Schedule A. Measurement Requirements for Oil and Gas Operations

Transcription

1

2 Schedule A Measureent Requireents for Oil and Gas Operations Directive PNG017 August 1, 2017 Version 2.1 Governing Legislation: Act: The Oil and Gas Conservation Act Regulation: The Oil and Gas Conservation Regulations, 2012 Minister s Order: MRO

3 Record of Change Version Date Description 1.0 May 13, 2015 Approved Initial Draft 1.1 June 22, 2015 Updated Paper Battery requireents in section and corrected several references-draft 1.2 Noveber 17, 2015 Updated version to coinside with AER revisions and adoption of MARP in Saskatchewan-draft 2.0 April 1, 2016 Approved Initial Version (authorized by Minister s Order 47-16) 2.1 August 1, 2017 See What s New Section for changes August 1, 2017 Page ii

4 Table of Contents Table of Contents... iii Introduction... xi Purpose... xi Interpretation... xi What s New in This Edition... xi Intent of this Directive... xiv Definitions... xiv Enforceent... xiv 1 Standards of Accuracy Introduction Applicability and Use of Uncertainties Maxiu Uncertainty of Monthly Volue Single Point Measureent Uncertainty Confidence Level Deterination of Uncertainties Exaple Calculation Oil Systes Gas Systes Injection/Disposal Systes Standards of Accuracy Suary Oil Systes excluding heavy oil Gas Systes Injection/Disposal Systes Heavy Oil - excluding Theral In Situ Operations (fro Section 12) Theral In Situ Operations (fro Section 12) Measureent Scheatics Measureent Scheatics Requireents Measureent Scheatic Updates Ipleentation Measureent Scheatic Availability Facility Delineation Requireents Calibration and Proving Frequency Frequency Exeptions Accuracy of Provers and Calibration Instruents Provers and Calibration Procedure Standards Gas Meters Gas Meter Calibration Requireents Gas Meter Calibration Frequency Gas Meter Internal Inspection Gas Meter Calibration and Proving Exeptions Orifice Meters with Chart Recorder Calibrations EFM Meter Calibrations Liquid Meters Liquid Meter Proving Liquid Meter Proving Exeptions Oil Meters August 1, 2017 Page iii

5 2.5.1 Additional Proving Requireents for Live Oil Meters Condensate Meters Proving Condensate Meters at Equilibriu Conditions Proving Condensate Meters at Flowline Conditions Other Liquid Hydrocarbon Meters Water Meters Product Analyzers Autoatic Tank Gauges Inventory Measureent Calibration Delivery Point Measureent Calibration Manual Tank Gauges for Oil Measureent Inventory Measureent Calibration Delivery Point Measureent Calibration Weigh Scales Proration Factors, Allocation Factors, and Metering Difference Proration Factors and Allocation Factors Acceptable Ranges for Proration and Allocation Factors Metering Difference for Fluids other than Oil Acceptable Metering Difference Range Gas Measureent General Requireents Gas Measureent and Accounting Requireents for Various Facility Subtypes Oil Batteries Gas Batteries Gas Gathering Syste (Petrinex facility subtypes: 621 and 622) Gas Plant (Petrinex facility subtypes: 401, 402, 403, 404, 405, 406) Gas Fractionation Plant (Petrinex facility subtype: 407) Injection or Disposal Facility (Petrinex facility subtypes: 501, 503, 504, 505, 506, 507, 510, 511, 512, 514, 516, 517, 518, 519 in SK and 501, 502, 503, 504, 505, 506, 507, 508, and 509 in AB) Meter Station (Petrinex facility subtypes: 631, 632, 633, 634, 640 in SK and 631, 632, 633, 634, 637, 638, 639, and 640 in AB) Other Facilities (Petrinex facility subtypes: 204, 207, 208, 210, 211, 212, 213, 214, 371, 381, 671, 673, 674, 675, 676, 701, 702, 703, 904, 905, 906, 907 in SK and 204, 206, 207, 208, 209, 371, 381, 601, 611, 612, 651, 671, 672, 673, 675, 701, 702, 801, 901, 902, 903 in AB) Base Requireents for Gas Measureent Design and Installation of Gas Measureent Devices Sensing Line Installation for Differential eters Teperature Pressure Volue Calculations Production Data Verification and Audit Trail and Voluetric Data Aendents Chart Operations Exeptions fro Base Requireents Electronic Flow Measureent (EFM) for Gas EFM Perforance Evaluation Test Measureent Reports for EFM Systes August 1, 2017 Page iv

6 4.5.1 Daily Report Monthly Report Meter Report Event Log Alar Log References Site-specific Deviation fro Base Requireents Site-specific Exeptions Site-specific Approval Applications Chart Cycles Extended Beyond the Required Tie Period Exeptions Applications Considerations for Site-specific Approval Gas Proration outside SW Saskatchewan and SE Alberta Shallow Gas Stratigraphic Units or Zones or Area Exeptions Applications Considerations for Site-specific Approval Measureent by Difference Gas Measureent by Difference Oil Measureent by Difference Exeptions Applications Considerations for Site-specific Approval Fuel Gas Measureent by Difference Surface Coingling of Multiple Gas Stratigraphic Units or Zones or Wells Exeptions Applications Considerations for Site-specific Approval Non-Heavy Oil Measureent General Requireents General Measureent, Accounting, and Reporting Requireents for Various Battery Types General Accounting Forula Oil Batteries Gas Batteries Producing Oil Base Requireents for Oil Measureent Syste Design and Installation of Measureent Devices Voluetric Calculations Production Data Verification and Audit Trail Production Data Verification and Audit Trail Field Operations Production Hours Fluid Sapling Requireents for S&W Deterination (and Density) S&W Analysis Proration Well Testing Oil Proration Battery Accounting and Reporting Requireents Proration Estiated Volue Calculation Calculate Proration Factors and Monthly Production August 1, 2017 Page v

7 6.6 Condensate Receipts at an Oil Battery Cobined (Cascade) Testing Electronic Flow Measureent for Oil Systes Reporting Requireents and Scenarios for Wells Producing Oil Oil Wells Gas Well Producing Oil Gas Proration Batteries General Requireents Group Measureent Stabilized Flow and Representative Flow Gas Multiwell Proration SW Saskatchewan and SE Alberta Batteries (Petrinex facility subtype: 363) Group Measureent Size of a Gas Multiwell Proration SW Saskatchewan or SE Alberta Battery Testing Requireents Production Accounting and Reporting Procedures Gas Multiwell Proration Outside SW Saskatchewan and SE Alberta Batteries (Petrinex facility subtype 364) Well Testing Requireents Production Volue Calculations Exeption for Gas Wells Producing Oil Gas Multiwell Effluent Measureent Batteries (Petrinex subtype 362) Well Testing Production Volue Calculations Sapling and Analysis Requireents Exeption for Gas Wells Producing Oil in Effluent Measureent Battery Well Effluent Measureent in the Duvernay and Montney Stratigraphic Units Qualifying Criteria for Well Effluent Measureent in the Duvernay and Montney Stratigraphic Units Measureent Systes requireents for Well Effluent Measureent in the Duvernay and Montney Stratigraphic Units Operational Scenario 1 Hydrocarbon Liquids are Recobined into the Gathering Syste Operational Scenario 2 Hydrocarbon Liquids are Delivered to Sales at the Battery Gas and Liquid Sapling and Analysis General Sapling and Analysis Requireents Sapling Procedures Saple Point and Probes H 2 S Sapling and Analysis Copositional Analysis of Natural Gas Gas Equivalent Factor Deterination fro Condensate Engineering Data Calculated Copositional Analyses Sapling and Analysis Frequency Gas Multiwell Proration SW Saskatchewan and SE Alberta Batteries with Minial Water (Petrinex facility subtypes: 363 in SK and 363 and 366 in AB including CBM) August 1, 2017 Page vi

