOERSTER: Okay. So why are you assuming 17 you be willing to sit down with our engineers and 17 an allocation factor crone for meter? 18 provide more detail on your economic analysis of the 18 MR. VIATOR: The Greater Mouses Tooth unit 19 project? 19 being located in the federal lands, you know, is really 20 MR VIATOR: I think we'd want to discuss that 20 a requirement from the BLM that it be kept whole. 21 internally, but I would think that we'd be able to get 21 CHAIR FOERSTER: Okay. And why are you 22 to some..... 22 measuring the gas sent to GMT at GMT rather than CRU, 23 CHAIR FOERSTER: Okay. 23 that's one of the things you're asking for a variance 24 MR, VIATOR: ..... arrangement. 24 on so why do you need that variance? 25 CHAIR FOERSTER: That might be a requirement. 25 MR. VIATOR: The split off for the gas line Page 35 Page 37 1 MR. VIATOR: Yeah 1 mining from the ACF that eventually goes to GMT, the 2 CHAIR FOERSTER: Is this system substantially 2 last T in the line is going out to CD5 so that's where 3 different from what you use at Colville River? 3 we would have to put the meter. And the difficulty 4 MR- VIATOR: We have the -- the test separators 4 with installing the metering in a brownfield situation 5 that we're having at GMTI are the same that are used in 5 at CD5 where it wasn't planned for another module the 6 the Colville River unit, but the Colville River unit 6 cost associated with installing it at CD5 and the 7 doesn't have a production separator. 7 complexity and potential impact on maintenance and 8 CHAIR FOERSTER: So what's the uncertainty in 8 access to our existing wells over there, we thought 9 measurements that you got at CRU, you're talking about 9 that it was much simpler to have it in the design from 10 a 2 percent here, what are you seeing at the CRU? 10 the beginning at GMTI, it would be less cost and there 11 MS. HOSACK: I mean, over time the allocation 11 would be no difference in the accuracy of the meter. 12 system at CRU has -- it's centered right around one or 12 CHAIR FOERSTER: So even though API recognizes 13 the life of the facilities there at Alpine. 13 your Coriolis meter as acceptable our current 14 CHAIR FOERSTER: I percent uncertainty? 14 regulations do not. So that does require a variance 15 MS. HOSACK: Well, the allocation factor of 15 and it requires an equal or better accuracy variance sc 16 one. I'm sorry. So it's -- I don't think we have 16 we do need some details on you from that. Would you 17 actual -- I mean, I'm not certain of the..... 17 need any of these variances ifyou just combined the 18 CHAIR FOERSTER: Did you get..... 18 two units? 19 MS.HOSACK ..... uncertainty calcs for that. 19 MR VIATOR If the units were combined then 20 CHAIR FOERSTER: ..... would you write -- make 20 the GMT development would bejust like any of the 21 -- if you've got somebody taking a list of questions 21 other CRU developments and only need the allocation. 22 that remain unanswered..... 22 CHAIR FOERSTER: So you wouldn't treed any 23 MS. HOSACK: Okay. 23 custody transfer variances, you'djust need allocation? 24 CHAIR FOERSTER: ..... add that to it. I think 24 MR. VIATOK: Okay. 25 that would be a good thing for maybe Mr. Goltz to do or 25 CHAIR FOERSTER: Did you consider combining the 10 (Pages 34 to 37) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..TARING 5/3/2016 DOCKET NO OTH-005 11 (Pages 38 to 41) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fac: 907-243-1473 Email: sahile@gci.net Page 38 Page 40 1 units? 1 some method ofdetermining that. 2 MR. VIATOR: In this development the decision 2 CHAIR FOERSTER: Okay. 3 to have the units separate was already made by the time 3 MS. HOSACK: In the..... 4 we started to do the metering design. So it wasn't — 4 CHAIR FOERSTER: So..... 5 it was considered and I've said as the basis that they s MS. HOSACK: ..... waterstream for sure..... 6 would be separate units. 6 CHAIR FOERSTER: So it wouldn't be unreasonable 7 CHAIR FOERSTER: Why was that done, do you 7 of us..... 8 know? 8 MS. HOSACK .....might be more complicated, 9 MR. VIATOR: I don't have the full history, but 9 but..... 10 we can talk about that and.... 10 CHAIR FOERSTER: ..... to make that a constraint 11 CHAIR FOERSTER: Okay. If you can give us sane 11 of approval Was an expert you think that you probably 12 historical perspective..... 12 should have done that? 13 MR VIATOR: Yeah. 13 MS. HOSACK On the water leg, yes,1 14 CHAIR FOERSTER: ..... on that and its one of 14 would..... is the things that well leave the record open for that 15 CHAIR FOERSTER: Okay. 16 would be good. 16 MS. HOSACK .....I would agree. 17 Were going to need a lot more detail on the 17 CHAIR FOERSTER: Okay. You say youll have 2.1 is smart diagnostics in order to buy off on that and so is percent uncertainty and what would be the uncertainty 19 can you provide that to our technical staff! 19 required by our regs, it's a lot tighter than that, 20 MS. HOSACK Yes, we have no problem providing 20 isn't it, in our regulations for custody transfer 21 that Do you want it for both the Coriolis meter as 21 metering? 22 well as the gas meters or..... 22 MS. HOSACK I personally don't remember seeing 23 CHAIR FOERSTER: Yes. 23 any targets on uncertainty within the regs, but 24 MS. HOSACK Both of them. Okay. 24 generally custody transfer is 0.35 percent. typical. 25 CHAIR FOERSTER: Yes. So how will you account 25 CHAIR FOERSTER: Okay. So our variance does Page 39 Page 41 1 Cor entrained oil in the water stream? 1 state that we grant a variance ifyou can provide equal 2 MS. HOSACK So right now we are planning to 2 or greater accuracy and so how do you address that 2.1 3 Just use the level measurement in the vessel to make 3 is not equal or greater to 0.3? 4 sure we're not pushing oil out the water leg, 4 MR. GOLTZ: IN might interject on that issue. 5 significant quantities of it. The vessel is being s That's one of the reasons why we are suggesting that 6 sized for — to ensure that we have enough residence 6 the Commission issue an order that's not necessarily 7 time, that we get good separation and were not pulling 7 strictly under section 225 including the variance 8 oil. 8 provision in subsection (j). The Commission does have 9 CHAIR FOERSTER: So the answer is you're going 9 authority to approve a measurement system that's an 10 to assume there isn't any? 10 adequate measurement system even if doesn't conform to 11 MS. HOSACK We don't have provisions to 11 228. 12 momiwr that in this current design. 12 CHAIR FOERSTER: Okay. Okay. Did 1 leave any 13 CHAIR FOERSTER: Okay. So the answer to my 13 simple questions for you? 14 question is yes, youW going to assume there isn't any 14 COMMISSIONER SEAMOUNT: No. is oil carried over into the water. Okay. And so how are 15 CHAIR FOERSTER: Okay. Does Corroon have 16 you going to account for entrained oil in the gas 16 anything else that they would like to say before we 17 stream? 17 invite anyone else in the audience to talk? is MS. HOSACK We don't have any provisions for 18 MR. VIATOR: No. 19 accounting for that..... 19 CHAIR FOERSTER: Okay. Is there anyone else 20 CHAIR FOERSTER: Okay. 20 who wishes to testify? 21 MS. HOSACK ..... either. 21 (No comments) 22 CHAIR FOERSTER: Okay. All right As an 22 CHAIR FOERSTER: Any ofdne people that work 23 instrumentation and measurement expert do you think 23 for these folks who think they didn't represent you 24 that's a sound choice? 24 well? 25 MS. HOSACK We probably should, yes, include 25 (No comments) 11 (Pages 38 to 41) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fac: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..TARING 5/3/2016 DOCKET NO OTH-005 12 (Pages 42 to 45) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net Page 42 Page 44 1 CHAIR FOERSTER: All right. So let's talk 1 month would be sufficient, too much? 2 about -- how long do you think you'll need to provide 2 MR. GOLTZ: I think that's reasonable. 3 answers to the unanswered questions. 3 CHAIR FOERSTER: Okay. All right. So let's 4 MR. GOLTZ: Well, I -- what I would most like 4 see today is May 3rd, well leave the record open until 5 to do is tan through my list to make sure that I..... 5 June 3rd for providing additional information to our 6 CHAIR FOERSTER: Okay. Make sure it's 6 staff. 7 accurate. Tlmt's a good idea. 7 Is that okay with you, Commissioner Seamount? 6 MR. GOLTZ: ..... that we've got it right and a COMMISSIONER SEAMOUNT: Yeah. 9 then I'll..... 9 CHAIR FOERSTER: Okay. All right. If there's 10 CHAIR FOERSTER: Okay. Because I've got a list 10 an one else wishing to testify and Conoco has — feels 11 of..... 11 like they said all they want to say then I will adjourn 12 MR. GOLTZ: ..... think about an answer. 12 this hearing at 10:26. The record stays open until 13 CHAIR FOERSTER: Okay. Go ahead. 13 June 3rd. 14 MR. GOLTZ: I had down a request to identify 14 (Hearing adjourned 10:26 a.m.) 1s the gravity of the oil, number 1; number 2, the GOR; 15 9:43:11 16 three, a detailed analysis you indicated would be pan 16 (END OF REQUESTED PORTION) 17 of the discussion with the engineers that would 17 18 potentially include additional economic information 19 19 (hat the Commission would hold confidential; four, 19 20 identification of the measurement uncertainty that we 20 21 experience at the Colville River unit; five, there's a 21 22 question that maybe we need to fill out a little bit 22 23 more about whether a variance would be necessary if the 23 24 units were combined and related to that was some more 24 25 information about the history of how these units came 25 Page 43 Page 45 1 to be crealed as separate units; and a request for more 1 CERTIFICATE 2 information on the smart diagnostics both on the 2 UNITED STATES OF AMERICA ) 3 Coriolis and the gas meters. )m 4 CHAIR FOERSTER: Uh-huh. 3 STATE OF ALASKA ) 5 MR GOLTZ: I think we might also need to 4 1, Salena A. Hile, Notary Public in and for the 5 state of Alaska, residing in Anchorage in said slate, 6 explain a little bit better in our response how we 6 do hereby certify that the foregoing matter: Docket 7 accounted for oil that might be entrained in a water 7 No.: OTH 16-005 was nanscribed to the best of our 6 leg or in a gas leg as well. That's all I've a ability; Pages 02 through 45; 9 identified as questions. 9 IN WITNESS WHEREOF I have hereunto set my hand 10 CHAIR FOERSTER: And did — I may have missed 10 and affixed my seal this I Ith day of May 2016. 11 it, did you include in there a review in greater detail 11 12 oftheeca mmlc5? 12 Salem A. Hite 13 MR GOLTZ: Yes, I do have that. 13 Notary Public, State of Alaska 14 CHAIR FOERSTER: Okay. My Commission Expires: 09/16/2018 15 MR GOLTZ: I think that'll -- I expect that to 14 16 be kind of a discussion about what might be expected by 15 17 the Conammion. At this point I don't know what 16 18 additional information we might provide..... 17 19 CHAIR FOERSTER: That could be..... 18 19 20 MR GOLTZ: ..... but we're happy to..... 20 21 CHAIR FOERSTER:.... just a discussion between 21 22 you and our staff. 22 23 MR GOLTZ: Okay. 23 24 CHAIR FOERSTER: Okay. So to get through all 24 25 of this do you think leaving the record open for a 2S 12 (Pages 42 to 45) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net TRANSCRIPT OF PUBLIC __CARING 5/3/2016 DOCKET NO OTH-005 Page 31 1 you don't have, you know, the answer now. 2 COMMISSIONER SEAMOUNT: I assume you don't know 3 what the GOR is either? 4 MR. VIATOR: I would need to confer. I have an 5 idea, but I'd rather confer before giving you an 6 incorrect answer. 7 COMMISSIONER SEAMOUNT: Okay. When you ship 8 off the Coriolis meter how are you going to do that and 9 where is it going? 10 MS. HOSACK: We haven't actually determined 11 where we will be sending it yet. We'll be sending it 12 to an accredited facility for the calibration, but we 13 anticipate every six months essentially one of the 14 meters will be removed from service, crated up and then 15 shipped off to the facility. We will have a third 16 meter that's essentially a standby meter that will 17 replace the one that's being sent off site for 18 calibration. So it'll be three meters that rotate 19 through the two metering stations. 20 COMMISSIONER SEAMOUNT: Okay. Now if this is 21 not approved, you talked about a four year delay, 22 where's the delay going to be, what's that going to 23 encompass? 24 MR. VIATOR: Well, the -- I guess the first 25 response to that is, you know, if we were to do the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net I TRANSCRIPT OF PUBLIC -.TARING 5/3/2016 DOCKET NO OTH-005 Page 32 1 processing facility we really would not even proceed 2 with the project. When we did this evaluation 3 previously the four year delay would come in the form 4 of needing to go back through the SEIS project and 5 reopen that, doing the evaluations of what 6 environmental impacts might be as well as engineering 7 design and going back to the engineering phase, 8 reopening that and the delays associated with 9 procurement and engineering design. 10 COMMISSIONER SEAMOUNT: So are you saying that 11 you would just completely give up on the project? 12 MR. VIATOR: At this time, yes, sir. 13 COMMISSIONER SEAMOUNT: And would that include 14 all projects to the west? 15 MR. VIATOR: Not necessarily, but we would need 16 a sufficient amount of development resource that would 17 support the processing facility. 18 CHAIR FOERSTER: So you might put GMT1 on hold 19 and do more exploration to get a larger conglomerate 20 before you proceeded? 21 MR. VIATOR: We would have to really evaluate 22 that, I can't say that with certainty. 23 COMMISSIONER SEAMOUNT: Okay. Those are the 24 simple questions. I'll flip it over to Chair Foerster. 25 CHAIR FOERSTER: And mine are going to be kind Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..TARING 5/3/2016 DOCKET NO OTH-005 Page 33 1 of in a stream of consciousness format and I'm not 2 going to follow a logical thought process, it's just as 3 I had the questions I wrote them down and I'm just 4 going to ask them that way. You talk about a shrinkage 5 factor matrix, who's going to oversee that and make 6 sure, you know, that it's accurate, unbiased, it's 7 appropriate? g MS. HOSACK: We do have a position that we're 9 planning to fill that's not filled yet that will be 10 overseeing the regulatory aspects of the metering 11 systems for both the state and the BLM. So I would 12 imagine that position would be doing that along with 13 probably our production engineers that are monitoring 14 the day to day production..... 15 CHAIR FOERSTER: Okay. Well..... 16 MS. HOSACK: .....from the drill site. 17 CHAIR FOERSTER: All right. We'll likely -- if 18 we approve this request we'll likely require that you 19 had a third party outside source, you know, for review. 20 And we've done that for others who've come to us with 21 things like this so put that into your thinking that if 22 this gets approved you're going to have to find an 23 outside, unbiased third party that's willing to sign 24 off and say this doesn't have a Conoco bias to it. 25 MS. HOSACK: Okay. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC, ..CARING 5/3/2016 DOCKET NO OTH-005 Page 34 1 CHAIR FOERSTER: Okay. So just put that into 2 your thoughts. Are you getting positive vibes from the 3 ELM, you think they're going to approve? 4 MR. VIATOR: Yes. I mean, in our discussions 5 that we've had they haven't indicated any major 6 concerns and where we're at today with the design is .7 really what they were wanting. 8 CHAIR FOERSTER: Okay. And do you see any 9 issues with them? 10 MR. VIATOR: No, ma'am. 11 CHAIR FOERSTER: We always try to be consistent 12 and fair and reasonable and treat everybody the same so 13 we're looking back on other situations we've had like 14 this. And you mentioned Oooguruk, but in a more recent 15 one we required more detail on the economic analysis. 16 Would -- of course it was held confidential, but would 17 you be willing to sit down with our engineers and 18 provide more detail on your economic analysis of the 19 project? 20 MR. VIATOR: I think we'd want to discuss that 21 internally, but I would think that we'd be able to get 22 to some..... 23 CHAIR FOERSTER: Okay. 24 MR. VIATOR: .....arrangement. 25 CHAIR FOERSTER: That might be a requirement. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC __TARING 5/3/2016 DOCKET NO OTH-005 Page 35 1 1 MR. VIATOR: Yeah. 2 CHAIR FOERSTER: Is this system substantially 3 different from what you use at Colville River? 4 MR. VIATOR: We have the -- the test separators 5 that we're having at GMT1 are the same that are used in 6 the Colville River unit, but the Colville River unit 7 doesn't have a production separator. 8 CHAIR FOERSTER: So what's the uncertainty in 9 measurements that you got at CRU, you're talking about 10 a 2 percent here, what are you seeing at the CRU? 11 MS. HOSACK: I mean, over time the allocation 12 system at CRU has -- it's centered right around one or 13 the life of the facilities there at Alpine. 14 CHAIR FOERSTER: 1 percent uncertainty? 15 MS. HOSACK: Well, the allocation factor of 16 one. I'm sorry. So it's -- I don't think we have 17 actual -- I mean, I'm not certain of the..... 18 CHAIR FOERSTER: Did you get..... 19 MS. HOSACK .....uncertainty calcs for that. 20 CHAIR FOERSTER: .....would you write -- make 21 -- if you've got somebody taking a list of questions 22 that remain unanswered..... 23 MS. HOSACK: Okay. 24 CHAIR FOERSTER: .....add that to it. I think 25 that would be a good thing for maybe Mr. Goltz to do or Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..CARING 5/3/2016 DOCKET NO OTH-005 Page 36 1 somebody to do. I think the people in the back of the 2 room are probably doing that too. 3 Can you characterize where you get the 2.1 4 percent from, some more details on where those 5 uncertainties reside and then how they'll change over 6 time? 7 MS. HOSACK: So the uncertainty calculation was 8 -- the full uncertainty calculation was provided in the 9 application. Again the largest contributor is the 10 shrinkage factor to that. I don't remember the 11 specific numbers off the top of my head, but the meter 12 itself, the Coriolis meters, the uncertainties for the 13 Phase Dynamic were accounted for in the calculation 14 over the range of operating pressures and temperatures 15 that -- and flow rates that we're anticipating. 16 CHAIR FOERSTER: Okay. So why are you assuming 17 an allocation factor of one for meter? 18 MR. VIATOR: The Greater Mooses Tooth unit 19 being located in the federal lands, you know, is really 20 a requirement from the 13LM that it be kept whole. 21 CHAIR FOERSTER: Okay. And why are you 22 measuring the gas sent to GMT at GMT rather than CRU, 23 that's one of the things you're asking for a variance 24 on so why do you need that variance? 25 MR. VIATOR: The split off for the gas line Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net TRANSCRIPT OF PUBLIC ..,TARING 5/3/2016 DOCKET NO OTH-005 Page 37 1 coming from the ACF that eventually goes to GMT, the 2 last T in the line is going out to CD5 so that's where 3 we would have to put the meter. And the difficulty 4 with installing the metering in a brownfield situation 5 at CD5 where it wasn't planned for another module the 6 cost associated with installing it at CD5 and the 7 complexity and potential impact on maintenance and 8 access to our existing wells over there, we thought 9 that it was much simpler to have it in the design from 10 the beginning at GMT1, it would be less cost and there 11 would be no difference in the accuracy of the meter. 12 CHAIR FOERSTER: So even though API recognizes 13 your Coriolis meter as acceptable our current 14 regulations do not. So that does require a variance 15 and it requires an equal or better accuracy variance so 16 we do need some details on you from that. Would you 17 need any of these variances if you just combined the 18 two units? 