8 8.4.2 Gas Multiwell Proration Outside SW Saskatchewan and SE Alberta Batteries (Petrinex facility subtypes: 364 in SK and 364 and 367 in AB) Multiwell Effluent Measureent Battery (Petrinex facility subtype: 362) Gas Single Well Battery (Petrinex facility subtype: 351) or Gas Multiwell Group Battery (Petrinex facility subtype: 361) and Shallow Gas Well or CBM Well without Condensate or Oil Gas Single Well Battery (Petrinex facility subtype: 351) or Gas Multiwell Group Battery (Petrinex facility subtype: 361) with Condensate or Oil Underground Gas Storage (Petrinex facility subtype: 505) Gas Cycling Schee (Petrinex facility subtype: 502) Gas Sales/Delivery Gas Plants (Petrinex facility subtypes: 401 to 407) and Gas Gathering Systes (Petrinex facility subtypes: 621 in SK and 621 and 622 in AB) Crude Oil Single Well Battery (Petrinex facility subtypes: 311) and Crude Oil Multiwell Group Battery (Petrinex subtype: 321) Crude Oil Multiwell Proration Battery (Petrinex facility subtype: 322) Miscible/Iiscible Flood Crude Oil Batteries Producing Heavy Oil (Petrinex facility subtypes: 313, 325, 326, and 327 in SK and 311, 321, 322, 343, and 344 in AB) Oil Sapling and Analysis Requireents Oil Analysis Requireents for New Wells Cross-Border Measureent General Requireents Cross-Border Sapling Requireents Cross-Border Measureent Points Trucked Liquid Measureent General Requireents Reporting Requireents Teperature Correction Requireents Pressure Correction Requireents General Trucked Liquid Measureent, Accounting, and Reporting Requireents for Various Facility Types Oil Batteries that Produce Non-Heavy Oil Custo Treating Facilities Pipeline Terinals or Railcar Terinals Clean Oil Terinals Gas Plants, Gas Batteries, and Gas Gathering Systes Water Injection/Disposal Facilities Waste Processing Facilities Facilities that Produce Heavy Oil Design and Installation of Measureent Systes Meters Weigh Scales Exeptions for Truck Measureent Systes Load Fluids Split Loads Sapling and Analysis Autoatic Sapling Manual Spot (Grab) Sapling August 1, 2017 Page vii

9 S&W Deterination Density Deterination Volue Deterination Tank Gauging Weigh Scales Meters Acid Gas and Sulphur Measureent General Requireents Acid Gas Measureent Deterining Acid Gas on a Dry Basis Sulphur Measureent and Pit Volue Deterination Sulphur Pit Volue/Tonnage Deterination Sulphur Measureent Sulphur Balance Calculation for Sour Gas Processing Plants Overview of Plant Inlet and Outlet Points for H 2 S Deterining H 2 S in Sour Gas Deterining the Concentration of H 2 S in Condensate Deterining Concentration of H 2 S in Inlet Separator Water Calculation Procedure for Estiating the Plant Sulphur Inlet Mass per Day Calculation Procedure for Estiating Plant Sulphur Outlet Mass per Day Production Data Verification and Audit Trail How to Coplete the S-30 Monthly Gas Processing Plant Sulphur Balance Report Heavy Oil Measureent General Measureent Requireents Teperature Correction Requireents Pressure Correction Requireents EFM Requireents Diluent/Condensate Receipts and Blending Shrinkage Hydrocarbon Blending and Flashing Shrinkage Water Measureent Well Proration Testing Heavy Oil Receipt, Delivery, or Sales Priary and Secondary Production Battery Subtypes Gas Measureent and Reporting Oil and Water Deliveries to a Treatent Facility Well Test Measureent with Tank Gauging or Metering Theral In Situ Operations (Petrinex facility subtypes: 344 in SK and 344 and 345 in AB) Bituen, Diluent, Dilbit or Heavy Crude Oil Delivery Point Measureent Gas Measureent Stea Measureent Water Measureent Water/Stea Priary and Secondary Measureent Solvent Measureent Production Measureent Well Production Measureent Proration Factors August 1, 2017 Page viii

10 Uncertainty and Proration Factor Suary Internal Inspection Exeptions Condensate and High Vapour Pressure Liquid Measureent and Reporting General Measureent and Reporting Requireents Measureent Requireents Reporting Requireents Reporting Scenarios for Gas Wells Producing Condensate Scenario 1 Condensate that is Effluent Metered, Tested or Proration Tested or Separated and Recobined Scenario 2 Liquid Production and Separated fro the Well Scenario 3 Liquid Production Separated fro a Multiwell Battery Scenario 4 Liquid Recovered fro Gas Copression Liquid Measureent General Requireents Scope Application of API Measureent Standards Syste Design and Installation Volue Measureent Meter Selection Shrinkage Live Oil Shrinkage Hydrocarbon Blending and Flashing Shrinkages Shrinkage Factor Deterination Shrinkage Factor Application Teperature Measureent Pressure Measureent Density Deterination Tank Measureent Tank Strapping Tank Sizing Manual Tank Gauging Autoatic/Electronic Tank Gauging Tank Gauging Applications Sapling and Analysis for S&W and Density Deterination Fluid Sapling Requireents for S&W and Density Deterination S&W Deterination Liquid Volue Calculations General Equations for Deterining Liquid Volues at Base Conditions Electronic Flow Measureent for Liquid Systes Perforance Evaluation Test Cases for Verification of Oil Flow Calculation Progras Test Cases for Verification of NGL and LPG Flow Calculation Progras Measureent Records The Daily Report The Monthly Report The Event Log EFM Specific Reports Water Measureent Base Requireents for Water Measureent, Volue Calculation, Production Data August 1, 2017 Page ix

11 Verification, and Audit Trail Water Measureent and Accounting Requireents for Various Facility Types Gas Facilities Crude Oil Facilities Water Source Production Water Injection and Disposal Facility Waste Processing and Disposal Facility Storage and Disposal Cavern Theral In Situ Schee (Petrinex facility subtype: 506) Downhole Water Disposal or Injection Brine Reporting (Petrinex facility subtype: 903) Load Water Reporting Water Gas Ratio (WGR) Testing Methodology WGR Testing WGR Calculation Appendix 1 Docuents Replaced Fully or Partially by Directive PNG017: Measureent Requireents for Oil and Gas Operations Appendix 2 Glossary Appendix 3 Water-Cut (S&W) Procedures Appendix 4 On-site Analytical Techniques for H 2 S Measureent Appendix 5 Gas Equivalent Volue Deterination Appendix 6 Calculated Copositional Analysis Exaples Appendix 7 Blending Shrinkage Calculation Exaple Appendix 8 Measureent Scheatic Exaple Appendix 9 Gas Group Delineation August 1, 2017 Page x

12 Introduction Purpose Interpretation Directive PNG017 - Measureent Requireents for Oil and Gas Operations consolidates, clarifies, and updates the Regulatory requireents with respect to easureent points used for accounting and reporting purposes, as well as those easureent points required for upstrea petroleu facilities and soe downstrea pipeline operations under existing regulations. The ter easureent as used in this docuent eans easureent, accounting, and reporting. While easureent is the deterination of a volue, accounting and reporting are integral coponents of easureent in that after a fluid volue is easured, atheatical procedures (accounting) ay have to be eployed to arrive at the desired volue to be reported. Directive PNG017 includes easureent and reporting requireents that are applicable to oil and gas operations located in Saskatchewan only, but highlight known differences with the Directive PNG017 equivalents in Alberta and British Colubia, with the intention that it will ultiately for the basis of a coprehensive and haronized regulatory docuent for all three jurisdictions. As a result, the ter Regulator is referenced throughout the docuent which refers to the Saskatchewan Ministry of the Econoy (ECON) in Saskatchewan, Alberta Energy Regulator (AER) in Alberta and the British Colubia Oil and Gas Coission (BCOGC). The ajority of the easureent and reporting requireents in Directive PNG017 are identical in all three jurisdictions. In situations where requireents differ between the three jurisdictions, the requireent that is applicable in each jurisdiction is listed separately in a box, as shown below. Wells and facilities operated in Saskatchewan ust coply with the requireent specified in the SK box. The Alberta and British Colubia inforation is provided for inforational purposes only and subject to change without notice. Province SK AB BC Measureent and Reporting Requireent Requireent applicable to oil and gas operations in Saskatchewan Requireent applicable to oil and gas operations in Alberta Requireent applicable to oil and gas operations in British Colubia Note that if there is no coent for any particular province that it does not ean that there are no applicable regulations. What s New in This Edition Guideline PNG042: Measureent, Accounting, and Reporting Plan (MARP) Requireents for Theral Heavy Oil Recovery Projects has been created and will be effective April 1, MARP application ust be subitted with Enhanced Oil Recovery application as an attachent through the ECON s Integrated Resource Inforation Syste (IRIS) generic application process. (See for how to apply) Interpretation: Added BC requireents throughout directive. Directive: changed the ters priary easureent eleent to priary eleent, ean to average, solution gas to gas in solution, standard conditions to base conditions, August 1, 2017 Page xi

13 well site to well or battery, wet gas to effluent, initial qualifying criteria to qualifying criteria and condensate shrinkage to blending shrinkage. Section : Changed the requireents for when live oil eters ay be reoved fro service and proved in a eter shop. Section 4.2.1: Added clarification regarding gas reporting for oil facilities by adding point #4, 5, and 6 which had already been stated in Section Section : Changed the word easured to etered. Section : Changed the word easured to etered. Section 4.2.2: In point #6 added a ust stateent. Gas production fro oil wells or batteries or fro other gas wells or batteries ust not be connected to a gas proration battery upstrea of the gas proration battery group easureent point. Section 4.2.2: In point #8 added that any fuel gas volues greater than /d crossing a reporting facility boundary ust be etered. Section : Reoved points #2 and #3 and referenced Section 7.4. Section 4.2.4: Added section for gas plants. Section 4.2.6: Added section for injection or disposal facilities. Section 4.2.7: Added section for eter stations. Section 4.2.8: Added section for other facilities. Section 4.3.1: Added subsections for all the different types of gas eters and their design and installation requireents. Section 4.3.2: Changed fro Section and a new heading of 'Sensing line installation for differential eters'. Section : Moved fro section Section 4.3.3: Added section for teperature easureents. Section 4.3.4: Added section for pressure easureents. Section 4.3.5: Changed the requireent in point #7 Section : Changed the requireent for EFMs to only ensure the constants are up to date on new easureent equipent. Section : Changed requireent in point #8 so that operators when fuel usage, flaring or vent occurs within a gas gathering syste but there is no applicable licensed facility within the gas gathering syste it ust be reported as an activity associated with the gas gathering syste itself. Section 4.3.4: Moved to Design and Installation Section Section 4.3.7: Added new paragraph to beginning of section that was located in Section 4.3.1; Section 4.3.7: Changed the word 'field personnel' to 'the Operator'. Section : Reworded beginning sentence to clarify requireents. Section : Changed the word easured to etered. August 1, 2017 Page xii

14 Section 4.5: Changed heading no requireent changes. Section : Added definition for 'idpoint of perforations' Section 8: Added requireents to subit analysis as per Minister's specifications listed in Directive PNG013. Section 8.2.3: Added definition for Sulphur Cheiluine Scene Detectors. Section 8.4: Added analysis requireents for lift gas using return gas fro a gas plant. Section 8.5: Added new section for oil sapling and analysis requireents. Section 9.1: Changed the word easured to etered. Section : Railcar terinals now apply to this section Section : Changed the word easured to etered. Section : Clarified that produced water entering a stea injection or leaving a stea injection facility priary easureent ust be verified with secondary easureent Section 13: Added definition for high vapour pressure liquids Section : Added clarification on copliance for easureent requireents. Section 14.3: Added acid gas reoval to the shrinkage section Appendix 7: Fixed shrinkage calculation Appendix 2: Glossary - aended definitions for ters - allocation factor, acid gas, atospheric pressure, butanes, calibration, cold water equivalent, condensate proration factor, custody transfer point, dead oil, dead oil eters, delivery point, delivery point easureent, dew point, effluent, effluent easureent, ethane, gas in solution, gas plant, high vapour pressure liquids, legal survey location, live oil, live oil eters, easured gas sources, eter eleent, Petrinex, positive displaceent eter, priary eleent, prorated production, proration, proration battery, proration factor, prover, prove, qualifying criteria, reote terinal unit, relative density, sales gas, satellite, SCADA, secondary eleent, secondary easureent, shrinkage factor, single point easureent uncertainty, split load, stabilized flow, stock tank vapours - added ters and definitions - analog transitter, approved, base conditions, calibration standard, copressibility (apparent), copressibility (liquid), copressibility factor, copressibi lity, continuous easureent, digital (sart) transitter, estiate, flare gas, flow coputer, flow eter, gas chroatograph, in situ operations, ediu oil, eter (noun), eter (verb), ultiphase fluid, uncertainty, theral (recovery/production), verification, water cut - reoved ters and definitions - reoved 'allowable' ter fro directive, reoved all references to standard conditions, stock tank conditions or reference conditions and replaced with base conditions, block, confidence level, innage gauge, liberated gas, ean, easuring standard, near easured production, outage gauge, perforation, prover run, relative density of gas, solid, solution gas, sulphur cheiluinescene detectors, supervisory control and data acquisition syste, tank, truck terinal, utility use, well event August 1, 2017 Page xiii

15 Intent of this Directive This Directive specifies: what and how volues ust be easured; what, where, and how volues ay be estiated; if accounting procedures ust be perfored on the deterined volues and what they are; what data ust be kept for audit purposes; and what resultant volues ust be reported to the Regulator. The licensee ust coply with all requireents set out in this Directive. In this Directive, the ter ust indicates a requireent that ust be followed. In soe situations, a requireent ay be subject to exeptions if specific conditions are et. The ter should indicates a recoendation that will not be subject to enforceent. However, the Regulator ay direct the licensee in writing to ipleent changes to iprove easureent accuracy, and this direction will becoe a condition of operation for that facility or facilities. The Directive does not include instructions on how the volues ust be reported to the Regulator which are included in other Regulator docuents, such as Saskatchewan s Directive R01 - Voluetric, Valuation and Infrastructure Reporting - Petrinex, but it does include soe inforation on requireents regarding facility subtype, status, and code in accordance with those docuents. If requireents in previously issued Regulator docuents (interi directives, inforational letters, guides, etc.) conflict with the requireents in this Directive, the requireents in this Directive replace the prior requireents. Over tie, it is intended that all relevant superseded requireents will be rescinded. Definitions Enforceent Many ters used in this Directive are defined in the Glossary (Appendix 2). However, any critically iportant definitions are also included within applicable sections. SK This Directive replaces and supersedes a nuber of Saskatchewan Regulatory docuents, as identified in Appendix 1. This Directive currently has Regulatory authority in Saskatchewan effective April 1, Regulatory enforceent of the new requireents, including audits and inspections, that are intended to ensure copliance with the new oil and gas easureent requireents and will be applied in accordance with the ipleentation schedule outlined below. Enforceent actions will be applied according to Section 13.6 of Directive PNG076: Enhanced Production Audit Progra. As a result of the ipleentation of Directive PNG017, ECON will be rescinding all Measureent Exeptions approved in Saskatchewan before April 1, Industry ust ake continuous progress with respect to copliance for easureent and reporting by April 1, 2020, and ECON ay require operators to deonstrate their progress throughout the ipleentation schedule. Operators August 1, 2017 Page xiv