19 MR. VIATOR: If the units were combined then 20 the GMT1 development would be just like any of the 21 other CRU developments and only need the allocation. 22 CHAIR FOERSTER: So you wouldn't need any 23 custody transfer variances, you'd just need allocation? 24 MR. VIATOR: Okay. 25 CHAIR FOERSTER: Did you consider combining the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net I TRANSCRIPT OF PUBLIC ..CARING 5/3/2016 1 units? DOCKET NO OTH-005 Page 381 2 MR. VIATOR: In this development the decision 3 to have the units separate was already made by the time 4 we started to do the metering design. So it wasn't -- 5 it was considered and I've said as the basis that they 6 would be separate units. 7 CHAIR FOERSTER: Why was that done, do you 8 know? 9 MR. VIATOR: I don't have the full history, but 10 we can talk about that and..... 11 CHAIR FOERSTER: Okay. If you can give us some 12 historical perspective..... 13 MR. VIATOR: Yeah. 14 CHAIR FOERSTER: .....on that and it's one of 15 the things that we'll leave the record open for that 16 would be good. 17 We're going to need a lot more detail on the 18 smart diagnostics in order to buy off on that and so 19 can you provide that to our technical staff? 20 MS. HOSACK: Yes, we have no problem providing 21 that. Do you want it for both the Coriolis meter as 22 well as the gas meters or..... 23 CHAIR FOERSTER: Yes. 24 MS. HOSACK: Both of them. Okay. 25 CHAIR FOERSTER: Yes. So how will you account Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ncARING 5/3/2016 DOCKET NO OTH-005 Page 3 9 1 1 for entrained oil in the water stream? 2 MS. HOSACK: So right now we are planning to 3 just use the level measurement in the vessel to make 4 sure we're not pushing oil out the water leg, 5 significant quantities of it. The vessel is being 6 sized for -- to ensure that we have enough residence 7 time, that we get good separation and we're not pulling 8 oil. 9 CHAIR FOERSTER: So the answer is you're going 10 to assume there isn't any? 11 MS. HOSACK: We don't have provisions to 12 monitor that in this current design. 13 CHAIR FOERSTER: Okay. So the answer to my 14 question is yes, you're going to assume there isn't any 15 oil carried over into the water. Okay. And so how are 16 you going to account for entrained oil in the gas 17 stream? 18 MS. HOSACK: We don't have any provisions for 19 accounting for that..... 20 CHAIR FOERSTER: Okay. 21 MS. HOSACK: .....either. 22 CHAIR FOERSTER: Okay. All right. As an 23 instrumentation and measurement expert do you think 24 that's a sound choice? 25 MS. HOSACK: We probably should, yes, include Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..CARING 5/3/2016 DOCKET NO OTH-005 Page 40 1 some method of determining that. 2 CHAIR FOERSTER: Okay. 3 MS. HOSACK: In the..... 4 CHAIR FOERSTER: So..... 5 MS. HOSACK: .....waterstream for sure..... 6 CHAIR FOERSTER: So it wouldn't be unreasonable 7 of us..... S MS. HOSACK: .....might be more complicated, 9 but..... 10 CHAIR FOERSTER: .....to make that a constraint 11 of approval if as an expert you think that you probably 12 should have done that? 13 MS. HOSACK: On the water leg, yes, I 14 would..... 15 CHAIR FOERSTER: Okay. 16 MS. HOSACK: .....I would agree. 17 CHAIR FOERSTER: Okay. You say you'll have 2.1 18 percent uncertainty and what would be the uncertainty 19 required by our regs, it's a lot tighter than that, 20 isn't it, in our regulations for custody transfer 21 metering? 22 MS. HOSACK: I personally don't remember seeing 23 any targets on uncertainty within the reqs, but 24 generally custody transfer is 0.35 percent typical. 25 CHAIR FOERSTER: Okay. So our variance does Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net I TRANSCRIPT OF PUBLIC i TARING 5/3/2016 DOCKET NO OTH-005 Page 41 1 state that we grant a variance if you can provide equal 2 or greater accuracy and so how do you address that 2.1 3 is not equal or greater to 0.3? 4 MR. GOLTZ: If I might interject on that issue. 5 That's one of the reasons why we are suggesting that 6 the Commission issue an order that's not necessarily 7 strictly under section 22S including the variance 8 provision in subsection (j). The Commission does have 9 authority to approve a measurement system that's an 10 adequate measurement system even if doesn't conform to 11 228. 12 CHAIR FOERSTER: Okay. Okay. Did I leave any 13 simple questions for you? 14 COMMISSIONER SEAMOUNT: No. 15 CHAIR FOERSTER: Okay. Does Conoco have 16 anything else that they would like to say before we 17 invite anyone else in the audience to talk? 18 MR. VIATOR: No. 19 CHAIR FOERSTER: Okay. Is there anyone else 20 who wishes to testify? 21 (No comments) 22 CHAIR FOERSTER: Any of the people that work 23 for these folks who think they didn't represent you 24 well? 25 (No comments) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..CARING 5/3/2016 DOCKET NO OTH-005 Page 42 1 CHAIR FOERSTER: All right. So let's talk 2 about -- how long do you think you'll need to provide 3 answers to the unanswered questions. 4 MR. GOLTZ: Well, I -- what I would most like 5 to do is run through my list to make sure that I..... 6 CHAIR FOERSTER: Okay. Make sure it's 7 accurate. That's a good idea. 8 MR. GOLTZ: .....that we've got it right and 9 then I'll..... 10 CHAIR FOERSTER: Okay. Because I've got a list 11 of..... 12 MR. GOLTZ: .....think about an answer. 13 CHAIR FOERSTER: Okay. Go ahead. 14 MR. GOLTZ: I had down a request to identify 15 the gravity of the oil, number 1; number 2, the GOR; 16 three, a detailed analysis you indicated would be part 17 of the discussion with the engineers that would 18 potentially include additional economic information 19 that the Commission would hold confidential; four, 20 identification of the measurement uncertainty that we 21 experience at the Colville River unit; five, there's a 22 question that maybe we need to fill out a little bit 23 more about whether a variance would be necessary if the 24 units were combined and related to that was some more 25 information about the history of how these units came Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC ..,DARING 5/3/2016 DOCKET NO OTH-005 Page 43 1 to be created as separate units; and a request for more 2 information on the smart diagnostics both on the 3 Coriolis and the gas meters. 4 CHAIR FOERSTER: Uh-huh. 5 MR. GOLTZ: I think we might also need to 6 explain a little bit better in our response how we 7 accounted for oil that might be entrained in a water 8 leg or in a gas leg as well. That's all I've 9 identified as questions. 10 CHAIR FOERSTER: And did -- I may have missed 11 it, did you include in there a review in greater detail 12 of the economics? 13 MR. GOLTZ: Yes, I do have that. 14 CHAIR FOERSTER: Okay. 15 MR. GOLTZ: I think that'll -- I expect that to 16 be kind of a discussion about what might be expected by 17 the Commission. At this point I don't know what 18 additional information we might provide..... 19 CHAIR FOERSTER: That could be..... 20 MR. GOLTZ: .....but we're happy to..... 21 CHAIR FOERSTER: .....just a discussion between 22 you and our staff. 23 MR. GOLTZ: Okay. 24 CHAIR FOERSTER: Okay. So to get through all 25 of this do you think leaving the record open for a Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: saMle@gci.net TRANSCRIPT OF PUBLIC --.TARING 5/3/2016 DOCKET NO OTH-005 Page 44 1 month would be sufficient, too much? 2 MR. GOLTZ: I think that's reasonable. 3 CHAIR FOERSTER: Okay. All right. So let's 4 see today is May 3rd, we'll leave the record open until 5 June 3rd for providing additional information to our 6 staff. 7 Is that okay with you, Commissioner Seamount? 8 COMMISSIONER SEAMOUNT: Yeah. 9 CHAIR FOERSTER: Okay. All right. If there's 10 no one else wishing to testify and Conoco has -- feels 11 like they said all they want to say then I will adjourn 12 this hearing at 10:26. The record stays open until 13 June 3rd. 14 (Hearing adjourned 10:26 a.m.) 15 9:43:11 16 (END OF REQUESTED PORTION) 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC .. TARING 5/3/2016 DOCKET NO OTH-005 Page 45 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) )ss 3 STATE OF ALASKA ) 4 I, Salena A. Hile, Notary Public in and for the 5 state of Alaska, residing in Anchorage in said state, 6 do hereby certify that the foregoing matter: Docket 7 No.: OTH 16-005 was transcribed to the best of our 8 ability; Pages 02 through 45; 9 IN WITNESS WHEREOF I have hereunto set my hand 10 and affixed my seal this 11th day of May 2016. 11 12 Salena A. Hile 13 Notary Public, State of Alaska My Commission Expires: 09/16/2018 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: OTH-16-005 ConocoPhillips Alaska Inc. May 3, 2016 NAME AFFILIATION Testify (yes or no) 65 P5 �ea�+ai 6a 1Zfl lio 1Ee5 )1411,4 UlMlaq- CD Nb Pc �Aw�✓sl� CO Skp 1 kaia� n No Po t6 N a )1411,4 UlMlaq- CD Nb Pc �Aw�✓sl� CO N o 00&- ConocoPhillips GMT1 Measurement Appfl�cat'ijon A ��Hear'mg May 3, 2016 ® ConocoPhillips seeks AOGCC approval o Proposed GMT1 measurement system • Custody transfer measurement regulation: 20 AAC 25.228 o We are seeking an order under AS 31.05.030(c); 20 AAC 25.505 • Concurrent application pending before BLM • Presenters • Brandon Viator, Project Integration Manager o Jodie Hosack, Staff Instrumentation Engineer ConocoPhillips Background / Overview Metering Application Highlights Regulations Economic Analysis ® Status & Summary ConocoPhillips First development in Greater Mooses Tooth Unit Key to continued NPR -A growth Utilizes Alpine infrastructure & CD5 design work 11.8 -acre gravel pad Up to 33 horizontal well MWAG development Estimated peak NS employment: —700 positions • Key Permits Received: • CPAI Project Sanction: • 1St Construction Season: • 2nd Construction Season • Start Drilling: • First Oil: Jan/Feb 2015 November 2015 4Q2016 - 2Q2017 4Q2017 - 4Q2018 2Q 2018 December 2018 Conoco Background / Overview: Land Ownership Working Interest Owners ConocoPhillips (Operator) Anadarko Petro -Hunt (CD3 only) Ilips (Operator) Anadarko CRU Surface Owners Kuukpik State of Alaska BLM GMTU / GMT1 Surface Owners Kuukpik BLM Subsurface Owners ASK State of Alaska BLM 11 Subsurface Owners ASRC BLM 5 May 3, 2016 Confidential The proposed measurement design has evolved through multiple discussions with stakeholders, including state and federal agencies The 3-phase production separator and associated metering achieve a high level of hydrocarbon measurement accuracy (2.1% uncertainty in oil stream) within a cost that allows the GMT1 project to remain viable The GMT1 design allows for efficient use of the existing infrastructure to reduce costs and limit gravel footprint, air emissions and other environmental impacts The proposed design is consistent with the 2012 NPR -A Integrated Activity Plan (IAP) EIS, which evaluated GMT1 as a satellite development that relies on Alpine Central Facility (ACF) for processing, and it complies with the IAP stipulation E-5, which requires sharing facilities with existing development in order to minimize project footprint Cono4hillips Greater Mooses Tooth Unit (GMT1) Colville River Unit (CRU) • Oil, Gas and Water are measured at the GMT1 3 -Phase Separator, recombined and sent to Alpine Central Facility (ACF) at CRU for processing © Gas (Lift Gas + Fuel Gas and Miscible Injection Gas) and Injection Water sent to GMT1 from CRU Gas streams measured at GMT1 o Water measured at the wellhead at GMT1 pine ine LEGEND Measurement MI — Miscible Injection gas LG —Lift Gas FG — Fuel Gas k ConocoPhillips OPhase Dynamics Water Line List: Cut meter Orange: Gas ® El ® Coriolis Meter Green: Oil+water Blue: Separated water O Orifice Plate Meter Black: Oil+water+gas Magmeter OGas sample station Production to CD5/ ACF ConocoPhillips Lift Alpine Central Facility (ACF) Gas Common 7 Gas Fuel&Flare I. Processing Dry Gas Gas � Injection Condensate_ Gas oil Stabilizer i Enriched Processing Gas ___________________ ; ? Injection Condensate ................... 1 - — Oil Sales 1 — Water Injection 1 - 1 1 �- 1 Alpine Qanni AI ine 1 Nanu I ;t NK FN FK 1 anuqNK Lookout* Lookout* *Proposed PA 'Reference table showing which PA's are associated with each drillsite is available in back-up material Sea Water �PKS FN > FK 2 ConocoPhillips ® LACT quality metering design requirements o LACT metering is achieved by measuring stable fluids and converting from an observed volume to a standard volume through the application of a Volume Correction Factor (VCF) • A processing facility is required to produce streams with stable fluids • Proposed alternative to LACT o The favored alternative to LACT metering is to measure live fluids and convert observed volumes to standard volumes through the application of a Shrinkage Factor (SF) • No processing facility is required The use of a SF applied to live fluids measurement increases the uncertainty — 2% versus the use of a VCF applied to stable fluids ConocoPhillips Mass Output I Observed Volume Net Observed Volume Net Standard Volume Observed Density Measured by the Flow Meter Water Content Determined by the Phase Dynamics Unit Volumetric Correction — Either VCF or SF ConocoPhillips e Shrinkage Factor (SF) Matrix o Developed across a range of operating pressures & temperatures (example below) Process Adjustment Matrix with Two Way Linear Interpolation - Oil Shrinkage Factor Temperature Pressure 250 350 400 135 350 Pressure > 150 Temperature v 0.87663 0.84492 0.83209 0.88501 0.85297 0.83990 0.89355 1 0.86090 1 0.84759 125 0.92176 135 0.93135 145 0.94081 Process Adjustment 0.853 Factor ConocoPhillips ® The proposed measurement system, along with robust operation and maintenance plans enable CPAI to achieve a high measurement certainty o Oil Measurement - Coriolis Meters o Monthly meter verification checks using Smart Meter Verification o Annual calibration at off-site testing facility o Gas Measurement - Differential Pressure Orifice Gas Meters ® Continuous DP Diagnostics system © Annual orifice plate and meter tube boroscope inspection o Watercut Analyzer and Secondary Instruments ® Quarterly calibrations a Monthly watercut cross verification with proportional sample lab results Coto4hillips o Oil Sampling o Fast -loop flow proportional sampling system configured to be connected to both meter runs, with only the in service meter run open to the sampling system o Monthly sample for water content analyses and occasional samples as needed for compositional and pressure, volume and temperature (PVT) analyses o Gas Sampling ® Flow through spot sampling stations at each regulatory gas meter o Monthly sample for compositional and BTU analyses ConocoPhillips o 20 AAC 25.228 Production Measurement • Produced oil& gas streams measured Equipment for Custody Transfer prior to leaving GMT1. • Gas stream leaving CRU, returning to a) Measured before severance from unit GMTU is measured off -lease at GMTU. • Use of shrinkage factors is necessary for b) Fabricate, install and maintained in conformance with live fluids and complies with API Chapter API MPMS 20.1 as a valid method for allocation �c) Microprocessor -based totalizer must be equipped metering. with (1) and (2) ✓d) If microprocessor used, reports must show... ✓e) Fluid samplers must be a probe or slipstream type. ✓f) Functional bypasses may not be connected g Oil meters must be periodically proved; Gas meters • Have proposed for oil meters to use periodically calibrated advanced monthly verification, supported h Provers used for certification... by annual meter calibration. • In compliance with gas meter calibration 1 24 hours notice needed before (1) calibration of requirements. provers, (2) crude oil sample collection, handling, analysis, (3) oil meter proving, and (4) gas meter calibration j) Upon request, commission will approve variance if CPA[ is requesting approval for e equal or improved accuracy q p y commission discretion in regards to off - off - lease measurement (gas measurement at V/k) "relevant parts of API MPMS" means... GMTU instead of CRU) and custody transfer metering. ConocoPhillips o AOGCC Industry Guidance Bulletin 13-002 © General Information V/. Description of project; design and production rate, temperature and pressure o Fluid Analysis V• Ownership and Physical location Flow Diagram Will be installed during 2018 and started up in 4Q 2018. Exact Meter prove / calibration frequency installation date not defined at this Planned date for installation of meter system t time. (DAPI Manual of Petroleum Measurement Standards (MPMS) (DMeter Run Details to be supplied once available (DFlow Computer (DInstrument / Meter Calibrations e Other than the items noted above, the remaining details required by Guidance Bulletin 13-002 are not available at this time ConocoPhillips Production Facility (PF) analysis showing relative impacts if CPAI were to comply with the AOGCC rules strictly as stated in regulations 150% 100% so% o% - -50% a° -100% z -150% • . ' . -zo0% -I zso% I -300% -' -350% Current Value Facility Capital Operating Cost Four Year Delay Revised Value (No PF) (PF) CPAI would not be able to proceed with further investment in the GMT1 project if LACT metering were required. ECONOMIC PREMISES • 10% Discount Rate • 1/1/2016 Present Value Date (Point Forward) • Alaska Department of Revenue Fall 2015 Price Forecast • 100% Working Interest CAPITAL • Incremental facility capital of —$500 MM EXPENSE • Additional operating costs of —$45 MM /year PRODUCTION • Four year project delay; 2022 first production ConocoPhillips • The GMT1 project is completing detailed engineering and currently engaged in the procurement process that will enable CPAI to order necessary equipment for the project and for metering Requesting both BLM and AOGCC approvals now for CPAI's measurement concept so project team can finalize measurement design and initiate procurement process for the necessary equipment o Design concept and metering philosophy for GMT1 production o Off -lease measurement for CRU gas flowing to GMT1 ConocoPhillips Back -Up cor oc�klllips 2Q Second Quarter • MI Miscible Injection 4Q Fourth Quarter ° MM Million AAC Alaska Administrative Code ° MPMS Manual of Petroleum Measurement Std. ACF Alpine Central Facility ° MWAG Miscible Water Alternating Gas AGA American Gas Association ° NPRA National Petroleum Reserve -Alaska AOGCC Alaska Oil & Gas Conservation Commission ° NS North Slope API American Petroleum Institute ° PA Participating Area ASRC Artic Slope Regional Corporation ° PF Production Facility BLM Bureau of Land Management ° PFD Process Flow Diagram BTU British Thermal Unit ° PVT Pressure, Volume & Temperature CD1 Colville River Delta - 1 SF Shrinkage Factor CPA] ConocoPhillips Alaska, Inc. ° VCF Volume Correction Factor CRU Colville River Unit EIS Environmental Impact Statement FG Fuel Gas GMTU Greater Mooses Tooth UnitParticipating Area GMT1 Greater Mooses Tooth #1 CD 1 Alpine Reference H2O Water CD 2 Alpine, Qannik information for IAP Integrated Activity Plan CD 3 Fiord-Kuparuk (FK), Fiord-Nechelik (FN) Attachment 1G: ACF Simple LACT Lease Automatic Custody Transfer CD4 Nanuq, Nanuq-Kuparuk (NK), Alpine Process Flow LG Lift Gas CD 5 Nanuq-Kuparuk (NK), Alpine Diagram GMT 1 Lookout ConocoPhillips Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number:OTH-16-005 The application of ConocoPhillips Alaska Inc. (CPAI) for a Waiver of the Requirements of 20 AAC 25.228(a) to Provide Custody Transfer Measurement of Hydrocarbons Prior to severance from the Lease or Unit. CPAI, by letter dated February 26, 2016, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue a waiver from the requirements of 20 AAC 25.228(a) to allow for final custody transfer metering of hydrocarbons sold from the Greater Moose's Tooth Unit (GMTU) to occur off unit and to allow for the final custody transfer metering of gas sold from the Colville River Unit to the GMTU to occur after the gas is severed from the CRU. The AOGCC has tentatively scheduled a public hearing on this application for May 3, 2016 at 9:00 a.m. at 333 West 7 1 Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on April 18, 2016 If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1221 after April 22, 2016. In addition, written comments regarding this application may be submitted to the AOGCC at 333 West 7ch Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on May 2, 2016, except that, if a hearing is held, comments must be received no later than the conclusion of the May 3, 2016, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 279-1433, no later than April 28, 2016. Cathy P. Foerster Chair, Commissioner Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: OTH- 16-005 The application of ConocoPhillips Alaska Inc. (CPAI) for a Waiver of the Requirements of 20 AAC 25.228(a) to Provide Custody Transfer Measurement of Hydrocarbons Prior to severance from the Lease or Unit. CPAI, by letter dated February 26, 2016, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue a waiver from the requirements of 20 AAC 25.228(a) to allow for final custody transfer metering of hydrocarbons sold from the Greater Moose's Tooth Unit (GMTU) to occur off unit and to allow for the final custody transfer metering of gas sold from the Colville River Unit to the GMTU to occur after the gas is severed from the CRU. The AOGCC has tentatively scheduled a public hearing on this application for May 3, 2016 at 9:00 a.m. at 333 West 71h Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on April 18, 2016. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1221 after April 22, 2016. In addition, written comments regarding this application may be submitted to the AOGCC at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on May 2, 2016, except that, if a hearing is held, comments must be received no later than the conclusion of the May 3, 2016, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 279-1433, no later than April 28, 2016. //signature on file// Cathy P. Foerster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT NVOiCE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTLS}TENT. ADVERTISrNG ORDER NUMER AO-16-017 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O. AGENCY PHONE: 333 West 7th Avenue 03/31/16 (907) 279-1433 Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: 4/1@016 F A.N NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: v LEGAL DISPLAY CLASSIFIED OTHER (specify below) DESCRIPTION PRICE OTH-16-005 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBAIIT INVOICE StIOWINc AI)VERTISINa: ORDERPO., CER7lF1ED AFFTDAYR DF!:- rDeEmxTmN WTTITATTAGI�neorroF> ADVEI1715A'fENT io•. Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pa71,fJIAII Total of Pages S REF Type Number Amount Dale Comments I PvN ADN84501 2 AO AO-16-017 3 4 FIN AMOUNT Sy Appr Unit PGD1 LGR Object F1' DIST LIQ 1 16 021147717 3046 16 2 3 4 Purc si g o' ame: Title: Purchasing Authority's Signature Telephone Nmnher 1. A. # and receiving agency name must appear on al invoices and documents relating to this purchase, 2. T state is registered For tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for re e DISTRIBUTION-, Divisioh FiseilT/Original AO :Copses. Publisher (faxed); Div 16 Fiscal, Receiving Form: 02-901 Revised: 3/31/2016 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, March 31, 2016 2:05 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf; George Pollock; Gordon Pospisil; Gregg Nady; gspfoff; Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt, Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz•, Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw, Donna Vukich; Eric Lidji; Garrett Haag; Smith, Graham 0 (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster; William Van Dyke Subject: OTH-16-005 ConocoPhillips Alaska, Inc. Attachments: OTH-16-005 Public Hearing Notice.pdf The application of ConocoPhillips Alaska Inc. (CPAI) for a Waiver of the Requirements of 20 AAC 25.228(a) to Provide Custody Transfer Measurement of Hydrocarbons Prior to severance from the Lease or Unit. Jody J• Col(ombie AOGCC Special Assistant Ai(aska OifandGas Conservation Commission 333 West7`ti Avenue Anchorage, Alaska 99501 office: (907) 793-1221 fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, withoul first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombte at 907.793.1221 or iodv.cotombie@alaska.aov. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Misty Alexa Richard Wagner Darwin Waldsmith Manager, WNS Development P.O. Box 60868 P.O. Box 39309 GMTU Representative Fairbanks, AK 99706 Ninilchik, AK 99639 ConocoPhillips Alaska, Inc. 700 G St. Anchorage, AK 99501-3439 Stephen Thatcher Manager, WNS Development CRU Representative ConocoPhillips Alaska, Inc. 700 G St. Anchorage, AK 99501-3439 r.l Angela K. Singh ConocoPhillips February 26, 2016 Commissioner Cathy Foerster Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 RE: Greater Mooses Tooth Unit Misty Alexa Manager, WNS Development ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 Phone 907.265.6822 Request for Approval of Production Measurement Dear Commissioner Foerster: RECEIVED FEB 2 6 2016 i Stephen Thatcher Manager, WNS Operations ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.670.4024 ConocoPhillips Alaska, Inc. (ConocoPhillips), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owner in the GMTU and CRU, Anadarko E&P Onshore LLC, requests approval for a proposed hydrocarbon production measurement and allocation system for the first GMTU development GMT1. As described in detail in Attachment 1 to this letter, GMT1 is designed as a satellite drillsite in the National Petroleum Reserve - Alaska (NPR -A) west of the existing CD -5 drillsite in the Colville River Unit (CRU). GMT1 construction is scheduled to begin in fourth quarter 2016, and first oil is planned to begin in the fourth quarter of 2018. ConocoPhillips has not yet submitted an application for a conservation order for the oil pools to be developed by GMT1. However, AOGCC Industry Guidance Bulletin 13-002 specifies that AOGCC approval of custody transfer measurement is required before installation of the meter system, which as a practical matter means approval is required at the engineering and procurement stage of development. Thus, ConocoPhillips is seeking AOGCC approval in advance of the application for pool rules. At this point, not all of the information listed in Guidance Bulletin 13-002 can be provided, in part because actual equipment must be installed before some of the information can be obtained. Yet, it is important to secure AOGCC approval of the system for which equipment will soon be purchased. ConocoPhillips thus seeks approval now, with the understanding that the AOGCC might later require specific information that is not presently available. ConocoPhillips is also seeking approval now because of the unique nature of the GMTU, which includes in part oil and gas leases conveyed by the federal Bureau of Land Management, and which is administered by the BLM. ConocoPhillips has discussed measurement issues with BLM at length, and most recently submitted an application for BLM approval of a proposed measurement system on January 21, 2016. Attachments 1— 4 to this cover letter, which provide details, technical specifications, and context for the proposed measurement system, are substantially the same attachments that have been provided to the BLM. In some particulars, the attachments are directed at BLM-specific issues, but overall they address issues of interest to both the AOGCC and the BLM. ConocoPhillips is seeking concurrent regulatory approval from both the AOGCC and the BLM for the proposed measurement system. The proposed GMT1 measurement system includes a 3-phase production separator providing continuous measurement of GMT1 oil production using a Coriolis meter and water cut analyzer. It also includes American Gas Association (AGA) compliant orifice meter runs for produced gas. After separation and measurement at the GMT1 drillsite, the produced fluids will be recombined and flow to the CD5 drillsite in the CRU, where production from the two drillsites will be combined and flow to Alpine production facilities. At the Alpine production facilities, commingled production from GMT1 and all of the CRU drillsites will be separated, processed, and delivered to the Alpine Pipeline, through a Lease Automatic Custody Transfer (LACT) meter, for transportation to market. The proposed system for GMT1 differs from the existing well test allocation system in effect at CRU. GMT1 production will be measured continuously within the GMTU prior to being commingled with CRU production, and will in effect have an allocation factor of 1.0 at the CRU LACT meter. The measurement system proposed for GMT1 also includes AGA -compliant orifice meter runs at GMT1 for re-injection gas and miscible injection gas that will flow from the Alpine production facilities back to GMT1. To the extent the system involves measurement of gas produced from CRU, ConocoPhillips seeks approval for off -unit measurement of the gas at GMT1. As AOGCC staff is already aware through informal discussions, the proposed GMT1 measurement system is designed to provide a high degree of accuracy, to gain approval of both AOGCC and the BLM, and to be economically reasonable. The system may not strictly conform to the API standard adopted in 20 AAC 25.228(b), but we believe it lies well within the Commission's authority to adopt reasonable orders to provide for the measuring of oil and gas under AS 31.05.030(c)(6). Documentation in Attachment 1 — 4 supporting this application includes a complete description of the proposed equipment and a detailed uncertainty analysis including the uncertainty associated with shrinkage. If you have questions or need additional information, please contact Brandon Viator, Project Integration Manager—GMTU, at 907-263-4653. Sincerely, Misty a Manager, WNS Development ConocoPhillips Alaska GMTU Representative _t57� IeL Stephen Thatcher Manager, WNS Operations ConocoPhillips Alaska CRU Representative Attachments 1. GMT1 Development and Measurement Approval Request Overview 2. GMT1 Flow Measurement and Metering Philosophy—Three Phase Production Separator 3. October 1, 2014 Whitepaper- GMT1 Commingling, Allocation, and Measurement Summary 4. Production Facility Analysis Attachment 1: GMT1 Development and Measurement Approval Request Overview Oil Measurement by Other Methods / Beneficial Use Off -lease Gas Contents A. Requested Approvals...........................................................................................................................2 B. GMT1 Project Description....................................................................................................................2 C. Maps and Schematics Depicting Units and Facilities..........................................................................4 Figures: • Attachment 1A — GMT1 and CRU Map (Gathering System) • Attachment 18 —GMT1 leases, preliminary PA, and proposed wells • Attachment 1C — GMT1 lease ownership, royalty rate, and allocation factor • Attachment 1D—GMT1 drillsite diagram • Attachment 1E — GMT1 drillsite process flow diagram • Attachment 1F—GMT1 production separator measurement system • Attachment 1G —ACF simple process flow diagram A. Requested Approvals ConocoPhillips requests Bureau of Land Management (BLM) and Alaska Oil and Gas Conservation Commission (AOGCC) approval for the Greater Mooses Tooth #1 (GMT1) measurement system design, described in Attachment 2, GMTI Flow Measurement and Metering Philosophy — Three Phase Production Separator. This document constitutes a submission for approval of the proposed oil measurement concepts for GMTI in accordance with section "E — Oil Measurement by Other Methods" of the BLM onshore order number four; Measurement of Oil (1989) and BLM's December 24, 2014 letter expressing intent to approve a measurement system with a continuous separator for GMT1. This document is also in accordance with Alaska Administrative Code 20 AAC 25.228 covering the application for AOGCC approval of production measurement equipment for custody transfer. The need for this submission stems from the operational scenario for GMT1 and is associated with the measurement of hydrocarbon liquids at elevated temperature and pressure (which are not stable) as per the requirements of the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) chapter 6.1 Metering Assemblies - Lease Automatic Custody Transfer (LACT) Systems (2012) ConocoPhillips also requests BLM approve royalty free beneficial use of fuel gas on the GMT1 drillsite. GMT1 fuel gas will be used in participating area (PA) specific operations (like the drillsite produced fluids heater) as depicted in Attachments 1E, 1F and IG. A production heater will be located at GMT1 to provide heat prior to measurement and transportation of produced fluids via pipeline back to the Alpine Central Facility (ACF) for processing. After processing at the ACF, gas for fuel, injection and artificial lift are sent back to GMTI via pipeline connections at CDS. As shown in Attachment 1E, total gas will be measured at GMT1 before being sent to the ACF for processing. The conditioned GMTI gas will then be sent back to GMT1 for use as fuel, injection and artificial lift. Any excess gas not used at GMT1 can be utilized in the CRU as fuel, injection or artificial lift and appropriately measured. AOGCC approval is also requested for the custody transfer measurement of the gas used at GMTU for fuel, injection, and artificial lift, to be located at GMT1 rather than in the Colville River Unit (CRU). B. GMTI Project Description The GMT1 project will develop the first drill site in the Greater Moose's Tooth Unit (GMTU) which is in the northeast corner of the National Petroleum Reserve — Alaska (NPR -A). The GMTI project is planned to construct a drillsite, access road, pipelines, power lines, bridges, and ancillary facilities for recovery of petroleum resources within the GMTU. The GMTI drillsite will be located 14 miles west of the CRU CD1 drillsite and the ACF. The GMT1 project will develop Arctic Slope Regional Corporation (ASRC) and federal leases from an oil accumulation formed by a stratigraphic trap of Upper Jurassic sandstones (Alpine C sandstone equivalent) similar to what has been developed at CD1. The GMT1 satellite was discovered in 2000 by the Lookout #1 well; was delineated in 2002 by the Lookout #2, Mitre 1, and Mitre 1A wells; and is covered by 1999 and 2015 3D Seismic datasets. The GMT1 project will provide sufficient infrastructure to support development of up to 33 wells. The proposed GMT1 infrastructure will tie back to the CRU at the CD5 drillsite and will be the fifth satellite developed through the ACF following development of the Qannik CD2, Fiord CD3, Nanuq CD4, and Alpine West CD5 satellites (see Attachment 1A). The project will produce 3-phase fluids (oil, gas, and water) which will be carried by pipeline to the CRU ACF at CD1 for processing. Water and gas will be returned to GMTU by pipeline to support enhanced oil recovery of GMTU resources. Sales-quality crude oil produced at the ACF will be transported from CD1 via the existing Alpine Sales Oil Pipeline and Kuparuk Pipeline to the Trans-Alaska Pipeline System (TAPS) for shipment to market. Development and production of hydrocarbons from GMT1 will help offset declines in production from the Alaskan North Slope and maintain throughput of TAPS. Development will also provide benefits to local, state, and national economies through local hire for jobs created during construction and operations, tax revenues, revenue sharing, royalties, and new resources to help meet US domestic energy demand. The GMT1 development is expected to employ up to 700 people during the peak of construction and result in new full time positions upon startup. The Naval Petroleum Reserves Production Act of 1976 (NPRPA) authorizes and directs the Secretary of the Interior to "further explore, develop, and operate" the National Petroleum Reserve-Alaska (NPR-A) (10 USC Section § 7422[c]). The GMT1 Development Project promotes the exploration and development of oil and gas resources in the NPR-A. Specifically, the NPRPA, as amended, encourages oil and gas leasing in the NPR-A while requiring protection of important surface resources and uses. Executive Order 13212 directs federal agencies to give priority to energy- related projects: "For energy-related projects, agencies shall expedite their review of permits or take other actions as necessary to accelerate the completion of such projects, while maintaining safety, public health, and environmental protections." The current GMT1 Development Project seeks to minimize environmental impacts by leveraging existing infrastructure where available and avoid redundancy and waste. One of the key aspects of this approach is the utilization of the existing installed processing capacity at the ACF. The use of this facility greatly reduces the environmental footprint of GMT1 by eliminating the need for a standalone GMT1 processing facility capable of producing sales-quality crude oil. Without approval of an alternative measurement method, a processing facility would have to be built as part of the proposed project to accommodate custody transfer metering prior to sales-quality crude leaving the lease or unit PA. The estimated incremental environmental and cost impacts associated with such a processing facility are discussed beginning on page 6 of Attachment 3, October 1, 2014 Whitepaper — GMT1 Commingling, Allocation, and Measurement Summary. Note that the measurement system submitted for approval here differs in some ways from the system originally proposed and discussed in the October 1, 2014 whitepaper. Attachment 4, Production Facility Analysis, has also been included to demonstrate the project value impact if GMT1 was required to install a processing facility in order to meet metering requirements. A related consideration that should be taken into account when evaluating this proposal is the viability of permitting a development which does not allow oil measurement by other methods. Permitting agencies and stakeholders are keen on reducing any impacts to the environment and subsistence lifestyle of local native residents. The wetlands fill permit for the GMT1 project, designed as a satellite drill site that relies on existing ACF infrastructure for processing, has been approved by the United States Army Corps of Engineers as the Least Environmentally Damaging Practicable Alternative (LEDPA). C. Maps and Schematics Depicting Units and Facilities The map and figures included as Attachments 1B and 1C, show the GMTU leases, proposed development wells and conceptual unit participating area (PA). The map and figures illustrate how GMTI pipelines tie back to the CRU. The GMT1 development drillsite consists of eight process modules and a well row. The process modules consist of a pig launcher/receiver module, production heater, test separator, remote electrical & instrumentation module (REIM), emergency shutdown module (ESD), chemical injection module, fuel gas conditioning skid (fuel gas is supplied to the drillsites from the ACF), and a production separator system which will be used as the GMT1 point of royalty. Attachment 1D, the proposed GMT1 site plan, displays the layout of the drillsite infrastructure. Attachment SE provides a GMT1 drillsite process flow diagram and Attachment IF provides additional detail on the GMT1 production separator measurement system. The ACF simplified process flow diagram is shown in Attachment 1G. The ACF separates and processes well bore fluids from the associated drillsite facilities and delivers sales -quality crude oil. ACF processed produced water is returned to the drillsites for re-injection into the producing formations to maintain reservoir pressure and provide secondary flood support. ACF processed gas is: (i) used to fuel plant and drillsite facility equipment, (ii) provided to the Village of Nuiqsut in accordance with the terms and conditions of the Surface Use Agreement between ConocoPhillips and Kuukpik Corporation, (iii) re -injected in the Alpine reservoir to maintain reservoir pressure for increased recovery, and (iv) used for gas lift. Attachment 1A: GMT1 and CRU Pipelines rison Ba ti National Petroleum Reserve - Alaska `.