16 ust eet the following ipleentation schedule: a. Requireents ust be 25 per cent ipleented by April 1, b. Requireents ust be 50 per cent ipleented by April 1, c. Requireents ust be 75 per cent ipleented by April 1, d. Requireents ust be 100 per cent ipleented by April 1, All operators are expected to be fully copliant with the Saskatchewan Regulatory requireents prior to the ipleentation of Directive PNG017. Any facilities licensed after April 1, 2016 ust be designed and operated in full copliance with Directive PNG017. For facilities licensed prior to April 1, 2016, operators are expected to coply with the 4-year ipleentation schedule. AB BC The operator ay apply for a site specific easureent exeption through the IRIS generic application process if all the necessary docuentation associated with an application is subitted and there is significant evidence to support the exeption (refer to Section 5 of Directive PNG017). The AER enforceent process is specified in Directive 019: Copliance Assurance. Noncopliance events are listed in the Risk Assessed Noncopliance section of Directive 019 under the Technical Operations Group, Production Operations Section, for Directive 017 and Directive 007 requireents. The BCOGC enforceent process is specified in the Copliance & Enforceent Manual August 1, 2017 Page xv

17 1 Standards of Accuracy 1.1 Introduction With regard to accuracy, it is assued an exact or true value exists for any variable that is valid for the conditions existing at the oent the result is deterined. Deterining the true value without doubt cannot be done, due to the liitations of easuring equipent and procedures and the possibility of huan error. Typically, the closer one wants to approach the true value, the ore expense and effort has to be expended. Measureent in an oil and gas industry context, the principal easureent technologies and procedures are: a. b. c. d. e. f. Meters for deterining flow volues. Calculated volues using a proration forula based on test volues. Estiates of volues based on production facility and product characteristics. Scales for saples and vehicles. Gauge boards for tanks. Gauges for teperature and pressure. The Regulator has established standards of accuracy for gas and liquid easureent that take into account potential ipacts to royalty, equity, reservoir engineering, declining production rates, aging equipent, environent, public safety, accuracy and copleteness. These standards have evolved, but originated fro a 1972 Alberta Board hearing decision that deterined a need for pool production accuracy standards of 2.0% for oil, 3.0% for gas, and 5.0% for water. The current standards are stated as axiu uncertainty of onthly volue and/or single point easureent uncertainty. The uncertainties are to be applied as plus/inus e.g., ±5.0%. Measureent at delivery/sales points ust eet the highest accuracy standards because volues deterined at these points can have a direct ipact on royalty deterination. Other easureent points that play a role in the overall accounting process are subject to less stringent accuracy standards to accoodate physical liitations and/or econoics. The specific standards of accuracy are listed in Section 1.7. If an inspection of a easureent device or of procedure reveals unsatisfactory conditions that significantly reduces easureent accuracy, the Regulator will direct that the licensee ipleent changes to iprove easureent accuracy, and this direction will becoe a condition of operation for the facility or facilities. 1.2 Applicability and Use of Uncertainties The Regulator used the uncertainty levels contained in this section to develop any of the requireents for equipent and/or procedures relating to easureent, accounting, and reporting for various aspects of oil and gas production and processing operations, which are explained in detail in other sections. If those requireents are being et and consideration has been ade regarding the potential ipacts to royalty, equity, reservoir engineering, environent, public safety, accuracy and copleteness, the Regulator considers a licensee to be in copliance without the need to deonstrate copliance with the applicable uncertainty requireents contained in this section. August 1, 2017 Page 1-16

18 In soe scenarios a licensee ay deviate fro the iniu requireents for equipent and/or procedures that are stated in this Directive. Refer to Section 5: Site-specific Deviation fro Base Requireents. 1.3 Maxiu Uncertainty of Monthly Volue The Regulator requires production data to be reported on a calendar onth basis. Maxiu uncertainty of onthly volue relates to the liits applicable to equipent and/or procedures used to deterine the total onthly volue. Total onthly volues ay result fro a single onth-long easureent, but ore often result fro a cobination of individual easureents and/or estiations. For exaple, consider a well in an oil proration battery to which a axiu uncertainty of onthly volue would apply: First, the well is tested, and the oil test rate is used to estiate the well s production for the period until the next test is conducted. The well s total estiated oil production for the onth is cobined with the onth s estiated oil production for the other wells in the battery to arrive at the total estiated onthly oil production for the battery. The total actual onthly oil production for the battery is deterined based on easured deliveries out of the battery and inventory change. A proration factor is deterined by dividing the actual battery production by the estiated battery production. The proration factor is ultiplied by the well s estiated production to deterine the well s actual onthly production. 1.4 Single Point Measureent Uncertainty Single point easureent uncertainty relates to the liits applicable to equipent and/or procedures used to deterine a single-phase specific volue at a single easureent point. The oil volue deterined during a 24-hour well test conducted on a well in a proration battery is an exaple of a specific volue deterination to which a single point easureent uncertainty liit would apply. 1.5 Confidence Level The stated uncertainties are not absolute liits. The confidence level, which indicates the probability that true values will be within the stated range, is 95%. This iplies that there is a 95% probability, 19 chances in 20 that the true value will be within the stated range. 1.6 Deterination of Uncertainties The uncertainties referred to relate to the accuracies associated with easureent devices, device calibration, saple gathering and analysis, variable operating conditions, etc. These uncertainties are for single-phase specific volue deterination points of specific fluids (oil, gas, or water) or for cobinations of two or ore such points. These uncertainties do not relate to coparisons of two or ore easureent points, such as coparison of inlet volues to outlet volues. Such coparisons are typically expressed as proration factors, allocation factors, or etering differences. August 1, 2017 Page 1-17

19 The uncertainties are relevant to equipent at the tie of installation. No uncertainty adjustent is required to account for the effects of ultiphase fluids, wear, sludge or scale buildup, etc. as it is accepted that such conditions would constitute a bias error to be onitored and accounted for through the use of proration factors, allocation factors, or etering differences. The ethods to be used for deterining and cobining uncertainties are found in the latest edition of the Aerican Petroleu Institute (API) Manual of Petroleu Measureent Standards (MPMS), Chapter 13: Statistical Aspects of Measuring and Sapling or the latest edition of the International Standard Organization (ISO) Standard 5168: Measureent of Fluid Flow Estiation of Uncertainty of a Flow-rate Measureent. August 1, 2017 Page 1-18

20 1.6.1 Exaple Calculation Deterination of single point easureent uncertainty for well oil at a proration battery using root su square ethodology: Individual uncertainties fro historical research: For oil/eulsion easureent: Oil eter uncertainty = 0.5% (typical anufacturer s specification) Meter proving uncertainty = 1.5% Sedient and water (S&W) deterination uncertainty = 0.5% Cobined uncertainty = [( 0.5) (1.5) (0.5) ] 2 = 1.66% (rounded to 2.0%) 2 2 For gas easureent; Priary eleent gas eter uncertainty = 1.0% Secondary eleent (pulse counter or transducer, etc.) uncertainty = 0.5% Secondary eleent calibration uncertainty = 0.5% Tertiary eleent (flow calculation, Electronic Flow Measureent (EFM), etc.) uncertainty = 0.2% Gas sapling and analysis uncertainty = 1.5% Cobined uncertainty = [1.0) 2 + (0.5) 2 + (0.5) 2 + (0.2) 2 + (1.5) 2 ] = 1.95% (rounded to 2.0%) Oil Systes Oil Systes - Total Battery/Facility Oil Delivery point easureent, including single-well batteries. August 1, 2017 Page 1-19