- ° Greater Mooses Tooth Unit e i GMT1 CD5 • Colville CD3 River Unit CD2 P NUIQSUT • I Legend • Exploration Well �.�.� —Roads and Pads t EMCPAI Unit Boundary —Pipeline ;NPR -A Boundary 0 1 2 3 4 5 N Miles h Attachment 1C: GMT1 lease ownership, royalty rate, and allocation factor List of Leases for Potential Lookout Participating Area Mrnntar Nlr-sne TnM6 11. if Proposed Tract Serial Number Description Number liaaic Royalty Working 9.e Ownership Tract Un K PA No. Tobin Number of Lands or Aeres R a Owner Interest s Percents ABora[bn GMTV Lookout 2 AA -081743 T11N-R2E, UM 16.6667% U.S. ConocoPhithps 78.00 TBD 953086 Section 13: SE7/4NEI/4, SE1/4, NEI/4SW1/4, S12SW1/4 Anadarko 320 W 22.00 Total 320.00 100.00 GMTU Lookout 38 AA -092340 T11N-R3E, UM 16.6667% ASRC ConocoPhilrlps 78.00 T8D 340759 Section 18: SWIMSE114. SW1/4, SW114NW114 223. Anadarko 2200, Total 223.50 100.00 GMTU Lookout 9A AA -081819 T11N-R2E, UM 16.6667% U.S ConocoPhlNps 78.00 TBD 932554 Section 23: NE1/4NEI/4, S1/2NE1/4, SE114, SEI/4SWI/4 319.50 Anadarko 22.00 Total 319.50 10000 GMTU Lookout 9B AA -092346 T11N-R2E, UM 16.6687% ASRC Cone oPhillips 78.00 TBD 340760 Section 24: A8 840.00 Anadarko 22.00 Section 25: A6 640.00 100.00 Section 26;E12,E1/20112, Wi/2SW1/4, SW7/4NW1/4 599.06 Section 35: E1/2, NEI/4SW1/4, El2NW1/4, NWt/4NW1/4 479.25 Section 36: Atl46 0.00 Total 2,998.31 GMTU Lookout 10A AA -081818 T11N-R3E, UM 16.6667% U.S. ConocoPlnl 1ps 78.00 TBD 932553 Section 30: W12, W12E12, El/2NEI/4, NEI/4SE114 565.31 Anadarko 2200 Section 31: W12, W12E1/2 45375 100,00 Total 1,019.06 GMTU Lookout 108 AA -092345 T11N-R3E, UM 16.6667% ASRC Conocolohillips 78.00 TBD 340761 Section 19: WV2. WI/2E12, SE1/4NE1/4, E112SE1/4 562.50 Anadarko 2200. Total 562.50 100.00 GMTU Lookout 16B AA -092342 T10N-R2E, UM 16.6867% ASRC ConocoPHIII)s 78.00 TBD 340763 Section 1: N12, SE114, N12SWI/4 559.13 Arretlarko 22.00 Section 2: EI2NEI/4, NW114NE114 119.81 100.00 Total 678.94 GMTU Lookout 17 AA -081798 TION -ME, UM 16.6687% U.S. ConocoPhHkps 78.00 TBD 932533 Section 6:NW1/4, W12N171M. N12SWI/4, SW1/4SW7/4 341.44 Anadarko 2200. Total 341.44 100.00 TOTAL PA ACREAGE 8,463.250 Key: Anadarko - Anadarko E&P Onshore LLC ASRC - Arctic Slope Regional Corporation ConocoPhillips - ConocolchAfips Alaska, Inc. U.S. - United Slates of Amenca Attachment 1E: GMT1 Drillsite Flow Diagram (Rev 1) Additional Utilities Required: Nitrogen Plant Air Fuel Gas Live List: Purple: Chemical Orange: Gas Green: OiF water Blue: Separated water Black: Ou water+ps ESD Module I I I I I it — — — — _ _ 11 Producnon Realer Ldt Gas Test Mod. Foet Gas _ _ _ _ Tolojector I I ® Wets 1 I 1 I Test Sep. � I I I I I � I I Water Cu[Meter ❑ Corroston Full flow 3 phase I r1 n I separator t I I i I I Pig Launcher GI MI from CDSiACF To CDS/AC! Water Cu[Meter ❑ Corroston Inhid[m L�J_..--_.-_ Coriolis ® Coriolis MeterInhibitor scale Emulsion O OrMce Plate Meter Breaker Anti -foam Full flow 3 phase I r1 n I separator t I I i I I Pig Launcher GI MI from CDSiACF To CDS/AC! Attachment 1F: GMT1 Production Separator Measurement System I wG slopWin6 TryiVIP 0 Watercut Meter bt, IV 013"Att Q. ®CWrNi1 woo 011�wafef Blur SePa�a!etl water No,: Rla& ONwaMr�gas O 0l8ie Pbli MHer ® st.t" Muer it shame, rrotluctim to rnsrna Attachment 1G: ACF simple process flow diagram 1 1 - 1 1 Alpine 1 _._.1.,. NK ,.Lookout* - "Proposed PA Alpine Production Facility Gas Common Fuel & Rai Processing Gas 71 Gas Enrichment Oil stabilizer FnGased Processing Injection Condensate '• — — —► Oil Sales i Water Injection FN S `i FK ,.Lookout*_ Sea Water Lift )ry Gas njection -�,NK-", PA's MICRO MOTION ELITE CORIOLIS MASS AND DENSITY FLOWMETERS io r The Coriolis Flowmeter You've Trusted for Over 35 Years EMERSON_ Ultimate Performance • Industry-leading liquid (± 0.05%) & gas (± 0.25%) mass flow accuracy • Multi -variable capability for simultaneous high accuracy mass, density, volume, and temperature measurement • Widest flow range capability with 100:1 turndown • Most reliable flow measurement performance, particularly in challenging applications such as two-phase flow • Designed for immunity to process, mounting and environmental effects Best Fit -for -Application • The ELITE product family can fit your needs with the widest range of line sizes; ranging from 1/ 1 2 -inch (DN1) to 12 -inch (DN300) • Multiple wetted materials and configurations enable the widest temperature ranges -400'F to 6621(240'C to 350'C) and high pressures up to 6000 psig (414 barg) • Flexible and fast communication protocols that can easily integrate with your process Superior Measurement Confidence • Our Smart Meter Verification process delivers measurement integrity assurance real-time and in process • World-class calibration and testing facilities deliver an accurate measurement straight out of the box • Global application experts and technicians to work with you 247 through your most difficult process challenges • Dedicated design and process engineers deliver unmatched Coriolis expertise Smart Meter Verification Delivers absolute confidence in measurement integrity and performance with our patented methodologyfor meter verification in-line and on demand. Multi -Variable Provides precision measurement for a range of variables including mass flow, volume flow, flow totals, density, concentration and temperature giving you more insight into your process. Two -Phase Flow Ultimate two-phase flow performance delivers reliable measurement for any application, including entrained air, slurry, or emulsion. Fit -for -Purpose With the widest flow range of.01 lb/min (0.35 kglhr) to 120,000lbJmin (3,266,000 kg/hr), the Micro Motion ELITE Coriolis Flowmeters cover the widest breadth of applications for your flow measurement needs. PRODUCRIGHLIGHTS SMART METER VERIFICATION T B` Oil and Gas • Assured liquid or gas measurement accuracywith both industry standards (e.g., API, AGA) and custody transfer approvals (e.g., MID, NTEP, Measurement Canada) • No moving parts means no scheduled maintenance, no mechanical wear, no meter factor drift, and no debris damage or plugging • Proprietary petroleum software, compliant with API 11.1 and API 11.2.4, delivers mass, gross volume, corrected net volume, and API gravity at both process and reference conditions Chemical • Improve plant -wide mass balance with unparalleled mass flow rate accuracy • Simplify greenhouse gas monitoring compliance with Smart Meter Verification • Extend proof test intervals for SIS and simplify compliance for Green House Gas measurement with Smart Meter Verification Food and Beverage • Most accurate in-line density and concentration measurement solution delivers reliable product quality • Eliminate costly downtime and maintenance inherent with alternative flow technologies • Reliable batching solutions eliminate volumetric variation caused by changes in ingredients, temperature, or density Power • Provide accurate and reliable flow & density measurements to facilitate cost effective environmental compliance • Superior accuracy and turndown reduce uncertainty in plant or unit performance testing • SMART, multivariable instrumentation enables greater operational flexibility • Certified fiscal custody transfer meters allow better resource accountability Marine • High accuracy over a wide range of flow rates to meet your fuel transfer needs • Measurement robustness during loading and unloading, even in the presence of entrained gas • Compatible with all marine fuel types: HEO, MGO, MDO and LNG • OIML(MID compliance allows for traceability and confidence in your fuel bunkering measurement Life Sciences • Accuracy in real-world conditions delivers measurement confidence for critical process control • Reliable "empty -full -empty" performance for repeatable batch operations • On-site metrology solutions and Smart Meter Verification provide simplified calibration and validation !.'�•A;l-i7��',.��TN3'r %fAFi�1'�'i&Y �}If�dfi?:'�11J![°%t�e tile}} �� Cq;y'i},y,rk�slxAx-ilr t� jZii;de)jYi(St(YA SItSi.i . I:S i kif lA tl it?. gil-i} rieJatY ;i.<. .dtCli)�t7e�i1.}il j�jtA _Yp1�it��a1��:��f ilji:.�t i'J JY-'.Y��10 (t/'.1't1?};T-f tP7 Pi17%1 t1.3 na ;" Emerson's Flow Lifecycle Services can help you get the most out of your flow meter and process • Workforce training by industry leading experts • Certified Field Service personnel provide in-person startup, configuration, and diagnostic support a 247 technical support team • Local service centers deliver quick response and nearby support ELITE Product Family CMFS Series CMF Delta Shape CMF Series CMF HC Series 1112 inch 1 J inch Cinch 3inch 61nch 9inch DNI DMS DN25 DN80 DN150 DN200 For more information, please visit: www.MicroMotion.comiELITE 02015 Micro Motion, Inc. All rights reserved. The Emerson logo is a trademark and service mark of Emerson Electric Co. Micro Motion, ELITE, PmUnk, MVD and MVD Direct Connect marks are marks of one of the Emerson Process Management family of companies. All other marks are property of their respective owners. Emerson Process Management Americas 7070 Winchester Circle Boulder, Colorado USA 80301 www.Micrc,Motion.com www.Rosemount.com T: +1 800 522 6277 T: +1 (303) 527 5200 F: +1 (303) 530 8459 Mexico T: 52 55 5809 5300 Argentina T: 54 114837 7000 Brazil T: 55 15 3413 8000 Venezuela T: 58 26 1300 8100 Chile T: 56 2 2928 4800 BR -001997 Rev B 0912015 Emerson Process Management EuropelMiddle East Central & Eastern Europe T:-41417696 111 Dubai T:+971 4 8118100 Abu Dhabi T: +9712 697 2000 France T: 0800 917 901 Germany T: 0800182 5347 Italy T: 800877334 The Netherlands T:+31(0)704136666 Belgium T:+32 2 716 77 11 Spain T:+34 913 586 000 U.K. T: 0870 240 1978 Russia/CIS T:+7 495 9819811 12 inch CUED Emerson Process Management Asia Pacific Australia T:(61) 397210200 China T: (86) 212892 9000 India T:(91) 22 6662 0566 Japan T:(81) 3 5769 6803 South Korea T: (82) 2 34384600 Singapore T:(65)67778211 e0 EMERSON. Smart Meter Verification Easily verify meter performance - in line and on demand Micro Motion 00 EMERSON. Micro Motion® Smart Meter Verification - oniy from Emerson' The only tool to deliver absolute confidence in measurement integrity and performance - sensor through electronics - in less than two minutes. Micro Motion Smart Meter Verification Benefits Reduce Costs • Save thousands by eliminating labor, outsourced calibration services, production interruption and potential damage Extend expensive proving and calibration cycles Increase Uptime • No need to remove the meter from the line or stop the process flow to test measurement integrity • Rapid feedback for troubleshooting to isolate meter performance and focus on process dynamics Eliminate Uncertainty • Run Smart Meter Verification on demand or on a pre -determined schedule for ongoing assurance of critical flow point measurement health and stability • Meter health verification results are immediately accessible for early warning of problems • Access stranded diagnostics or verify the performance of difficult -to -reach devices with Emerson's Smart Wireless Improve Quality & Safety • Test meter against factory specifications to ensure peak performance and optimal, on -spec production • Establish audit trail for each meterwith stored results, easily captured and trended forvisual analysis and reporting • Avoid unnecessary trips to the field and testing procedures that break the process seals Micro Motion Smart Meter Verification is ideal for: • Routine verification checks Performance checks for custody transfer field proving • Troubleshooting to isolate problems and eliminate flow measurement suspicions • Safety checks to determine actual tube structural integrity Tracking erosion or corrosion when it is expected as part of the process Quality check to support required procedures Inherent Advantages of Micro Motion Coriolis • No moving parts result in no maintenance or repair • Install anywhere with no now conditioning or straight pipe run required t -----"'g• Accuracy over a wide flow range from a single meter to optimize plant efficiency • Repeatable, direct mass flow measurement to eliminate problems of volume measurement kivuchnology 0 delivers absolute measurement certainty Better Measurement Means Better Process Management Micro Motion Coriolis meters have no moving internal parts resulting in no wear and tear, no maintenance and an expectation that meter calibration will not drift over time. These characteristics, coupled with exceptional accuracy and the delivery of mass, volume, temperature and density measurements from a single device, have supported the widespread adoption of Micro Motion meters in processes around the world for over three decades. As the mechanical stiffness, or rigidity, of Micro Motion Coriolis flow tubes are directly related to its flow calibration factor, Smart Meter Verification is able to identify changes, damage or degradation in the measurement performance of the meter. Other techniques to verify meter health, such as damping trending, are highly affected byfluid properties, changes in temperature, viscosity or density, the presence of entrained air and require user analysis of the data to identify if a meter change is acceptable. Improved verification work practices will improve the overall operation of your process. With its immediate pass fail verification alert, you can count on Smart Meter Verification as the only technology available for complete and instant Coriolis verification of sensor, drive and full electronics. Troubleshoot any process and isolate confirm meter performance with rapid and clear verification feedback Pro -actively monitor the condition of meters with regular verification, trending and forecasting the need for calibration • Assure stability of operation with ongoing measurement verification, including verifying meter after process events or upsets • Accessible directly at the meter, through digital connectivity orvia the Smart Wireless THUM Adapter, provides flexibility of use. Key Specifications Sensor Compatibility: ELITE' Series H -Series F -Series Transmitter Compatibility: 100012000/3000 Series with MVD^ See Product Data Sheet for details Emerson's AMST" Suite: Intelligent Device Manager 9.0: Includes the Meter Verification SNAP-ON application for Micro Motion ELITE' Coriolis meters Schedule checks with immediate results using the local electronics display, remotely using Hart, Modbus, FOUNDATION fieldbus`, DeviceNet, ProLink II, Profibus, or AMS Device Manager, or through digital control networks or Smart Wireless. "Smart Meter Verification runs automatically, is completely non-invasive and provides us with added confidence that our critical measurements are sound. Another huge benefit is on the integrity side with our quality control program. Until meter verification came along there was no non -intrusive or nondestructive method of assuring the pressure rating of the Coriolis tubes still met the manufacturer original specifications. Now we have that ability. We're excited to explore expanding this technology to custody transfer and other critical measurement points." Guy Fulkerth Instrument Specialist Maintenance Team Leader Keyera Energy Emerson's Micro Motion devices are known globally in over 85 countries for quality and reliability. As part of the Emerson PlantWeb® digital plant architecture, Micro Motion enables increased plant availability, decreased costs and enhanced safety. With over 600,000 meters installed around the world, Micro Motion delivers application expertise, service and technical support not available elsewhere. Benefit from the wide range of Micro Motion solutions available • Meter verification ofthe complete Coriolis meter - sensourthrough electronics - with no downtime • Exceptional measurement and operating performance in entrained gas conditions • World -leading dedicated density measurement devices • Solutions for high and extreme temperature applications • Best -in -class compact and drainable Coriolis • Exida Safety -certified Coriolis for SIL -2 and SIL -3 applications xW W W.micromotion.com PlantWeb 02011 Micro Motion, Inc. All rights reserved. The Emerson logo is a trademark and service mark of Emerson Electric Co. Micro Motion, ELITE, Protink. MVD and MVD Direct Connect marks are marks of one of the Emerson Process Management family of companies. Allot her marks are property of their respective owners. Emerson Process Management Micro Motion Americas Worldwide Headquarters 7070 Winchester Circle Boulder, Colorado USA 80301 T: +1 800 522 6277 T: +11303) 527 5200 F:+1 (303) 530 8459 Mexico T: 52 55 5809 5300 Argentina T: 54 114837 7000 Brazil T: 55 15 3238 3527 Venezuela T: 58 26 1792 1858 Emerson Process Management Micro Motion Europe/Middle East Central & Eastern Europe T: +4141 7686 111 Dubai T:+971 4 8118100 France T: 0800 917 901 Germany T: 0800 182 5347 Italy T: 800877334 The Netherlands T:+31 318 495 555 Belgium T:+32 2 716 77 11 Spain T:+34 913 586 000 U.K. T: 0870 240 1978 Russia/CIS T:+7 495 9819811 Emerson Process Management Micro Motion Asia Pacific Australia T: (61) 3 9721 0200 China T: (86) 212892 9000 India T: (91) 22 6662 0566 Japan T:(81) 3 5769 6803 Korea T: (82) 2 3438 4600 Singapore T: (65) 6 777 8211 For a complete list of contact information and websites, please visit: www.emersonprocess-comlhomelcontactslglobal Micro Motion MC -00949 Rev D 1212011 O EMERSON.. Phase Dynamics Technolo y for Precision Measurements Phase Dynamics, Inc. 1251 Columbia Drive Richardson, TX 75081 USA E -Mail sales@phasedynamics.com Tel: 972-680-1550 Fax: 972-680-3262 Family of Water Cut Analyzers fr n- • CSA, FM, ATEX & PED • RTD Temperature Measurement • Configurable Current Loop & Alarm Outputs • True Net Oil and Net Water (With Flow Input) • Modbus RTU, HART This family of Water Cut Analyzers was developed specifically for use in the oil industry. The Low Range Analyzer is typically used for custody transfer or pipelines. The Full Range analyzer is used for well testing on three phase separators and for control of high water cut situations. Flexibility for the user is provided for through various configurations including an insertion unit. Salinity does not affect the measurement because of Phase Dynamics ability to properly • Low Range (04%, 0-10%, 0-20%) • Mid Range (0 to Inversion) • Full Range (0-100%) • High Range (80-100%) • Heuristic Salinitlgm Optional • Insertion Analyzers for Installation In Pipes 6" and Larger • Flow -Through Analyzers in 1" To 4" Pipe Sizes • Three Styles of Flow -Through Configurations • 24 VDC, 120 VAC and 230 VAC • Density Correction Included • Optional Touch Screen Electronics Can Provide Data Logging & Other Capabilities Including Graphics • Enhanced Electronics Can Replace Flow Computers In Fiscal Systems calculate salinity based on the Heuristic SalinityTm (optional). Phase Dynamics' Full and Low Range Analyzers offer the most accurate measurement possible. The Low Range Analyzer has been used on custody transfer pipeline installations by all major oil companies. Phase Dynamics utilizes the unique, patented, "Oscillator Load Pull" microwave technology which provides for this outstanding capability. All functions of the analyzers can be accessed through the front panel by four push button switches. The LCD display or optional color touch screen indicates the measurement value as well as temperature, net oil, net water, and phase of the emulsion (full range only). Full digital Modbus RTU access to the information is standard. Electronics are available in NEMA 4 or explosion proof enclosures. 0 Phase Dynamics, Inc. Analyzer Family 20110505 Page I Phase Dynamics, Inc. Water Cut Analyzer Operational Specifications PARAMETER Low Ran a Mid Range Full Range High Range RANGE 04%&0-100/. 0.200/. 0 -Inversion 0-100% 80-100% UNCERTAINTY* +/-0.04%(0-4%) +/-0.2% +/-0.5% Oil Phase+/ -0.5% +/-0.6% to F +/41% (4-100%) Oil Phase Only Oil Phase Only Water Phase +/- 1 % Water Phase Only REPEATABILITY +/-0.02% +/--0.1% +/-0.10/0 Oil Phase+/ -0.1% Water Phase +/- Water Phase +/-0.5 0.3% RESOLUTION 0.01% 0.1% 0.1% 0.1% 0.1% FLUID TEMPERATURE 32 - 160° F 32 - 160° F 32- 1600 F 32 - 160' F 32 - 160° F HIGH TEMP. VERSION 32-600°F 32-600°F 32-600°F 32-60TF 32-600°F 0. 1% - 25% Water (p 0.1%-25% SALINITY Not Applicable Not Applicable Not Applicable Always Water (p Oil (D Salt Not a Factor All percentages are expressed as absolute water content percentages within a 2 Sigma deviation (95% Confidence). Measurement Section: Pressure Ratings: Flange Sizes up to ANSI 1,500; Raised Face Flanges Standard; RTJ and Flat Face Optional Process/Ambient Temperatures: Fluid Temperature Compensation: Automatic with Built-in RTD Temperature Probe Construction Ambient Temperature Ranges: 316/316L Standard; Other Materials Available; Designed and Measurement Section: -40° to +120° F Fabricated per ASME B31.3 & ASME IX: Full Material Electronics: +320 to +120° F Certifications Optional -40° to +1200 F (With Optional Heater) Certifications: Operational Fluid Temperatures: Class 1, Div. 1, Groups C&D; Standard 320 to 160° F EEx d IIB T5 78°C Optional 320 to 220° F Optional 320 to 400° F Process Connections: to F Low Range Analyzers: 1, 2, 3, 4 inch Flanges TemOptperature n Temperature Compensation Full Range +/-0.3%/deg C Max. mpe Insertion Type Only in 3" Flange All Other Analyzers: 2, 3, 4 inch Flanges Cables: Electronics Enclosures: 3 or 6 Conduit Entry Explosion Proof Enclosures: 17.4 H x 14.0 W x 9.9 D inches; 59 lbs., NEMA 7; Class 1, Div. 1, Groups C & D; EEx d BB T5 89°C See Figure 1 8 Conduit Entry Explosion Proof Enclosures: 17.4 H x 14.0 W x 11.9 D inches; 71 lbs., NEMA 7; Class 1, Div. 1, Groups C & D; EEx d IIB T5 89°C See Figure 1 Rain and Dust Tight Fiberglass Enclosure: 16.3 H x 10.5 W x 7.9 D inches; 17 lbs., NEMA 4 X; See Figure 2 Alarms: Any Electronics Enclosure: Includes Dry Contact Closure Rated I Amp, 120 VAC, Field Definable Setpoint System Error Dry Contact, NO or NC Rated 1 Amp, 120 VA Between Standard Analyzer Measurement Section and Electronics Enclosure: Dedicated 19 Conductor, 22 AWG, 3 Twisted Pairs, 1/2" Diameter, Special Factory installed Military Connector (armored cable not available). 150 feet Maximum Length between Electronics and Measurement Section; typically in Conduit. A 14 gauge ground wire MUST be connected between measurement section and main electronics to assure proper operation and meet FM requirements. Certifications: Explosion Proof Enclosures; CSA, FM, ATEX/PED (Optional) NEMA4X Fiberglass Enclosure; CSA Approved (Optional) Phase yInc. Analyzer Family 201105050 m5 Page 2 Technology for Precision Meusurenteuts 2011 Power & Electronics Specifications Enhanced Electronics: Power Requirements: 18-28 VDC 120-230 VAC 50-60 Hz (Optional) 16 Watts Typical, 27 Watts Maximum Outputs: Analog: 4-20mA, 16 bit D -to -A Conversion Digital: Four (4) RS485 Modbus RTU, HART Inputs: Frequency: Voltage or Magnetic Pickup Pulse (3mV to 15V max.) with Field Selectable Definition Analog: 0-20 or 4-20 mA, 16 bit A -to -D Conversion with Field Selectable Definition Flow -Through -op- Group ►Group Line Testing Pipelines Well Testing Expanded Electronics: Power Requirements: 18-28 VDC 120-230 VAC 50-60 Hz (Optional) 16 Watts Typical, 28 Watts Maximum Outputs: Analog: Five (5) 4-20mA, 16 bit D -to -A Conversion Digital: Four (4) RS -485 Modbus RTU, HART Inputs: Frequency: Three (3) Voltage or Magnetic Pickup Pulse (3mV to 15V max.) with Field Selectable Definition Analog: Five (5) 4-20mA 16 bit A -to -D Conversion Field Selectable Definition �- Insertion Analyzer Group Line Testing Pipelines Well Testing u� Phase Dynamics, Inc. The Water Measurement Experts Analyzer Family 20110505 Page 3 p + Flow -Through Group Line Testing Pipelines Well Testing Figure 1. Explosion Proof Enclosure 11.9 8 ENTRY -9 9 0.8] 134 3 OR 6 ENTRY 0 0 59 174 ®® F? 0 0 0 i �8.0---J CONDUIT ENTRY AREA A C D D; IAB_\ RECOMMENOEO WNMUM `-0.75.71 NPr CLEARANCE FOR ACCESS REDUCING BUSHING Figure 2. Rain and Dust Tight Fiberglass Enclosure ° o NEMA -4X ® is Only CSA ®®®® 463 Approved - 6A--CDNDUIT ENTRY AREA Water Cut Analyzer Measurement Section Dimensions Nominal Pipe Size Configuration 'U", "Z", "L" or Insertion (Note 1) Flange Size (Now 2) A Dimensions Inches B C D Net Weight lbs. I inch & Z 0 39.7 1 13. 4 8 " U&Z 300 39.7 5.4 133 24 31 600 8 16.2 10 60 " " U & Z 900 39.7 6.3 13.3 24 36 Insertion 150 6.1 5.8 25.8 26 Low Cut " U & Z 300 41.8 6.3 14.8 24 56 " U & Z 600 41.8 6.6 14.8 24 60 " U &Z 900 41.8 8.0 14.8 24 72 " L 15027,316z 8,5 167 0 6 " L 3 8,9 16.7 12 10 4 U & Z 600 34.1 9.8 167 12 150 " " L 900 10.3 16.7 12 t0 56 3 inch U & Z 150 8.5 16.1 .2 24 78 L U & Z 300 8.9 I6.1 .2 24 91 L U&Z 600 9 7 16 1 .2 24 91 L U&Z 900 10.25 16.1 .2 24 13 Notes: Nominal Configuration Pipe Size "U,'Z", L" orT a or Insertion ➢P (Note 1 & 4) Flange Size (Note 2) A Dimensions Inches B C D Net Weight lbs. 3 inch L 150 7.25 16.2 10 52 " L 300 76 16.2 10 60 "L 600 8 16.2 10 60 " L 900 8.8 16.2 10 82 Low Cut Insertion 150 6.1 5.8 25.8 26 Low Cut Insertion 300/600 6.1 5.8 25.8 28 Md/FeWH Insertion 150 6.1 10.5 30.5 --- 37 Mid/FaWH Insertion 300/600 6.1 10.5 30.5 -- 39 4 inch 150 332 8,5 167 120 " U&Z 300 33.7 8,9 16.7 12 140 " U & Z 600 34.1 9.8 167 12 150 " U & Z 900 34.4 10.3 16.7 12 178 " L 150 8.5 16.1 10 67 " L 300 8.9 I6.1 ]0 87 ` L 600 9 7 16 1 0 108 " L 900 10.25 16.1 10 136 1. Consult Factory for configurations including High 3. Mid Range, Full Range and High Range are not Temperature versions available in ]"pipe 2. Flanges are dimensioned as ANSI Raised Face. Higher 4. Insertion units have different lengths depending upon pressure rating flanges and RTJ flanges are available - water cut measurement range. The Low Range has consult Factory for dimensions and availability different dimensions from Mid, Full or High Range analyzers. All have 3" flanges. For more Information, Visit Our Web Site at: PHASE DYNAMICS CO Phase Dynamics, Inc. Analyzer Family 20110505 Page 4 WWW. PHASED YNA MICS. COM CAMERON JISKOOT CoJetix Sampling System OIL Np ,ice,. JISKOOT CoJetix Sampling System Cameron's 11SKOOT' CoJetix* system is the highest accuracy liquid hydrocarbon sampling system available. It has the lowest measurement uncertainty (-0.025%)' and delivers the best return on investment for high value transactions. A CoJetix is the system of choice for custody -transfer, allocation and quality measurement where mixing is required? The CoJetix system is a combined fast -loop sampling and JetMix system. The sampling system is integrated as part of the JetMix loop which provides optimal pipeline mixing without inducing a pressure drop in the main process. It is suitable for applications with a wide turndown of flow rates or where a pressure drop could cause a bottleneck in the process. CoJetix mixing nozzle Isolation valve CoJetix pump 'Not to scale Typical Systems Schematic Flow Main process pipeline Sample receiver enclosure Cell sampler Flow B B eoever Receiv A B Flow Sampling loop 'Based on data from over 200 water injection proving tests 'An online assessment of pipeline mixing can be performed at www.c-a-m/iskoot Liquid hydrocarbon sampling 0.025% measurement uncertainty' ISO, EI (IP), API and ASTM compliant Provable to standards by water injection Low inter -batch sample contamination risk Operator friendly and simple to maintain Low installation cost CoJetix quill Isolation valve Applications • Crude oil • Condensate • Low temperature liquid hydrocarbons • Refined products • Hazardous liquids Mixing energy is added to the flow by jets in the nozzle, ensuring the mixing is suitable for sampling at all flow rates. Flow is extracted into a sampling loop through a large take -off quill inserted into the center of the main pipeline. The quill has a large inlet, which further reduces the sampling systems uncertainty. The sampling loop is designed to have no water traps and sufficient fluid velocity to maintain sample representativity and homogeneity through the system. The loop passes through a sample receiver enclosure which can be located in a convenient position for the operator. The enclosure can be fully isolated so that any maintenance work can be carried out with no impact on the main process. The enclosure contains a flow-through cell sampler which discharges icc samples directly into a sample receiver. The short distance travelled by the sample minimizes the risk of cross -contamination between batches. The enclosure, which can be heated to maintain an even temperature to avoid solid or wax formation, also houses the sample receivers. These can be fixed volume (PR -103, PR -53, PR -23) or constant pressure sample receivers (Constant Pressure Cylinder) with manual or automatic changeover. Fixed nozzel and quill take -off Dynamic performance measurement can be achieved by fitting a CanWeigh system for PR receivers or a level -sensor system for Constant Pressure Cylinder receivers. A sampler controller can be installed providing configuration, monitoring and control functions with DCS integration capability. System components are selected for maximum reliability. Crucial items are mounted outside the main pipeline allowing the system to be easily isolated for maintenance without access to the main line. The withdrawable nozzle and quill can be installed by hot -tap into either the top or the bottom of the pipeline. Online analyzers such as water -in -oil monitors and densitometers can be integrated as part of the sampling loop ensuring optimum representativity, accuracy and direct comparison of results. CAMERON •. NORTH AND SOUTH AMERICA 14450 JFK B'vd. Houston, TX 77032 USA Tel 1 281 582 9500 ms-us@c-a-m.com EUROPE, AFRICA, CASPIAN AND RUSSIA 11SKOOT Technology Centre Longfield Road Tunbridge Wells Kent, TN2 3EY United Kingdom Tel 44 1892 518000 ms-jiskootuksales@c-a-i-n.com ASIA PACIFIC Suite 16.02 Menara AmFirst No. 1 Jalan 19/3 46300 Petaling Jaya Selangor Darul Ehsan Malaysia Tel 603 7954 0145 ms-kl@c-a-m.com MIDDLE EAST Level 9, Ai Jazira Club Tower A P.O. Box 47280, Muroor Road Abu Dhabi United Arab Emirates Tel 971 2 596 8400 ms-uk@c-a-m.com Learn more about measurement at: vAvvv.c-a-m.com/nreasun:rnent 0 ALGERIA • CANADA • CHINA • INDIA - MALAYSIA • RUSSIA • UAE • UK - USA y- HSE Policy Statement -F_ C At Cameron, we are committed ethically, financially and personally to a working environment where no one gets hurt and nothing gets harmed. O 2013 Cameron I JISKOOT 8 a Indemark of Camaroa Coletix and letMu ie a m9lIIered JraCemare of Came: on. I SW P 2M 4113 ADD0697NI 1 58002 I, 4 e 4 W.- -. EMERSON. CONSIDER IT SOLVED. 4" Accurate Instruments or Fabricated Pipe? The difference is ...... Daniel Meter Tubes Instruments You Can Trust Daniel Meter Tubes are more than just fabricated pipe with an orifice fitting. They are accurate, dependable instruments because of Daniel's dedicated approach to quality. Extra steps taken during every phase of meter tube design and production separate Daniel Meter Tubes from all the rest. Experience Experienced "code qualified" welders, use internal jigs to insure smooth inlet and outlet surfaces, and expert grinding by quality oriented craftsmen all contribute to the highest quality on each and every meter tube order. Design Experience and expertise in designing a wide variety of applications insures that the proper length of tube, type of flow conditioner and orifice fitting will be exactly what is needed for accurate flow measurement. 1W ya µ �� k� Knowledge Individuals from Daniel sit on the boards of more professional standards organizations than any other manufacturer in the oil and gas transmission industry. What is a Meter Tube? A Meter Tube consist of an Orifice Fitting (Daniel Senior, Junior, Simplex or Orifice Flange Union), a length of pipe upstream of the fitting and a corresponding length of pipe downstream of the fitting. There is also, in most cases, a flow conditioner (Daniel Flow Conditioning Plate or 19 Tube Concentric Bundle) upstream of the orifice as well. When fluid (gas or liquid) flows through the orifice opening, a pressure drop occurs. Flow rate is proportional to the square root of pressure AV,, differential. Flow volume is err determined by integrating flow rate, and is typically corrected A0 to "standard conditions" with an associated flow computer. Daniel 2 Section Meter Tube with Tube Bundle Flow Straightener All Daniel standard two section meter tubes are available with any style Senior or Junior orifice fitting, Simplex plate holder or orifice flange union. Each tube contains an upstream of the minimum length prescribed by API 14.3, with a line mounted 19 tube concentric tube bundle flow straightener per the standard. Each downstream has one each'/" and 3/4" branch connection for thermowell or other uses. Upstream lengths are the minimum recommended by 14.3 table 2-8b for use with plates up to .67 beta ratio for installation in any piping configuration. The downstream is extra long to allow for the installation of additional branch connections in the field, if desired. Beveled ends are standard. Optional ends available on request. Daniel 3 Section Meter Tube with Tube Bundle Flow Straightener The 3 -section assembly contains an inlet spool of the minimum length prescribed by the 14.3 standard. The second section begins with a concentric, flange mounted tube bundle meeting the 2000 API 14.3 requirements and a thick spacer plate to ease tube removal for inspection. The outer end of section 2 contains the orifice flange or fitting. The third or downstream section follows and contains 2 branch connections. Other or additional connections can be supplied in this section on request. The upstream lengths are in compliance with API 14.3 table 2-8b minimum for up to .67 beta ratio and can be used in any piping configuration. Downstream sections are extra long to allow for the addition of extra branch connections in the field, if desired. The standard meter tube has flanged outer ends. Other end connections are available on request. Typical Meter Tube Daniel Flow Conditioner + 1/2" spacer plate Line Model Tube Ml rrr .�.... Bundle Vane 1/2" 3/4' Senior, Junior or Flange Model Tube Bundle Vane Simplex Onrice + V2" spacer plate Fitting Daniel Meter Tube with Daniel Flow Conditioner The three section meter tube with Daniel Flow Conditioner contains an inlet spool of the minimum length determined during testing to the API 14.3 standard. The flange union between the first and second sections contains the Flow Conditioner and a /2" thick spacer plate to facilitate tube removal for inspection. The outer end of section 2 contains the orifice flange or fitting. The third or downstream section follows and contains 2 branch connections. Other or additional connections can be supplied in this section on request. The upstream lengths were established during testing of the device in accordance with the 14.3 test requirements. These meter tubes are for use in any piping configuration with beta ratios to .67. Downstream sections are extra long to allow for the addition of extra branch connections in the field, if desired. The standard meter tube has beveled outer ends. Flanges or other end connections are available on request. The Basics Daniel's Meter Tube Instrumentation: Alignment - Meter tubes using Senior or Junior orifice fittings and Simplex plate holders in 150 and 300# ANSI ratings are supplied with a dowel pin alignment feature at the fitting to meter tube connection. 600# and higher rated tubes use a special, close tolerance large male/female flange alignment method. Either method insures that the bores of both tube sections are matched without offsets. Tubes using orifice flanges utilize a knock -out dowel pin feature to align both pipe sections and center the orifice plate within the flanges. Connections - Each meter tube is supplied with one''/" and one 3/4" branch connection on the downstream for thermowell or other uses. Additional connections are available on request. Testing - Each meter tube is hydrostatically tested after manufacture. Each orifice fitting is tested for tap hole and orifice plate seal integrity after the meter tube has been pressure tested. Material Selection: Daniel uses special cold drawn seamless tubing or honed pipe in the fabrication of meter tubes. The strict requirements for internal roundness and surface finish preclude the use of standard commercial pipe in most cases. Daniel maintains a large inventory of this special pipe to rapidly complete your order. Orifice Fitting Styles vveianeK Inspection: Daniel maintains rigid inspection procedures during manufacturing of meter tubes. Micrometer and internal surface roughness readings are recorded and supplied with each meter tube. Customer or third party inspectors are welcome to verify these readings. Radiography of welds is available on request. Packing/Shipping: Daniel bolts together all meter tubes, when size permits, before shipment. This saves the user time and Feld labor costs. Fittings are protected by heavy lumber, and the tube flanges by special -cut protectors. A SPECIAL NOTE: The use of genuine Daniel parts will assure your Senior, Junior and Simplex Orifice fittings will stay within original specifications and operate properly. Daniel Flow Conditioning Plate The Daniel FLow Conditioning Plate has been tested and shown to be in full compliance with the requirements of API 14.3 April 2000. The Profiler both removes swirl and creates a fully developed flow profile at the orifice. Use of this unit allows r e r r ` ■ �t •+ shortened upstream 'K11Eir��1 1E1r• straight pipe `'+ r ®t r 44 4 All lengths of 17 r� 1� • ` diameters. Beta ratio limit is .67 as with the tube bundle. Available in flange mounted model only. 19 Tube Concentric Bundle Available in either line mounted or flange mounted styles. These units effectively remove swirl that has been introduced by upstream piping components. Individual tubes and bundle diameter are sized to meet the requirements of API 14.3 April 2000. These units allow the use of a 29D upstream meter tube section in any piping configuration with a .67 beta ratio limit. Meter Tube End Modifications Several common and frequently used end modifications are shown here to illustrate Daniel Division Headquarters Houston, Texas, USA, T. (713) 467-6000, F: (713) 827-3880 Calgary, Nberta, Canada, T (403) 279-1879, F: (403) 236-1337 Stirling, Scotland - UK, Mid -East & Afinca,T: +44 01786 433400, F: +44 01786 433401 Singapore - Asia Pacific, T. +65-6777-8211, F: +65-6770-8001 types available. Daniel will custom build -A risers, flanges, 147* ells, reducers and couplings, expertly fabricated to meet your specifications. When ordering special end tube modfications, r please specify full information for both upstream and downstream tube sections. USA Toll Free 1.888 -FLOW -001 vvvvw.daniel.com Daniel is a wholly owned subsidiary of Emerson Electric Co., and a division of Emerson Process Management The Daniel logo is a registered naderni of Daniel Indostnes, Inc The Emerson logo is a registered rademark and service mark d Emerson Elecnc Co An 111111VAC49 Lorin /— 2002 Daniel Measurement and Carona], Inc, a0 rights reserved. Printed in USA. EMERSON DANd867.51N(4)502 ,'�] DP DIAGNDSTIES MONITOR, VERIFY, AND TRUST YOUR DP METER Orifice Plate Flow Meters - with Diagnostic Capabilities The Most Advanced Orifice Meter Svstem on the Market W fW DP Diagnostics Supply Diagnostic Capable Orifice Plate Meters The Most Widely Used Differential Pressure (DP) Meter Simple & Reliable No Moving Parts ISO /API Stated Uncertainty Up to 0.5% Accurate & Repeatable Flow Metering 7 DP Diagnostics Supplies Orifice Meters to All Industries Size: As stated by ISO 5167 (50mm / 2" 5 D 5 1 000m / 40") Flanges: #150-#2500 Material: All standard materials available. Length: A standard orifice meter is approximately 5D long. A diagnostic ready orifice meter is approximately 12D long. DP Transmitter: Any DP transmitters may be used. Calibration Requirements: Meter and diagnostics performance are predictable from ISO / API. No calibration is required for standard installations. Installation Requirements: Orifice meters are installed according to the recommendations made by ISO /API. Performance: Orifice meters give a discharge coefficient performance of ±0.5% (an excepted industry standard). Turndowns of up to 8:1 without transmitter stacking. A Orifice Meter Installed with Diagnostics. rv, L 14 Fr DP DIAGNOSTICS MONITOR, VERIFY, AND TRUST YOUR DP METER DP Diagnostics Supplies a Unique, Powerful, Industrially Proven, Patent Pending Diagnostics System > �J LYT - _ - _ T H X 1 t d Orifice Meter with Optional Extra DP Transmitters for Diagnostic Capabilities P ^ LSP - APpp, AP P - - - - -i PPL _ r 1 p PPL Pd APt APr PP _�z 1 t d x Pressure Field through the Orifice Meter • A Downstream Pressure Tap Allows 3 DP's to be Read. • The Pressure Field Through the Meter is Monitored. • The Diagnostic System Multiplies the Meters Capability. • 3 DP's are Compared to Assure Correct Meter Operation. • A Simple Live Diagnostics Plot is Shown in the Control Room. -' DP DIAGNDSTICS MONITOR, VERIFY, AND TRUST YOUR DP METER Ll The Diagnostics Results are Represented as 3 Points and a Box. If the Points Remain in the Box this Ensures Good Flow Measurement. G; Normalized Flow Comparison . Di�rros(i � ■ Di�rrostr 2 ♦Di�rrostt 3 Orifice Meter Problems that Produce a Warning with Diagnostics Include: 1. Incorrect Inlet or Throat Diameter Keypad Entry. 