21 Figure 1.1. Total battery/facility oil - delivery point easureent Oil Battery/Facility Oil Pipeline Oil Battery/Facility Pipeline Terinal Oil Pipeline Oil Battery/Facility or Gas Plant Oil Pipeline, Clean Oil Terinal, or other facilities Oil Battery/Facility Oil Battery/Facility or Gas Plant Oil Pipeline, Clean Oil Terinal, or other facilities Oil Battery/Facility Oil Battery/Facility Custo Treating Facility or 3 rd Party Licensed Clean Oil Terinal Oil Pipeline = single point easureent uncertainty Maxiu uncertainty of onthly volue = N/A The uncertainty of the onthly volue will vary, depending upon the nuber of individual easureents that are cobined to yield the total onthly volue. Single point easureent uncertainty: Delivery point easures > /d = 0.5% Delivery point easures /d = 1.0% August 1, 2017 Page 1-20

22 The royalty trigger point for oil is at the wellhead. Thus, delivery point easureents are required at the following locations: Facility dispositions Trucked-in receipts Pipeline receipts Railcar receipts Sales LACT Excluded: Test points and group points if they are not used for accounting or inventory Oil Systes - Total Battery Gas Includes produced gas that is vented, flared, or used as fuel, including single-well batteries. Also referred to as associated gas, as it is the gas produced in association with oil production at oil wells. Figure 1.2 Fuel or Flare S Gas S Vent S S Fuel Battery, Gas Gathering Syste, and/or Gas Plant Oil Battery Oil Oil Tank Vented Gas S Water S = single point easureent uncertainty Single point easureent uncertainty: > /d = 3.0% > /d but /d = 3.0% /d = 10.0% Maxiu uncertainty of onthly volue (M) > /d = 5.0% > /d but /d = 10.0% /d = 20.0% Note that M is dependent upon cobined deliveries, fuel, and vented gas easureent. August 1, 2017 Page 1-21

23 The axiu uncertainty of total onthly battery gas volues allows for reduced ephasis on accuracy as gas production rate declines. For gas rates up to /d, the gas volues ay be deterined by using estiates. Therefore, the axiu uncertainty of onthly volue is set at 20.0%. If gas rates exceed /d, the gas ust be etered. However, a coponent of the total onthly gas volue ay include estiates for low volues of fuel, vented, or flare gas that ay add to the onthly uncertainty. At the highest gas production rates, it is expected the use of estiates will be inial or at least have a inor ipact on the accuracy of the total onthly gas volue, thereby resulting in the 5% axiu uncertainty of onthly volue. The equipent and/or procedures used to deterine the etered gas volues when etering is required ust be capable of eeting a 3.0% single point easureent uncertainty. Due to the difficulty associated with etering very low gas rates, the equipent and/or procedures used in deterining gas-oil ratios or other factors to be used in estiating gas volues where rates do not exceed /d are expected to be capable of eeting a 10.0% single point easureent uncertainty. These uncertainties do not apply to gas produced in association with heavy oil with a density of 920 kg/ 3 or greater at 15 C Oil Systes - Total Battery Water Includes single-well batteries. Figure 1.3 Gas Battery, Gas Gathering Syste, and/or Gas Plant Oil Battery Oil Water Tank M Water No single point easureent uncertainty requireent. Maxiu uncertainty of onthly volue relates to deterination of total onthly volues (M). M = axiu uncertainty of onthly volue Maxiu uncertainty of onthly volue: > 50 3 /onth = 5.0% 50 3 /onth = 20.0% Single point easureent uncertainty = N/A August 1, 2017 Page 1-22

24 Total battery water ay be deterined by etering or estiation, depending on production rates, so no basic requireent has been set for single point easureent uncertainty. Total battery water production volues not exceeding 50 3 /onth ay be deterined by estiation. Therefore, the axiu uncertainty of onthly volue is set at 20.0%. If the total battery water production volues exceed 50 3 /onth, the water ust be separated fro the oil and easured. Therefore, the axiu uncertainty of onthly volue is set at 5.0% Oil Systes - Well Oil - Proration Battery Figure 1.4 To Gas Gathering Syste Gas Wells Test S Oil and Gas in Solution Oil Battery Oil Sales Water Water Disposal S = single point easureent uncertainty Single point easureent uncertainty: All classes = 2.0% Maxiu uncertainty of onthly volue: Class 1 (high) > 30 3 /d = 5.0% Class 2 (ediu) > 6 3 /d but 30 3 /d = 10.0% Class 3 (low) > 2 3 /d but 6 3 /d = 20.0% Class 4 (stripper) 2 3 /d = 40.0% Maxiu uncertainty is dependent upon oil and gas test volues and the nuber of days the test is used for estiating production, plus correction by a proration factor. The axiu uncertainty of onthly well oil production volues for light and ediu density oil wells in proration batteries has been developed to allow for reduced ephasis on accuracy as oil production rates decline. Rather than being deterined by continuous easureent, onthly well oil production volues are estiated fro well tests and corrected by the use of proration factors to result in actual volues. Lower rate wells are allowed reduced testing frequencies, which, coupled with the fact that wells ay exhibit erratic production rates between tests, results in less certainty that the reported onthly oil production volue will be accurate. August 1, 2017 Page 1-23

25 Oil Systes - Well Gas - Proration Battery Also referred to as associated gas, as it is the gas produced in association with oil production at oil wells. Figure 1.5 To Gas Gathering Syste Gas S Oil Wells Test Oil & GIS Oil Battery Oil Sales Water Water Disposal Total test gas ust include GIS with test oil. S = single point easureent uncertainty Single point easureent uncertainty: > /d = 3.0% > /d but /d = 3.0% /d = 10.0% Maxiu uncertainty of onthly volue: > /d = 5.0% > /d but /d = 10.0% /d = 20.0% Maxiu uncertainty is dependent upon oil and gas test volues and the nuber of days the test is used for estiating production, plus correction by a proration factor. The axiu uncertainty of onthly oil well gas volues has been developed to allow for reduced ephasis on accuracy as gas production rates decline. Rather than being deterined by continuous etering, onthly oil well gas production volues are estiated fro well tests and corrected by the use of proration factors to result in actual volues. Low gas production rates are typically associated with wells that are allowed reduced testing frequencies, which, coupled with the fact that wells ay exhibit erratic production rates between tests, results in less certainty that the reported onthly gas production volue will be accurate. For gas rates up to /d, the well test gas volue ay be deterined by using estiates. Therefore, the axiu uncertainty of onthly volue is set at 20.0%. If gas rates exceed /d, the test gas ust be etered. However, a coponent of a well s total test gas volue ay include estiates for gas in solution dissolved in the test oil August 1, 2017 Page 1-24

26 volue, which ay add to the onthly uncertainty. At the highest gas production rates, it is expected that the use of estiates will be inial or at least have a inor ipact on the accuracy of the total onthly gas volue, thereby resulting in the 5.0% axiu uncertainty of onthly volue. The equipent and/or procedures used to deterine the easured test gas volues if easureent is required ust be capable of eeting a 3.0% single point easureent uncertainty. Due to the difficulty associated with easuring very low gas rates, the equipent and/or procedures used in deterining gas-oil ratios or other factors to be used in estiating gas volues if rates do not exceed /d are expected to be capable of eeting a 10.0% single point easureent uncertainty Oil Systes - Well Water - Proration Battery Figure 1.6 To Gas Gathering Syste Gas Oil Wells Test Oil & GIS Oil Battery Oil Sales S Water Water Disposal S = single point easureent uncertainty Single point easureent uncertainty = 10.0% Maxiu uncertainty of onthly volue = N/A The uncertainty of the onthly volue will vary, depending upon the ethod used to deterine test water rates and the frequency of well tests. Rather than being deterined by continuous easureent, onthly oil well water production volues are estiated fro well tests and corrected by the use of proration factors to result in actual volues. The water rates deterined during the well tests ay be inferred fro deterining the water content of eulsion saples, and in soe scenarios estiates ay be used to deterine water rates. Therefore, the single point easureent uncertainty is set at 10.0%. August 1, 2017 Page 1-25