2. Two -Phase Flow. 3. Excessive Flow Disturbance Upstream of the Meter. 4. Contamination Build -Up Through the Meter. 5. Blocked Impulse Lines. 6. Saturated & Drifting DP Transmitter. 7. A Buckled Plate 8. A Plate Installed Backwards. 9. A Worn or Damage Orifice Leading Edge. 10. Incorrectly Spanned DP Transmitter, etc.. DP Diagnostics can retrofit a diaqnostic system to an existing 3rd party orifice meter if a downstream tap is supplied. Downstream pressure tappings at >6D can be used due to the availability of a correction factor. -�]- DP DIAGNOSTICS I MONITOR, VERIFY, AND TRUST YOUR DP METER Contacts: DP Diagnostics LLC, PO Box 121, Windsor, Colorado, 80550, USA Telephone: 1-970-686-2189, Email: info(a)dpdiagnostics.com Website: www.dpdiagnostics.com Gain More Control of Your Operation Rosemount 3051 Pressure Products THE CHALLENGE Your costs for measurement instrumentation go well beyond the price of the device. While trying to keep your costs down, you still need to work as efficiently and safely as possible. With the capabilities of the Rosemount 3051, you can increase productivity, reduce maintenance, extend your budget, and achieve more. "66% of maintenance time is actually spent simply trying to diagnose the issue" -D own ti m e ce n tra 1. co m "60% of all safety incidents occurred when a maintenance job was performed reactively, versus proactively." -Handbook of Maintenance Management and Engineering "40% of the existing workforce will retire in the next 10 years" -Society of Petroleum Engineers DISCOVER MORE Online product page: www.rosemount.com/3051 Interactive product tour: www.rosemount.com/3051 demotour t •�!nL ii., a.•, r iid3E3i THE SOLUTION Solutions and Experience You Can Trust • The Rosemount 3051 has the industry's broadest offering of pressure, level and now solutions available with SIL 2/3 certification to meetyour demanding application needs for safety, control and monitoring. • Emerson brings unmatched experience and reliability to pressure measurement as the industry leader with 50 years of proven history and over 15,000,000 installed devices. Improve Operational Performance and Efficiency • Tighten your process control with best -in -class performance. • Increase efficiency with engineered solutions that meet application-specific requirements. Increase Worker Productivity and Lower Maintenance Costs • Commission the Rosemount 3051 in less than one minute with the Local operator Interface (1-01), saving time and money at every device. • Reduce downtime by detecting electrical loop integrity issues with Power Advisory Diagnostics. Stay Within Budget • Monitor more with wireless -even in remote and hard -to -reach locations -at a 40-60% savings over wired systems, • Reduce installation costs with ready -to -install pressure, flow, and level solutions. EMERSON_ Emerson has enhanced Rosemount 3051 Pressure Products with new features, performance improvements and capabilities. NEW ENHANCEMENTS (specify HR5) Performance Improvements • 0.04% span reference accuracy • 150:1 rangedown • LCD and L0loperateto-40'C Selectable HART Revision Minimize inventory and protect your investment with selectable HART revision. Because the Rosemount 3051 is field configurable to revision 5 or 7, you can match current and future system capabilities. Scaled Variable The Rosemount 3051's scaled variable feature means you can configure the output in engineering units foryourspecific application, reducing complexity. Process Alerts Process alerts notify you of unexpected pressure or temperature changes, so you can prevent issues before they become serious. The transmitter can be configured to notify you when user -defined limits are exceeded. Low Flow Cutoff With low flow cutoff, you can eliminate erroneous readings by driving the output to zero at no Flow conditions. Scan the code to learn more or go to www.rosemount.com/3051 NEW OPTIONS Power Advisory Diagnostics (specify DAO) Now you can proactively detect degraded electrical loop integrity issues before they affect your process operation. This innovation helps prevent unplanned downtime and is safety certified foryour most critical applications. Local Operator Interface (specify M4) The LOI features straightforward menus and built-in configuration buttons so you can commission the device in less than a minute without complicated training or tools—even in hazardous -area locations - without opening the transmitter housing. Wireless (specify "Transmitter Output" X) See more of your operation with Rosemount 3051 wireless solutions. Quickly add new pressure, level OF flow measurements, even in remote locations, without significant infrastructure costs. Safety Certification (specify QT) The Rosemount 3051 is SI1-2)3 certified (IEC 61508) and includes complete documentation to support your SIS requirements. The certification is also available with the Power Advisory Diagnostic for expanded coverage. External Buttons (specify M4, DZ, or D4) External buttons are isolated from the transmitter electronics allowing you to configure in hazardous areas. You can also specifywhat the buttons do: • Local Operator Interface (specify M4) • Digital Zero- Compensates for mounting position effects (specify DZ) • Analog Zero and Span -Re-range transmitter with applied pressure (specify D4) 02013 Emerson Process Management. All rights reserved. The Emerson logo is a trademark and service mark of Emerson Electric Co. NI other marks are the property of their respective owners The contents of this publication are presented for information purposes only, and while effort has been made to ensure their accuracy, they are not to be construed as warranties or guarantees, express or implied, regarding the products or services described herein or their use or applicability. All sales are governed by our terms and conditions, which are available on request. We reserve the right to modify or improve the designs or specifications of our products at any time without notice. 00807-0100-6169 03113 Product Data Sheet June 2015 00813-0100-4021, Rev NB Rosemount® 3144P Temperature Transmitter ®' 4exlda C E For every responsibility you have, you are confronted with a number of challenges. You have aggressive production and quality targets, but inaccurate or unavailable temperature measurements create unscheduled downtime and off -spec products. Loops may be running in manual because you don't trust your temperature measurement, requiring the attention of your maintenance staff and costing money in lost production. Additionally, improving safety and complying with government and company regulations is made more difficult when you don't have the information ortools needed to prove your compliance. That's why companies are coming to Emerson'm — because they know they need reliable measurements and visibility into their temperature measurements in order to address these challenges and achieve their business objectives. With the Rosemount 3144P Temperature Transmitter, you gain greater visibility into your temperature processes so you can improve safety, comply with regulations, make the most of your limited resources, and reach your production and quality targets. By leveraging the diagnostic capabilities and the unparalleled reliability and accuracy of the Rosemount 3144P, you can minimize off -spec product, reduce maintenance and downtime, improve the usage of your limited resources, and meet regulatory demands. EMERSON. Rosemount 314413 June 2015 Rosemount 3144P Temperature Transmitter Industry-leading temperature transmitter delivers unmatched field reliability and innovative process measurement solutions ■ Superior accuracy and stability ■ Dual and single sensor capability with universal sensorinputs (RTD, TIC, mV, ohms) ■ Comprehensive sensor and process diagnostics offering ■ SIL3 Capable: IEC 61508 certified by an accredited 3rd party agency for use in safety instrumented systems up to SIL 3 [Minimum requirement Of single use (1 ool) for SIL 2 and redundant use (1 oo2) for SIL 31 ■ Dual -compartment housing ■ Large LCD display ■ 4-20 mA /HART® with Selectable Revisions (5 and 7) ■ FoUNDATIONTMfieldbus, compliant tolTK6.0and NEI 07standards Improve efficiency with best -in -class product specifications and capabilities ■ Reduce maintenance and improve performance with industry leading accuracy and stability ■ Improve measurement accuracy by 75% with Transmitter -Sensor Matching ■ Ensure process health with system alerts and easy to use Device Dashboards ■ Easily check device status and values on local LCD display with large percent range graph ■ Achieve high reliability and installation ease with the industry's most rugged dual compartment design Content Optimize measurement reliability with diagnostics designed for any protocol on any host system ■ Thermocouple Degradation Diagnostic monitors the health of a thermocouple loop, enabling preventative maintenance ■ Minimum and Maximum Temperature Tracking tracks and records temperature extremes of the process sensors and the ambient environment ■ Sensor Drift Alert detects sensor drift and alerts the user ■ The Hot BackupT'feature provides temperature measurement redundancy Rosemount 3144P Temperature Transmitter ............. 2 Product Certifications .............................. 16 Transmitter Specifications ............................ 8 Dimensional drawings..............................21 www.rosemount.com June 2015 Rosemount 3144P Explore the benefits of a complete point solution from Rosemount Temperature An "Assemble To Sensor" option enables Emerson to provide a complete point temperature solution, delivering an installation -ready transmitter and sensorassembly Emerson offers a selection of RTDs, thermocouples, and thermowells that x py,.-- -— bring superior durability and Rosemount reliability to temperature sensing _ - - complementingtheRosemountTransmitterportfolio Experience global consistency and local support from numerous worldwide Rosemount Temperature manufacturing sites ■ World-class manufacturing provides globally consistent product from every factory and the capacity to fulfill the needs of any project, large or small ■ Experienced Instrumentation Consultants help select the right product for any temperature application and advise on best installation practices ■ An extensive global network of Emerson service and support personnel can be on-site when and where they are needed ■ Looking for a wireless temperature solution? For wireless applications that require superior performance and unmatched reliability, consider the Rosemount 648 Wireless Temperature Transmitter. ■ A demanding high temperature application requires an innovative temperature solution. Pair the Rosemount 3144P Thermocouple Diagnostic with the Rosemount 1075 High Temperature Thermocouple. www.rosemount.com Product Data Sheet January 2015 00813-0100-2654, Rev HC Volume 1 Temperature Sensors and Accessories (English) ■ RTD and Thermocouple offering in single and dual sensor models ■ Barstock Thermowell offering in wide range of materials and process connections ■ Calibration capabilities for increased measurement accuracy ■ Sanitary RTD for hygienic applications EMERSON Sensors and Accessories (Volume 1 ) January 2015 Rosemount Volume 1 Temperature Sensor and Thermowells Optimize plant efficiency and increase measurement reliability with industry -proven design and specifications ■ Available in a variety of sensing technologies — RTD and Thermocouples ■ All sensor styles and lengths are available in 1/4 -in. diameter ■ State of the art manufacturing procedures provide robust element packaging, increasing reliability ■ Industry-leading calibration capabilities allow for Callendar-van Dusen values to give increased accuracy when paired with Rosemount transmitters ■ Optional Class A accuracy for critical temperature measurement points ■ Sanitary offering provides sensor assemblies approved for hygienic applications Streamline operations and maintenance with sensor and thermowell design ■ Spring loaded threaded adapter, general-purpose welded adapter,capsule, and bayonet styles offer remote or integral transmitter mounting configuration Explore the benefits of a Complete Point Solution TM from Rosemount Temperature Measurement ■ An"Assemble Sensor toSpecific Transmitter" option enables Emerson to provide a complete point temperature solution, delivering an installation -ready transmitter and sensor assembly ■ Emerson has a complete portfolio of Single Point and High Density Temperature Measurement solutions, allowing you to effectively measure and control your processes with the reliability you trust from Rosemount products Contents 68 Rosemount 68 Sensor and Thermowell .................. 4 Rosemount 78 Sensor and Thermowell ................. 17 Rosemount 183 Sensor and Thermowell................ 31 Rosemount 68Q Sanitary Sensor ...................... 44 Rosemount 58C Cut -to -Fit Sensor ..................... 47 Rosemount 91 Series Thermowells .................... 49 How to Decide What to Order ........................ 59 Spring -Loaded Sensor Dimensions .................... 61 Temperature Sensor Assemblies ...................... 66 Series 68 Platinum RTD ............................. 68 Series 78 Platinum RTD ............................. 70 Series 183 Thermocouple ...........................72 Series 68Q Sanitary Platinum RTD ..................... 74 Series 58C Platinum RTD .............................77 Calibration.......................................79 Mounting accessories...............................86 Thermowells...................................... 95 Product Certifications ............................. 102 2 www.rosemount.com January 2015 Sensors and Accessories (Volume 1) Experience global consistency and local support from numerous worldwide Rosemount Temperature manufacturing sites ■ World-class manufacturing provides globally consistent product from every factory and the capacity to fulfill the needs of any project, large or small. ■ Experienced Instrumentation Consultants help select the right product for any temperature application and advise on best installation practices. ■ An extensive global network of Emerson service and support personnel can be on-site when and where they are needed. www.rosemount.com Sensors and Accessories (Volume 1) Series 78 Platinum RTD Series 78 Sensors are intended for applications that require high accuracy, dual -elements, and/or are subjected to high temperatures. Series 78 Platinum Resistance Temperature Sensors measure from -200 to 600 °C (-328 to 1112'F). These sensors are available in capsule, general-purpose, and spring-loaded in sensor (X) lengths from 1 to 68 inches. They are also available bayonet spring-loaded style in sensor (X) lengths from 1 to 45 inches. Table shows the interchangeability of the Series 78 Pt100-385 Sensors. The performance of the standard Series 78 Sensor conforms to the standard set by IEC 751 Class B. Additionally, IEC -751 Class A accuracy is available as an option. For maximum system accuracy, Emerson Process Management can provide sensor calibration. See Sensor characterization (calibration) schedules- Option Code V. Emerson Process Management also offers optional sensor -to -transmitter matching capability obtainable through the use of Callendar-Van Dusen Constants. See Option Code "V" Callendar-van Dusen Constants and Graph of a Typical Two -Point Trim The wire -wound design and construction of the general-purpose Series 78 Sensor allows direct immersion in non -corrosive Fluids at reasonable static pressures. For corrosive environments and in many industrial applications, these sensors are commonly used with standard thermowell assemblies. Platinum element and lead wire configurations Single -element high-temperature sensors have four lead wires and may be used in 2-,3-, and 4 -wire signal conditioning systems. Dual -element sensors have redundant elements to provide separate readout and control signals from a single measurement point. Dual -element sensors have three lead wires For each element and may be used with 2- or 3 -wire systems. Figure S. Lead Wire Configuration Single element Red Red White White Dual White White Red Green Green Black (1) Dual element sensors are only available on Series 68Q and 78 Sensors. 70 January 2015 Figure 9. Construction of a Platinum Wire -Wound RTD A. Lead Wires B. Seal C. High Purity Insulator D. Platinum Resistance Element Specifications Performance specifications Temperature range C Series 78 single- and dual -element sensors may be used in temperatures from -200 to 500'C (-328 to 932 °F). Series 78 single -element high-temperature sensors are provided for high-temperature service overthe range of 0 to 600'C (32 to 1112 °F). Effect of temperature cycling ±0.04%(0.10 °C or 0.1 8 "F) maximum ice -point resistance shift following 10 cycles between -200 and 500'C (-328 to 932 "F). Stability ±0.05% maximum ice -point resistance shift following 1.000 hours at 400'C (752'F). www.rosemount.com January 2015 Table 22. Series 78 Interchangeability(1)(2) Standard series 78 IEC -751 Class B Temperature ±0.80 °C (±1.44 °F) -100 °C (-148 T) ±0.30 °C (±0.54 °F) 0 -C (32 °F) ±0.80 °C (±1.44 °F) — -- - - - 100 °C (212 °F) ±1.80 °C (±3.24'F) — ----- --- 300 -C (572 °F) ±2.30 °C (±4.14 °F) � 400 °C (752 T) Series 78 With IEC -751 Class Aoption Temperature ±0.35'C (±0.63 °F) -100 °C (-148 °F) ±0.15 °C (±0.27 °F) 0 -C (32 "F) ±0.35 "C (±0.63'F) 100 -C (212 °F) 10.75 °C (±1.35 °F) -- ------ 300 °C (572'F) ±0.95'C(±1.71 °F) 400 °C (752 °F) (1) Both tolerances valid from -200 to 500°C. (2) Class B tolerances valid from 0 to 600°C on single -element high temperature sensor. Maximum hysteresis ■ Single- and dual -element, Nominal R0100Ohm Nominal alpha 0.00385 fljo °C: +j- 0.04% of range ■ Single -element, high temperature: ±0.1 %of range. Time constant 4 seconds maximum required to reach 63.2% sensor response in water flowing at 3 ftjs (0.91 m/s), 9.5 seconds for single -element high-temperature sensors. Self heating Sensors and Accessories (Volume 1) Environmental specifications Humidity limits Lead seal is capable of withstanding 100% relative humidity. Vibration limits Standard single- and dual -element sensors ■ ±0.03% maximum ice -point resistance shift due to 30 minutes of 21 g peak vibration from 5 to 350 Hz continuous sweep at 20'C (68'F) for unsupported stem length of less than 5.5 inches (140 mm). Single -element high-temperature sensors ■ Meet ASTM E 1137-95. Cycling time is 3 hours per longitudinal axis, less the time spent at resonant dwells at the axis, from 5 to 500 Hz. The test level is 1.27 mm (0.05 in.) double amplitude displacement or peak g -level of 3, whichever is less. Quality assurance Each sensor is subjected to a resistance accuracy test at 0 °C and an insulation resistance test. Enclosure ratings When installed properly, Rosemount Series 78 Sensors are suitable for indoor and outdoor NEMA4X and CSA Enclosure Type 4X installations. See Hazardous area approvals for complete installation information. Physical specifications Sheath material Single and dual -element, 316 SST Single element high temperature, 316SST and 321 SST 18 mW minimum power dissipation required to cause a 1 °C Lead wires (1.8'F) temperature measurement error in water Flowing at 3 ft/s. 25 mW for single -element high temperature sensors. ■ Single and dual -element, PTFE -insulated, nickel -coated, Insulation resistance 22 -gauge stranded copperwire. 500 x 106 ohms minimum insulation resistance when measured • Single element high temperature, PTFE insulated, silver at 500 Vdc at room temperature 120'C (68 °F)j. plated, 24 -gauge stranded copperwire. Identification data The model and serial numbers and up to six lines of permanent tagging information are etched on each sensor adapter. Stainless steel tags are available upon request. www.rosemount.com 71 Attachment 2 ConocoPhillips Alaska Greater Mooses Tooth 1 Flow Measurement and Metering Philosophy — Three Phase Production Separator Oil and Gas Measurement Revision 1 February 9, 2016 GREATER MOOSES TOOTH 1 DATE: 219/16 ConocoPhillips FLOW MEASUREMENT AND METERING PHILOSOPHY P' — THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT PAGE 2 OF 17 REV. I TABLE OF CONTENTS 1.0 INTRODUCTION ......................................................................................................................3 2.0 VOLUMETRIC CONVERSION.................................................................................................4 2.1 Measurement System Design, Operation and Maintenance.........................................5 3.0 FLOW MEASUREMENT AND METERING SYSTEM DESCRIPTIONS...................................5 3.1 Custody Transfer/Point of Royalty Metering..................................................................6 3.1.1 Production Separator Oil Metering....................................................................6 3.1.2 Production Separator Gas Metering..................................................................7 3.2 Drillsite Gas Metering...................................................................................................7 3.3 Operation and Maintenance..........................................................................................8 3.3.1 Coriolis Oil Meters.............................................................................................8 3.3.2 Differential Pressure Gas Meters......................................................................8 3.3.3 Secondary Measurement Instruments...............................................................8 3.3.4 Sampling...........................................................................................................8 3.3.5 Shrinkage Factor...............................................................................................9 4.0 ALLOCATION METHODOLOGY...........................................................................................10 5.0 GENERAL INFORMATION....................................................................................................10 5.1 Industry Standards......................................................................................................10 5.2 Terms and Definitions.................................................................................................12 5.3 Abbreviations and Acronyms......................................................................................13 5.4 Units of Measurement.................................................................................................14 6.0 MEASUREMENT PROJECT ACTIVITIES AND REQUIREMENTS.......................................14 6.1 General.......................................................................................................................14 6.2 Design.............................................................................:::........................................15 6.3 General Installation Requirements..............................................................................15 6.4 Instrument Traceability...............................................................................................16 6.5 Measurement System Fabrication and Testing...........................................................16 6.6 Commissioning...........................................................................................................16 6.7 Handover....................................................................................................................17 6.8 Maintenance......._................................................_....................................................17 6.9 Test Equipment...........................:..............................................................................17 6.10 Audit...........................................................................................................................17 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc Conoaftillips Alaska 1.0 INTRODUCTION GREATER A100SES TOOTH I FLOW MEASUREMENT AND METERING PHILOSOPHY —THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT REV. I DATE: 219/16 PAGE 3 OF 17 The GMT1 project will develop the first drill site in the Greater Moose's Tooth Unit (GMTU) which is in the northeast corner of the National Petroleum Reserve — Alaska (NPR -A). The GMT1 project will develop resources on Arctic Slope Regional Corporation (ASRC) and federal government leases, and ConocoPhillips seeks approval for the measurement system design from both the Bureau of Land Management (BLM) and Alaska Oil and Gas Conservation Commission (AOGCC). This document is part of a submission package for approval of the proposed oil measurement system for GMT1 in accordance with Section E — ("Oil Measurement by Other Methods") of the BLM Onshore Oil and Gas Order No. 4; Measurement of Oil (1989). This document is also in accordance with BLM's December 24, 2014 letter expressing intent to approve a measurement system for GMT1 that uses a continuous separator, and with Alaska Administrative Code 20 AAC 25.228, which addresses AOGCC approval for production measurement prior to custody transfer. The need for this submission stems from the design of GMT1 as a satellite drillsite that will deliver three-phase production to Alpine Central Facilities (ACF) for separation and processing. Accordingly, the measurement of hydrocarbon liquids will occur at elevated temperature and pressure which are not stable as per the requirements of the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) chapter 6.1 Metering Assemblies - Lease Automatic Custody Transfer (LACT) Systems (2012). The metering system is designed for approval under both State of Alaska and Federal regulatory requirements as per Table 1 below. Table 1 — State of Alaska and Federal Regulations Alaska Administrative Code ( . ,. CC Guidanlobw 20 AAC 25.228 Production Measurement Equipment for Custody Transfer AOGCC Industry Guidance Bulletin 13- 002 Custody Transfer Meter Application Guidance BLM Onshore Orders and Notice to Lessees (NTL) Onshore Order 3 Site Security (Effective Date: March 27, 1989) Onshore Order 4 Measurement of Oil (Effective Date: August 23, 1989) Attach 2 GMT1 Flow Measurement and Metering Philcsophy_Rev1.doc GREATER MOOSES TOOTH I COnoc6miih s FLOW MEASUREMENTAND METERING PHILOSOPHY r' — THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT REV. I DATE: 219116 PAGE 4 OF 17 BLM Onshore Orders and Not' Onshore Order 5 Measurement of Gas (Effective Date: March 27 1989) Alaska State Office Standards for the Use of Electronic Flow Computers Used On Differential Tvpe NTL 2009-1 Flow Meter for Gas Measurement 2.0 VOLUMETRIC CONVERSION The following paragraphs provide an explanation and illustration as to why it is not possible to comply with the BLM onshore order for oil measurement and why we must submit an application to measure oil by other methods to those prescribed in Onshore Order No. 4. The GMT1 project constraints require that we measure live fluids at elevated temperature and pressure. Standard volume is not a wholly measured parameter; it is a parameter derived from a measurement of volume at operational conditions which is then converted by means of empirical or laboratory analysis data to a volume at standard conditions. The conversion of stable fluids from observed volume to standard volume is achieved using Volume Correction Factors (VCF) derived from tables and calculations created by the API and which have an uncertainty budget in the region of +/- 0.1 %. The conversion of live fluids from observed volume to standard volume is achieved through the application of a Shrinkage Factor (SF) which is derived from laboratory pressure, volume and temperature (PVT) testing or equation of state (EOS) modeling based upon detailed compositional analysis. The uncertainty budget for these methods are dependent upon a range of variables which include the representivity of samples, the quality of test equipment and the detail of compositional data obtained. The uncertainty budget associated with Shrinkage Factors is not well documented for either laboratory or EOS modeling; however available industry literature such as the draft API MPMS Chapter 21.4 and experience from field operations elsewhere in ConocoPhillips suggests that +/-2% is a reasonable estimate. Appendix A of this document provides approximately four years of ConocoPhillips United Kingdom J -Block daily mass balance errors as field operations evidence in support of the uncertainty budget estimate. The conversion of volume at operational conditions to volume at standard conditions will incur a penalty of +/-0.1 % when applied to stabilized fluids and a penalty of +/-2% when applied to live fluids. Table 2 below provides an illustration of the comparable measurement uncertainties for stable and live fluids. Attach 2 GMT1 Flow Measurement and Metering Philosophy_ReO.doc 2.1 GREATER MOOSES TOOTH I '11' FLOW MEASUREMENTAND METERING PHILOSOPHY C�n�COI Il����ps— THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT REV. I Table 2 — Comparable Measurement Uncertainties DATE. 219116 PAGES OF 17 Measurement System Design, Operation and Maintenance It is very important to note that the differences in performance in determining Standard Volume between the BLM onshore order or AOGCC requirements and ConocoPhillips proposed metering system design are not related to the base accuracy of the flow meters or hardware components of the metering system. The ConocoPhillips proposed measurement system design, utilizing Coriolis flow meters, will meet the BLM performance requirements for the measurement of Mass and Gross Observed Volume but will not meet the performance standard required for Standard Volume. The measurement uncertainty estimate for GMT1 oil production is provided as Appendix B of this document where a maximum value of +/- 2.1% at 95% confidence level has been determined. The calculations required to determine Net Standard Volume are also contained within the uncertainty calculation provided in Appendix B. The operating and maintenance methods contained in section 3.3 of this document will allow us to monitor and verify the performance of the metering system and its components to demonstrate ongoing compliance with agreements reached based upon this submission in accordance with the onshore order. 3.0 FLOW MEASUREMENT AND METERING SYSTEM DESCRIPTIONS The oil metering system described in this section has been designed to obtain approval under state and federal regulations and incorporates experience from existing installations and previous projects. The GMT1 project is located 14 miles west of the Alpine Central Facility (ACF) in the GMTU within the NPR -A on the North Slope of Alaska. The GMT1 drillsite development scope includes Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc rtaixx C Liv . I, certain Flow Meter Base Flow Meter Base Accuracy plus Accuracy plus Mass 0.15 Pressure and Mass 0.16 Pressure and Temperature Temperature Corrections Corrections Observed Mass Uncertainty Observed Mass Uncertainty Volume 0.25 plus Observed Volume 0.47 plus Observed Density Uncertainty Density Uncertainty Mass Uncertainty, Mass Uncertainty, Observed Density Observed Density Standard 0.35 Uncertainty Plus Standard 21 Uncertainty Plus Volume Conversion to Volume Conversion to Standard Volume Standard Volume Uncertainty (VCF) Uncertainty (SF) Measurement System Design, Operation and Maintenance It is very important to note that the differences in performance in determining Standard Volume between the BLM onshore order or AOGCC requirements and ConocoPhillips proposed metering system design are not related to the base accuracy of the flow meters or hardware components of the metering system. The ConocoPhillips proposed measurement system design, utilizing Coriolis flow meters, will meet the BLM performance requirements for the measurement of Mass and Gross Observed Volume but will not meet the performance standard required for Standard Volume. The measurement uncertainty estimate for GMT1 oil production is provided as Appendix B of this document where a maximum value of +/- 2.1% at 95% confidence level has been determined. The calculations required to determine Net Standard Volume are also contained within the uncertainty calculation provided in Appendix B. The operating and maintenance methods contained in section 3.3 of this document will allow us to monitor and verify the performance of the metering system and its components to demonstrate ongoing compliance with agreements reached based upon this submission in accordance with the onshore order. 3.0 FLOW MEASUREMENT AND METERING SYSTEM DESCRIPTIONS The oil metering system described in this section has been designed to obtain approval under state and federal regulations and incorporates experience from existing installations and previous projects. The GMT1 project is located 14 miles west of the Alpine Central Facility (ACF) in the GMTU within the NPR -A on the North Slope of Alaska. The GMT1 drillsite development scope includes Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc GREATER MOOSES TOOTH I DATE: 219116 ConocoPhillir]$ FLOW MEASUREMENTAND METERING PHILOSOPHY P —THREE PHASE PROD UCTIONSEPARA TOR OIL Alaska MEASUREMENT PAGE 6 OF 17 REV. I all on -pad production facilities and off -pad infrastructure including a gravel access road and drillsite pad. The GMT1 development will connect to the CD5 drillsite via eight miles of pipelines, power lines, and gravel road; providing the first infrastructure into the GMTU and connecting the project to the existing CD5 and CRU infrastructure. The project scope includes 9 initial wells (4 production wells and 5 injection wells). The GMT1 drillsite gravel pad will accommodate up to 33 wells for possible future development. GMT1 will consist of eight process modules and a well row. The process modules consist of a pig launcher/receiver module, full flow three-phase production separator, production heater, test separator, remote electrical & instrumentation module (REIM), emergency shutdown module (ESD), chemical injection module and fuel gas conditioning module. The drillsite full -flow production separator, elevated to prevent gas breakout, will serve as AOGCC's unit boundary custody transfer measurement and BLM's point of royalty measurement (PRM) for produced oil and gas hydrocarbon streams. After measurement, the well fluids will be recombined and travel to ACF in the production crude pipeline. The ACF separates and processes well bore fluids from the production crude pipeline and delivers sales -quality crude oil. ACF -processed produced water is returned to the drill sites for re-injection into the producing formations to maintain reservoir pressure and provide secondary flood support. ACF -processed gas is returned to the drillsite as miscible injection (MI) or lift gas, or used within the plant as fuel gas. MI is re -injected in the reservoir to maintain reservoir pressure and to enhance oil recovery. Lift gas is used for production well lift and converted to fuel gas for drillsite utilities. 3.1 Custody Transfer/Point of Royalty Metering The custody transfer/PRM system shall consist of a horizontal vessel which will operate as a three-phase separator (vapor/water/oil). Vessel internals will consist of an inlet cyclonic separator, weir (three-phase operation), mist extractor on the gas outlet, vortex breaker and sand -jet system. It is anticipated that the water content flowing through the oil leg of the production separator will not exceed 10% by volume at any point throughout field life 3.1.1 Production Separator Oil Metering The oil metering system shall consist of two Micro Motion Elite Coriolis Flow Meters installed in a parallel configuration, sized to cope with the full range of expected flow rates, and includes strainer, inline mixer, water cut analyzer, pressure and temperature instrumentation and control valves. All flow measurement information shall be fed to a dedicated flow computer in order to calculate Net oil volume at standard conditions. An automatic flow proportional sample system shall be installed in order to permit collection of representative oil samples for laboratory analysis. Process and Instrumentation diagrams (P+ID's) of the GMT1 production separator and oil metering system can be seen at Appendix C of this document. This is a dual redundant metering system configuration which will permit maintenance and operational activities to be performed without interruption to production. Flow calculations shall be performed as per the calculation detail provided in Appendix B of this document and in accordance with API chapter 20.1 Allocation Metering. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc GREATER MOOSES TOOTH I ^,�^ �.. FLOWMEASUREMENTAND METERING PHILOSOPHY DATE: 219116 ConocoPhillips _ THREE PHASE PRODUCTIONSEPARA TOR OIL Alaska MEASUREMENT PAGE 7 OF 17 REI. I All measurement equipment and sample system hardware shall be installed per suppliers' recommendations. Sufficient pressure head and careful arrangement of piping are critical factors to avoid flashing of gas and for proper metering systems performance. 