27 Gas Systes Gas Systes - Gas Deliveries Sales Gas Figure 1.7 Gas Plant Gas S Transission Pipelines, Other Gas Plants, Injection Systes, or Fuel for Other Facilities Battery or Gas Gathering Syste Gas S Transission Pipelines or Injection Systes S = single point easureent uncertainty Single point easureent uncertainty = 2.0% Maxiu uncertainty of onthly volue = N/A The total onthly volue ay result fro a single onth-long easureent, aking the uncertainty of the onthly volue equivalent to the single point easureent uncertainty. SK AB BC Since the delivery point is often a custody transfer point, a stringent expectation is set for the single point easureent uncertainty. The delivery point or royalty trigger point for gas is generally for clean processed gas disposition (DISP) at the plant gate or for raw gas that is sent to another facility for FUEL usage only. The easureent at this point deterines the gas volues upon which royalties will be based in Alberta. Therefore, a stringent expectation is set for the single point easureent uncertainty. Gas deliveries in this context will typically be clean, processed sales gas that is delivered out of a gas plant or gas facility into a transission pipeline. The easureent at this point deterines the gas volues on which royalties will be based. Therefore, a stringent expectation is set for the single point easureent uncertainty. August 1, 2017 Page 1-26

28 In soe scenarios, this type of gas ay be delivered to other plants for further processing or to injection facilities. Thus delivery point easureents are required at the following locations: Gas plant dispositions Sales to downstrea Purchase fro downstrea facilities Cross-border and cross-jurisdiction Gas delivered fro one upstrea facility to another that is not tied to the sae syste for FUEL, such as fro a gas battery to an oil battery Condensate disposition to an oil facility or for sales Excluded: Return fuel to the original source facility after the gas has been sweetened Gas Systes - Hydrocarbon Liquid Deliveries Figure 1.8 Gas Plant S Oil or Condensate Pipeline Gas Plant, Battery, or Gas Gathering Syste Oil or Condensate S Pipeline Terinal or Other Facilities S = single point easureent uncertainty Single point easureent uncertainty: Delivery point easures > /d = 0.5% Delivery point easures /d = 1.0% Maxiu uncertainty of onthly volue = N/A The uncertainty of the onthly volue will vary, depending upon the nuber of individual easureents that are cobined to yield the total onthly volue. The ter delivery point easureent for hydrocarbon liquids refers to the point at which the hydrocarbon liquid production fro a battery or facility is easured. Where clean hydrocarbon liquids are delivered directly into a pipeline syste via a Lease Autoatic August 1, 2017 Page 1-27

29 Custody Transfer Unit (LACT) easureent or trucked to a pipeline terinal, it can also be referred to as the custody transfer point. The delivery point terinology is fro the perspective of the producing battery or facility, but the receiving facility (pipeline, terinal, custo treating facility, other battery, etc.) ay refer to this point as its receipt point. The hydrocarbon liquid volue deterined at the delivery point is used in all subsequent transactions involving that liquid. Hydrocarbon liquids delivered out of a gas syste at the well, battery, or plant inlet levels are typically condensate, and in soe scenarios they ay be considered to be oil. The hydrocarbon liquids delivered out of a gas plant ay be pentanes, butane, propane, ethane, or a ixture of various coponents. The easureent equipent and/or procedures ust be capable of deterining the hydrocarbon liquid volue within the stated liits. For facilities where the hydrocarbon liquid delivery volues total /d, the single point easureent uncertainty has been increased to allow for the econoical handling of hydrocarbon liquids when inial volues would not justify the added expense for iproved easureent equipent and/or procedures Gas Systes - Plant Inlet or Total Battery / Group Gas Figure 1.9 Battery or Gas Gathering Syste Gas Plant Inlet Separator S Condensate M To Plant Processing M is dependent upon cobined uncertainties of easured gas and gas equivalent of condensate. Gas S M Gas Plant or Gas Gathering Syste Battery Condensate (recobined with gas) M is dependent upon cobined uncertainties of easured gas and gas equivalent of recobined condensate. Gas S M Gas Plant or Gas Gathering Syste Battery Condensate Oil Terinal / other facilities M is dependent upon uncertainties of easured gas only. M = axiu uncertainty of onthly volue S = single point easureent uncertainty August 1, 2017 Page 1-28

30 Maxiu uncertainty of onthly volue = 5.0% Single point easureent uncertainty = 3.0% Plant inlet gas or total battery/group gas is typically unprocessed gas that ay vary in coposition and ay contain entrained liquids. The total reported gas volue could result fro cobining several easured volues fro various points and ay also include the calculated gas equivalent volue of entrained hydrocarbon liquids, typically condensate. The expectation for the axiu uncertainty of onthly volue is set at 5.0% to allow for the uncertainties associated with easuring gas under these conditions. The equipent and/or procedures used to deterine the easured gas volues ust be capable of eeting a 3.0% single point easureent uncertainty Gas Systes - Plant Inlet or Total Battery / Group Condensate - Recobined Figure 1.10 Battery or Gas Gathering Syste Plant Inlet Separator Gas S To Plant Processing Condensate (reported as gas equivalent volue and included in Total Plant Inlet Gas) Gas Gas Plant or Gas Gathering Syste Battery S Condensate (recobined with gas) Gas Gas Plant or Gas Gathering Syste Battery Condensate Oil Terinal / Other Facilities If condensate is reoved fro the battery by truck and not sent for further processing, the single point easureent uncertainty for hydrocarbon liquid deliveries ust be et. S S = single point easureent uncertainty Single point easureent uncertainty = 2.0% Maxiu uncertainty of onthly volue = N/A The condensate volue is included in the total gas volue for reporting purposes and is therefore covered by the axiu uncertainty of onthly volue for the plant inlet or total battery/group gas. Plant inlet condensate is typically separated fro the inlet strea and sent through the plant for further processing. For reporting purposes, the gas equivalent of the plant inlet condensate is included in the total plant inlet gas volue. If total battery/group condensate August 1, 2017 Page 1-29

31 upstrea of the plant inlet is separated and easured prior to being recobined with the gas production, the condensate is converted to a gas equivalent volue and included in the gas production volue. In either scenario, the condensate single point easureent uncertainty is set at 2.0% for the liquid volue deterination. Note that if plant inlet or total battery/group condensate is separated and delivered out of the syste at that point, the condensate easureent is subject to the single point easureent uncertainties stipulated for hydrocarbon liquid deliveries stated in Section Gas Systes - Fuel Gas Figure 1.11 Well or Wells Fuel S Battery or Gas Gathering Syste Gas Fuel S = single point easureent uncertainty S S Fuel S S Gas Plant Unprocessed Fuel Fuel for other facility(s) S Processe d Fuel S Residue Gas Field Fuel Single point easureent uncertainty: > /d = 3.0% /d = 10.0% Maxiu uncertainty of onthly volue: > /d = 5.0% /d = 20.0% Note that axiu uncertainty is dependent upon cobined uncertainties of various fuel sources at each reporting facility. The axiu uncertainty of onthly fuel gas volues allow for reduced ephasis on accuracy as gas flow rates decline. For all upstrea oil and gas facilities, if the annual average fuel gas rate is /d or less on a per-site basis, the gas volue ay be deterined by using estiates. Therefore, the axiu uncertainty of the onthly volue is set at 20.0%. If the annual average fuel gas rates exceed /d on any site, the gas ust be etered, but since the gas being used as fuel ay be unprocessed gas and part of the total fuel gas volue ay include soe estiated volues up to /d, the axiu uncertainty of the onthly volue is set at 5.0% to allow for the uncertainties associated with easuring gas under those conditions. See Section for ore detail. The equipent and/or procedures used to deterine the easured gas volues if etering is required ust be capable of eeting a 3.0% single point easureent uncertainty. Due to the difficulty associated with easuring very low gas rates, the equipent and/or August 1, 2017 Page 1-30