3.1.2 Production Separator Gas Metering 3.2 gas metering systems. All measurement equipment shall be installed per suppliers' recommendations Drillsite Gas Metering differential pressure diagnostic system shall be installed on the gas meter runs to monitor the health of the gas metering systems. Attach 2 GMT1 Flow Measurement and Metering Phi1osophy_Rev1.doc GREATER MOOSES TOOTH 1 DATE: 2/9/16 ConocoPhilli s FLOWMEASUREMENTAND METERING PHILOSOPHY F' —THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT PAGE 8 OF 17 REV. I 3.3 Operation and Maintenance 3.3.1 Coriolis Oil Meters Flow meter verification is accomplished by monthly checking of meter health utilizing Smart Meter Verification (SMV) functionality, which permits automated and online verification of the flow meters. The results of the SMV verifications are trended over time and provide traceable evidence of meter performance within defined manufacturer limits. In addition, each flow meter shall be removed from service and calibrated at an accredited facility on an annual basis. This approach to monitoring and calibrating Coriolis flow meters has been implemented elsewhere in ConocoPhillips and has yielded satisfactory results over a number of years. Evidence in support of this practice is provided at Appendix D of this document where we have provided traceable information and certification of historical meter performance. We have also included SMV trending from Coriolis meters installed in test separator service at our existing drill sites in Alaska which demonstrate that the required meter performance can be achieved in this environment and that we have the infrastructure available to perform these checks. Manufacturer's brochures for Micro Motion Elite coriolis flowmeters and SMV are provided in Appendix E. 3.3.2 Differential Pressure Gas Meters Differential pressure gas meter verification is in part accomplished by the continuously running Manufacturer's brochures for Daniel meter tubes and DP Diagnostics are provided in Appendix E. 3.3.3 Secondary Measurement Instruments The measurement instruments which are used in the determination of net standard volume shall be verified on a three monthly (quarterly) frequency. Verification frequency is based upon historical performance of this equipment. Manufacturer's brochures for Rosemount pressure and temperature transducers are provided in Appendix E. 3.3.4 Sampling Monthly flow proportional oil samples shall be obtained and occasional analyses performed as events dictate in order to provide operations teams with data to compare against observed online measurement parameters. Where a comparison of data shows a discrepancy between observed online information and sample information this will trigger investigative work to resolve the disparity. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER MOOSES TOOTH 1 �.� FLMETERING PHILOSOPHY ConocoPhlllips - THREE PHASE PRODUCTION SEPARA TOR OIL Alaska MEASUREMENT REV. 7 DATE: 2/9/16 PAGE 9 OF 17 Monthly flow proportional samples shall be made available to perform monthly water content (BS&W) analyses and occasional analyses as needed for the following parameters and retained for one year: Pressure, volume, temperature (PVT) analysis to determine shrinkage Compositional analysis of evolved gaseous hydrocarbons Compositional analysis of liquid hydrocarbons Where it is found that any online data, which has been used in the determination of net standard volume, needs to be corrected then operations teams will raise and submit a mismeasurement report in order to correct the reported volumes. Manufacturer's brochures for Phase Dynamics water content analyzers and JISKOOT CoJetix sampling systems are provided in Appendix E. 3.3.5 Shrinkage Factor Shrinkage factor (SF) shall be developed across a range of operating pressures and temperatures so that any process variances are captured in order to prevent a systematic bias impacting the measurement of oil. Table 3 below, linear interpolation matrix, provides an indication of the method which will be employed to determine SF from operating temperature and pressure. Table 3 — SF Linear Interpolation Matrix Process Adjustment Matra with Two Way Linear Interpolation Oil Shrinkage Factor Temperature Pressure 135 350 Pressure > 150 250 350 400 Temperature v 125 0.92176 0.87663 0.84492 0.83209 135 0.93135 0.88501 0.85297 0.83990 145 0.94081 0.89355 1 0.86090 1 0.84759 Process Adjustment 0.853 Factor Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc GREATER MOOSES TOOTH 1 SOPHY DATE: 219/16 Conocophilli $ FL—THREE HAS E PRODUCTION TIONSEPARATOMETERING OIL —THREE PHASE PRODUCT/ON SEPARATOR OIL Alaska MEASUREMENT PAGE 10 OF 17 REI. 1 4.0 ALLOCATION METHODOLOGY Each well will be tested in the Test Separator once per month and that data used in conjunction with the 3-phase separator to determine well allocation at GMT1. Net standard volumes will utilize this metering allocation information for royalty payment data. 5.0 GENERAL INFORMATION 5.1 Industry Standards The State and Federal regulations do in some instances mandate compliance with particular industry standards, thus elevating them to a regulatory requirement. The below list of Industry Standards should be considered in discussions pertaining to the GMT1 oil measurement concept. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER HOOSES TOOTH 1 V.. FLOW MEASUREMENT AND METERING PHILOSOPHY ConocoPhilhps —THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT REV. I Table 4 — Industry Standards DATE: 2/9/16 PAGE 11 OF 17 American Petroleum Institute (API) API 505 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified As Class I, Zone 0, Zone1, and Zone 2 API RP551 Process Measurement Instrumentation API RP555 Process Analyzers MPMS 4.X (Chapter 4) Manual of Petroleum Measurement Standards Chapter 4 — Proving Systems MPMS 5.X 5 Manual of Petroleum Measurement Standards Chapter 5 - Measurement of Liquid Hydrocarbons -(Chapter MPMS 6.X 6 Manual of Petroleum Measurement Standards Chapter 6 - Metering Assemblies -(Chapter MPMS 8.X Cha ter 8 Manual of Petroleum Measurement Standards Chapter 8 - Sampling MPMS 9.X Cha ter 9 Manual of Petroleum Measurement Standards Chapter 9 — Density Determination MPMS 14.X 14 Manual of Petroleum Measurement Standards Chapter 14 - Natural Gas Fluids Measurement -(Chapter MPMS 20.1 20.1 Manual of Petroleum Measurement Standards Chapter 20.1 - Allocation Measurement -(Chapter MPMS 21.X 21 Manual of Petroleum Measurement Standards Chapter 21 — Flow Measurement Using Electronic Metering Systems -(Chapter MPMS 22.X (Chapter 22 Manual of Petroleum Measurement Standards Chapter 22 - Testing Protocol Section TR 2570 Continuous On -Line Measurement of Water in Petroleum AMIMMMs A A) Report No. 3 Orifice Plate Metering of Natural Gas and other Related Hydrocarbon Fluids Report No. 5 Natural Gas Energy Measurement Report No. 8 Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases Report No. 10 Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER MOOSES TOOTH I DATE: 219116 ConocoPhillips FLOW MEASUREMENTAND METERING PHILOSOPHY P —THREE PHASE PRODUCTIONSEPARA TOR OIL Alaska MEASUREMENT PAGE 12 OF 17 REV. I 5.2 Terms and Definitions The following terms and definitions apply to this document. Table 5 —Terms and Definitions Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc Construction Company or business that agrees to furnish materials and/or Contractor perform specified construction/fabrication services at a price and/or rate to the Owner Engineering/Design Company or business that agrees to furnish materials and/or Contractor perform specified engineering/design services at a price and/or rate to the Owner Metering System Primary and secondary equipment used together to establish flow characteristics for a given process stream. Owner ConocoPhillips Company or a designated affiliate. Operator ConocoPhillips Company or a designated affiliate assigned with the operation and maintenance of equipment. Philosophy A presentation of the guiding principles based upon qualitative characterization, experience, policy, and company culture. Point of Royalty The meter or measurement facility used to measure the volume and Measurement quality of oil and gas on which royalty is reported as due. At quote stage: any entity invited to supply a quotation for the equipment and/or any Subcontractors thereto At Purchase stage: any entity contracted for the supply of the Supplier equipment and/or any Subcontractors thereto. In all cases, the Supplier is responsible for performance of all Work and will be the single point of contact for all Work-related issues. The Company will not receive information from, nor respond directly to Subsuppliers. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc ConocoPhillips Alaska GREATER MOOSES TOOTH I FLOW MEASUREMENTAND METERING PHILOSOPHY — THREE PHASE PRODUCTION SEPA RA TOR OIL MEASUREMENT REI. I 5.3 Abbreviations and Acronyms The following abbreviations and acronyms apply to this document. Table 6 — Abbreviations and Acronyms DA TF: 1/9/16 PAGE 13 OF 17 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc Descriptio. AACFAlpine Alaska Administrative Code ACF Central Facility AGA American Gas Association AOGCC Alaska Oil and Gas Conservation Commission API American Petroleum Institute BLM Bureau of Land Management BOD Basis of Design BU Business Unit CRU Colville River Unit FAT Factory Acceptance Test GMT1 Greater Mooses Tooth 1 GMTU Greater Mooses Tooth Unit HSE Health, Safety and Environmental IM Instruction Memorandum (BLM) MPFM Multi -Phase Flow Meter MPMS Manual of Petroleum Measurement Standards — American Petroleum Institute (API) NPR -A National Petroleum Reserve—Alaska NTL Notice to Lessees (BLM) PRM Point of Royalty Measurement (BLM) SAT Site Acceptance Test TA Technical Authority WLR Water Liquid Ratio WNS Western North Slope DA TF: 1/9/16 PAGE 13 OF 17 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc GREATER MOOSES TOOTH 1 DATE: 219116 ConocoPhillips FLOT REE PHASE ERODUnMETERING CTION SEPARATOR OILHY Alaska MEASUREMENT 9F [^.%I PAGE 14 OF 17 REV. I Customary U.S. Oilfield units of measure shall be used. These units are listed below: Table 7 — Units of Measure Par' titer bbl (barrel = 42 U.S. gallons) or STB (stock tank barrel) Liquid Volume Liquid Volume Other gal (U.S. gallon) Gas Volume W (cubic feet) or scf (standard cubic feet) Pressure psi (pounds per square inch) or inches of water Temperature °F (degree Fahrenheit) Gas Flow Rate MMscfd (million standard cubic feet per day) Sales Oil Flow Rates STB/d (stock tank barrel per day) Water Flow Rate bpd (barrel per day) Chemical Flow Rate gph (gallon per hour) Viscosity cP (centipoise) Vessel and Tank Levels % (percent) Mass Ib (pound) Rotational Speed rpm (revolutions per minute) Current A (ampere) Voltage V (volt) Power HP (horsepower) or kW (kilowatt) Gas Gravity SG (specific gravity) Oil Gravity °API (API gravity) Standard Conditions 60°F and 14.67 psia (pounds per square inch absolute) MEASUREMENT PROJECT ACTIVITIES AND REQUIREMENTS General This document describes the oil metering system that will be installed for the new GMT1 drillsite development. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revt.doc 6.2 6.3 GREATER HOOSES TOOTH 1 % DATE: 2/996 ConocoPV'hillips FLOW MEASUREMENTAND METERING PHILOSOPHY 1" — THREE PHASE PRODUCTIONSEPARA TOR OIL Alaska MEASUREMENT PAGE 15 OF 17 REV. I Metering station design shall be according to all relevant specifications with respect to vessels, piping, pipe supports, valves, materials, surface protection, insulation, heat tracing, weather protection etc. and the metering stations shall be manufactured such that they are suitable for the climatic conditions at the field location. Design Measurement system design as well as operational and maintenance activities will be based upon state and federal regulatory requirements and agreements as well as the ConocoPhillips standards. This GMT1 Metering Philosophy supports the operating goals, so metering systems must allow for scalable throughput, occasional turndown, minimally disruptive maintenance, and periodic verification as dictated by regulations and commercial agreements. Single point of failure outages that significantly affect throughput or increased measurement uncertainty are to be avoided, and critical devices and equipment must be installed with redundancy. Meter runs shall be installed using practices that reduce or eliminate uncertainty that may occur due to the effects of piping arrangements, and will facilitate maintenance while minimizing requirements for excessive disassembly, associated labor costs and HSE risks. Bypasses around custody transfer/ PRM are generally not allowed. Bypasses built into the design for operational flexibility shall be car sealed closed. For accurate product measurement, it is necessary to provide means of fluid measurement and calculation, as well as determination of fluid quality at appropriate points throughout the process. Pressure and temperature compensation shall be applied to all applicable volumetric measurements. Fluid quality measurement instruments or sampling systems shall be installed for each significant fiscal measurement. Measurement verification dictated by commercial agreements and regulatory requirements may be accomplished in part via application of advanced electronics and systems diagnostics. Communication links to smart instrumentation shall be installed to collect data, maintain and verify devices, support record keeping, report and document failures and malfunctions, and assist with overall reporting and compliance. General Installation Requirements All instruments, including meters and analyzers, shall be located so as to be readily accessible for repair, or adjustment from operating level. Maintenance access shall normally be accomplished by mounting of instruments and manifold valves on stands such that they are accessible from grade. Where measurement accuracy or other physical conditions require close—coupled instruments in a location not accessible from grade, an access platform shall be provided. Instruments shall be installed and mounted rigidly and normal to the vertical or horizontal plane and in such a manner that they may be removed without disturbing adjacent equipment, piping or tubing. All instruments, equipment and components shall be suitable for the maximum extreme environmental and climatic conditions in which they are installed. Protective housings or Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc GREATER MOOSES TOOTH 1 rr� DATE: 219116 ConocoPhiill s FLOWMEASUREME PRODUCT METERING PHILOSOPHY M —THREE PHASE PRODUCTIONSEPARATOR OIL Alaska MEASUREMENT 6.4 6.5 M PAGE 16 OF 17 REV. 1 weather—hoods may be required. Instruments and sense lines containing process fluids shall have insulation, heat tracing, and/or seals where process fluids may undergo a change in phase due to exposure to ambient temperatures. All instruments, tubing, piping, fittings, instrument tags, instrument dials, etc., must be protected from physical damage, contamination by dirt, sand, or other foreign material during transport, storage, fabrication, painting, insulation and other assembly and construction activities. Dials, glasses, nameplates, etc. must be free of paint, insulation, protection residue and other defacing. Instrument Traceability The intent of instrument traceability is to obtain a permanent record and to verify that the instruments will measure, indicate and operate within tolerances guaranteed by the Supplier in accordance with the Instrument Specification and Data Sheets. Meter station transmitters and indicators shall be factory calibrated whenever possible and calibration sheets provided. All instrumentation with factory calibration will be subjected to functional checking. Shop verification check of instruments that cannot be field -checked shall be witnessed. Instruments shall meet the Supplier's published specifications, unless a prior written agreement has been made. All instruments supplied on package systems shall be calibrated and properly tagged. Calibration sheets for these package instrumentation systems shall be turned over prior to system checkout. Measurement System Fabrication and Testing Checks carried out during fabrication at vendor factories or facilities shall ensure that the delivered system will meet design performance targets and that all required documentation is available. The metering system's fabrication shall be ensured to meet the approved design and that all design and fabrication documentation is available. Performance targets shall be verified by calibration/factory acceptance test (FAT), and the tests shall be witnessed by appropriate stakeholders. All performance related documentation such as calibration certificates and verification check reports shall be available for review by stakeholders. Commissioning Commissioning activities ensure that performance targets achieved during fabrication are still achievable after equipment has been transported, installed and electrically connected. The performance targets shall be confirmed by instrument verification checks and site acceptance test (SAT) and appropriately witnessed by stakeholders. All installation/commissioning/verification/SAT documentation shall be available and properly retained. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc ConocoPhillips Alaska 6.7 Handover GREATER MOOSES TOOTH 1 FLOW MEASUREMENTAND METERING PHILOSOPHY —THREE PHASE PRODUCTIONSEPARA TOR OIL MEASUREMENT REV. 1 DATE: 2/9116 PAGE 17 OP' 17 Handover requires close coordination. During this activity, punch list items are resolved and verified. For measurement systems, the Operator shall participate in the handover by reviewing and approving punch list items and ensure any rework is identified for corrective action. 6.8 Maintenance Operator shall ensure that all components of the measurement system are maintained in accordance with regulatory and/or contractual obligations. All instruments, flow computers, samplers, analyzers, and supporting equipment shall have a maintenance frequency for each piece of equipment that is agreeable to partners and regulators as appropriate. Calibration certificates shall be properly retained. 6.9 Test Equipment The calibration of all test equipment shall be checked before being used for any verification activity. If the test equipment is visibly damaged or the calibration certificate is over one year old, the equipment shall be sent to a qualified independent testing laboratory for certification. Test equipment recertification records shall be properly retained. The test instrument calibration check shall be recorded on a label, showing the date and the person or agency performing the check, and the label should be attached to the equipment in such a place that it is easily visible and not easily removed. All calibrations shall be performed using test equipment with accuracies at least one order of magnitude lower than the instrument being calibrated. 6.10 Audit Regular auditing of measurement systems will ensure compliance with regulatory and contractual requirements. The audit shall include checks of the measurement system's performance at current production rates and an assessment of activities required to maintain metering system performance at target levels. After conducting an audit, the audit findings/recommendations shall addressed/implemented within required time scales. The uncertainty calculations shall reflect current production rates and fluid properties. Revised uncertainty calculations shall be analyzed to identify any system modifications that may be required to maintain the target/contractual performance targets. The Operator shall support the auditing of measurement systems by third parties such as regulatory bodies and contractual partners, if required. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revi.doc Attachment 3 Attachment 4 150% 100% 50% 0% -50% KIIIVA -150% -200% -250% -300% -350% Current Value Four Year Delay Facility Capital (No PF) Operating Cost Revised Value (PF) Conoc4hillips