32 procedures used in deterining gas-oil ratios or other factors to be used in estiating gas volues if rates do not exceed /d are expected to be capable of eeting a 10.0% single point easureent uncertainty Gas Systes - Flare and Vent Gas Figure 1.12 M M Flare/Vent Unprocessed gas S S Flare/Vent Acid gas Flare/Vent Processed Gas M Flare/Vent Flare/Vent S Gas Plant S Well or Wells S Battery or Gas Gathering Syste M is dependent upon cobined uncertainties of various flare gas points at each reporting facility.. M = axiu uncertainty of onthly volue S = single point easureent uncertainty Maxiu uncertainty of onthly volue = 20.0% Single point easureent uncertainty = 5.0% Flare gas ay be clean processed gas or it ay be unprocessed gas, depending on the point in the syste fro which gas is being flared. Continuous or interittent flare and vent sources at all oil and gas production and processing facilities, including theral in situ facilities but excluding non-theral heavy oil and bituen facilities, where annual average total flared and vented volues per facility exceed /d excluding pilot, purge, or dilution gas ust be etered. Sites requiring flare or vent gas etering ay estiate up to /day. Any continuous or interittent flare and vent sources at non-theral heavy crude oil or bituen facilities exceeding /day ust be etered. Sites requiring flare or vent gas etering ay estiate up to /day. Flare lines usually operate in a shut-in condition and ay be required to accoodate partial or full volues of gas production during flaring conditions. In soe scenarios if flaring is infrequent and no easureent equipent is in place, flare volues ust be estiated such as flaring at SW Saskatchewan or SE Alberta gas wells in a proration battery where there is no on-site easureent equipent. Therefore, the axiu uncertainty of the onthly volue is set at 20.0%, to allow for the erratic conditions associated with flare easureent. August 1, 2017 Page 1-31

33 Gas Systes - Acid Gas Figure 1.13 S Acid Gas to Sulphur Plant, Flare, or Injection Batteries and Gas Gathering Systes Gas Plant Residue Gas S = single point easureent uncertainty Single point easureent uncertainty = 10.0% for low pressure acid gas before copression, and = 3.0% after copression. Maxiu uncertainty of onthly volue = N/A The total onthly volue ay result fro a single onth-long easureent, aking the uncertainty of the onthly volue equivalent to the single point easureent uncertainty. Acid gas usually contains a great deal of water vapour and has other conditions associated with it, such as very low pressure that affects easureent accuracy. Therefore, the single point easureent uncertainty is set at 10.0%. See Section for details Gas Systes - Dilution Gas Figure 1.14 Acid Gas to Flare S Unprocessed Dilution Gas M Batteries and/or Gas Gathering Systes Gas Plant S Processed Dilution Gas Residue Gas M = axiu uncertainty of onthly volue S = single point easureent uncertainty M is dependent upon cobined uncertainties of various dilution gas sources. Single point easureent uncertainty = 3.0% Maxiu uncertainty of onthly volue = 5.0% August 1, 2017 Page 1-32

34 Dilution gas is typically fuel gas used to provide adequate fuel for incineration or flaring of acid gas. Since it ust be easured, it is subject to the sae uncertainties as stated in Section for fuel gas that ust be deterined by easureent Gas Systes Well with Gas - Separation Figure 1.15 Gas S M Gas Gathering Syste or Gas Plant Well Separator Condensate M is dependent upon cobined uncertainties of easured gas plus gas equivalent of condensate. Well Separator Gas S M = axiu uncertainty of onthly volue S = single point easureent uncertainty Oil or Condensate Gas Gathering Syste or Gas Plant Pipeline Terinal M is dependent upon uncertainties of easured gas only. Single point easureent uncertainty = 3.0% Maxiu uncertainty of onthly volue: > /d = 5.0% /d = 10.0% If production coponents fro gas wells are separated and continuously easured, the axiu uncertainty of onthly well gas volues allows for reduced ephasis on accuracy as gas production rates decline. Since the separated gas is unprocessed and ay still contain entrained liquids at the easureent point and a coponent of the total reported well gas production ay include the calculated gas equivalent volue of the well s condensate production, the axiu uncertainty of onthly volues also allows for the uncertainties associated with easuring gas under those conditions. The equipent and/or procedures used to deterine the separated easured well gas volues ust be capable of eeting a 3.0% single point easureent uncertainty. August 1, 2017 Page 1-33

35 Gas Systes - Well Gas - Proration Battery Figure Well gas (effluent easureent battery) Wells with Effluent Measureent M M M Test Taps Group Separator Gas Gas Gathering Syste or Gas Plant Condensate Testing Unit Separator Gas S Metered and Recobined Condensate M is dependent upon well effluent easureent, correction by an effluent correction factor, and a proration factor. Produced Water M = axiu uncertainty of onthly volue S = single point easureent uncertainty Figure Effluent Measureent Battery (SW Saskatchewan, SE Alberta or other approved proration battery) Wells with No Continuous Measureent M M M Test Taps Group Separator Gas Gathering Syste or Gas Plant Condensate S Test Meter or Separator M is dependent upon well estiates and correction by a proration factor. M = axiu uncertainty of onthly volue S = single point easureent uncertainty Single point easureent uncertainty = 3.0% Maxiu uncertainty of onthly volue = 15.0% If production coponents fro gas wells are not separated and continuously easured, the gas wells are subject to a proration accounting syste. There are two types of gas proration batteries. Effluent gas wells have continuous effluent easureent, and the actual production is prorated based on the easureent of group gas and liquid coponents following separation at a central location. Dry gas wells approved to operate without continuous easureent have the production estiated based on periodic tests, and the August 1, 2017 Page 1-34

36 Separator actual production is prorated based on the easureent of group volues at a central location. For both types of proration batteries, the axiu uncertainty of the onthly well gas volue is set at 15.0% to allow for the inaccuracies associated with these types of easureent systes. The equipent and/or procedures used to deterine the easured well test gas volues downstrea of separation during effluent eter correction factor tests or during the periodic dry gas well tests ust be capable of eeting a 3.0% single point easureent uncertainty Gas Systes - Well Condensate - Recobined Figure 1.18 Gas Gas Gathering Syste or Gas Plant Well S Condensate S = single point easureent uncertainty Single point easureent uncertainty = 2.0% Maxiu uncertainty of onthly volue = N/A The gas equivalent of the condensate volue is included in the total well gas volue for reporting purposes and is therefore covered by the onthly uncertainty for the well gas. If condensate produced by a gas well is separated and easured at the wellhead prior to being recobined with the gas production, the condensate is atheatically converted to a gas equivalent volue and added to the well gas production volue. In this scenario, the condensate single point easureent uncertainty is set at 2.0% for the liquid volue deterination. No requireent has been set for the axiu uncertainty of onthly volue because the gas equivalent of the condensate volue is included in the total well gas volue for reporting purposes. In the scenario of a gas well subject to effluent easureent, the gas equivalent of the condensate volue is included in the well s total gas production volue. The liquid volue deterination, which is done during the effluent eter correction factor test, is subject to a single point easureent uncertainty of 2.0%. No requireent has been set for the axiu uncertainty of onthly volue because the gas equivalent of the condensate volue is included in the total well gas volue for reporting purposes. Note that if condensate produced by a gas well is separated at the wellhead and delivered out of the syste at that point, the condensate is reported as a liquid volue. In this scenario, the condensate easureent is subject to the single point easureent uncertainties stipulated for hydrocarbon liquid deliveries stated in Section August 1, 2017 Page 1-35

37 Separator Gas Systes - Total Battery Water Figure 1.19 Gas Well or Wells Water Battery Condensate Water Tank M Total battery water ay be the water separated at the battery, the su of the water separated at the wells, or a cobination. M is dependent upon the ethod used to deterine the total water volue. M = axiu uncertainty of onthly volue Single point easureent uncertainty = N/A Maxiu uncertainty of onthly volue = 5.0% Total battery water ay be deterined by an individual group easureent, by totaling individual well easureents, or by totaling individual well estiates, so no basic requireent for easureent uncertainty has been set. Total battery water in a gas syste ay be collected at a central location where it can be easured prior to disposal, or it ay be a suation of individual well estiates or easureents of water collected at ultiple locations and disposed fro those sites. The 5.0% axiu uncertainty of onthly volue allows for soe leeway in volue deterination Gas Systes - Well Water Figure 1.20 Well Gas Condensate S Battery or Gas Gathering Syste Water Tank S = single point easureent uncertainty Single point easureent uncertainty = 10.0% Maxiu uncertainty of onthly volue = N/A The uncertainty of the onthly volue will vary, depending upon whether produced volues are subject to individual well easureent, estiation, or proration. August 1, 2017 Page 1-36

38 Water production at gas wells ay be deterined by easureent after separation, or if separators are not used, it ay be deterined by using water-gas ratios deterined fro engineering calculations or seiannual tests. To allow for the various ethods used to deterine production volues, the single point easureent uncertainty is set at 10.0% Injection/Disposal Systes Injection/Disposal Systes - Total Gas Figure 1.21 Gas Plant or Battery Gas Plant Liquid Petroleu Gas (LPG) Gas Plant LPG M Injection Facility Well or Wells M = axiu uncertainty of onthly volue M is dependent upon cobined uncertainties of various sources and types of fluids received. Maxiu uncertainty of onthly volue = 5.0% Single point easureent uncertainty = N/A The single point easureent uncertainty will vary depending on the source and type of fluids received. Gas used in injection/disposal systes ay be clean processed gas or unprocessed gas that ay contain entrained liquids, and in soe scenarios several sources ay ake up the total gas volue received by an injection syste. The expectation for the axiu uncertainty of onthly volue is set at 5.0% to allow for the uncertainties associated with easuring gas under those conditions Injection/Disposal Systes - Well Gas Figure 1.22 Injection Facility S S Well or Wells S = single point easureent uncertainty Single point easureent uncertainty = 3.0% Maxiu uncertainty of onthly volue = N/A August 1, 2017 Page 1-37

39 The total onthly volue ay result fro a single onth-long easureent, aking the uncertainty of the onthly volue equivalent to the single point easureent uncertainty. The gas injected/disposed into each well ust be easured at the injection site and ay consist of clean processed gas and/or unprocessed gas that ay contain entrained liquids. The equipent and/or procedures used to deterine the gas volues injected/disposed into each well ust be capable of eeting a 3.0% single point easureent uncertainty Injection/Disposal Systes - Total Water Figure 1.23 M Gas Plants, Batteries, or Fresh Water Sources Injection Facility Well or Wells M = axiu uncertainty of onthly volue M is dependent upon cobined uncertainties of various sources and types of water received. Maxiu uncertainty of onthly volue = 5.0% Single point easureent uncertainty = N/A To be equivalent to the requireents for Oil Systes - Total Battery Water (Section ) and Gas Systes - Total Battery Water (Section ). Water used in injection/disposal systes ay be produced water fro oil or gas batteries, fresh water fro water source wells, or waste water. To be equivalent to the requireents for total oil and gas battery water, the expectation for the axiu uncertainty of onthly volue is set at 5.0% Injection/Disposal Systes - Well Water / Stea Figure 1.24 Gas Plants, Batteries, or Fresh Water Sources Injection Facility S S Well or Wells S = single point easureent uncertainty Single point easureent uncertainty = 5.0% Maxiu uncertainty of onthly volue = N/A The total onthly volue ay result fro a single onth-long easureent, aking the uncertainty of the onthly volue equivalent to the single point easureent uncertainty. August 1, 2017 Page 1-38

40 The water/stea injected/disposed into each well ust be easured at the injection site. The single point easureent uncertainty is set at 5.0%. For water and stea production at a theral in situ facility, the single point easureent uncertainty is set at 2.0%, see Sections and for details Standards of Accuracy Suary Oil Systes excluding heavy oil Flow Rate Maxiu uncertainty of onthly volue Single point easureent uncertainty (i) Total battery oil (delivery point easureent) Delivery point easures > /d N/A 0.5 Delivery point easures /d N/A 1.0 (ii) Total battery gas (includes produced gas that is vented, flared, or used as fuel) > /d > /d but /d /d (iii) Total battery water > 50 3 /onth 5.0 N/A 50 3 /onth 20.0 N/A (iv) Well oil (proration battery) Class 1 (high), > 30 3 /d Class 2 (ediu), > 6 3 /d but 30 3 /d Class 3 (low), > 2 3 /d but 6 3 /d Class 4 (stripper), 2 3 /d August 1, 2017 Page 1-39

41 Flow Rate Maxiu uncertainty of onthly volue Single point easureent uncertainty (v) Well gas (proration battery) > /d > /d but /d /d (vi) Well water N/A Gas Systes Flow Rate Maxiu uncertainty of onthly volue Single point easureent uncertainty (i) Gas deliveries (sales gas) N/A 2.0% (ii) Hydrocarbon liquid deliveries Delivery point easures /d N/A 0.5% Delivery point easures > /d N/A 1.0% (iii) Plant inlet or total battery/group gas 5.0% 3.0% (iv) Plant inlet or total battery/group condensate (recobined) N/A 2.0% (v) Fuel gas > /d 5.0% 3.0% /d 20.0% 10.0% August 1, 2017 Page 1-40

42 Flow Rate Maxiu uncertainty of onthly volue Single point easureent uncertainty (vi) Flare and vent gas 20.0% 5.0% (vii) Acid gas before copression N/A 10.0% Acid gas after copression N/A 3.0% (viii) Dilution gas 5.0% 3.0% (ix) Well gas (well site separation) > /d 5.0% 3.0% /d 10.0% 3.0% (x) Well gas (proration battery) 15.0% 3.0% (xi) Well condensate (recobined) N/A 2.0% (xii) Total battery water 5.0% N/A (xiii) Well water N/A 10.0% Injection/Disposal Systes Maxiu uncertainty of onthly volue Single point easureent uncertainty (i) Total gas 5.0% N/A (ii) Well gas N/A 3.0% (iii) Total water 5.0% N/A August 1, 2017 Page 1-41

43 Maxiu uncertainty of onthly volue Single point easureent uncertainty (iv) Well water/stea N/A 5.0% Produced water/stea at theral in situ oil sands facilities N/A 2.0% Heavy Oil - excluding Theral In Situ Operations (fro Section 12) Maxiu uncertainty of onthly volue Single point easureent uncertainty (i) Gas N/A 3.0% (ii) Liquid products received into a cleaning plant, excluding the effect of S&W and density deterination N/A 1.0% (iii) Sales oil delivery point fro a treatent facility N/A 0.5% (iv) Test eulsion eter, excluding the effect of S&W deterination N/A 2.0% Theral In Situ Operations (fro Section 12) Maxiu uncertainty of onthly volue Single point easureent uncertainty (i) Gas production or injection N/A 3.0% (ii) Eulsion tesing using grouped well etering when the subsurface drainage area has coalesced excluding the effects S&W deterination 5.0% August 1, 2017 Page 1-42

44 Maxiu uncertainty of onthly volue Single point easureent uncertainty (iii) Eulsion test using etering for individual wells - excluding the effects S&W deterination N/A 2.0% (iv) Clean oil/bituen sales N/A 0.5% (v) Wellhead stea injection (CWE) N/A 5.0%, (vi) All other stea easureent, including stea leaving a stea plant (CWE) N/A 2.0% (vii) Liquid solvent injection N/A 2.0% (viii) Fresh, brackish, or produced water delivered to or fro an injection facility N/A 2.0% (ix) Boiler feed water, boiler blowdown N/A 2.0% (iix) Water disposal N/A 2.0% 1.8 Measureent Scheatics This section presents the requireents for easureent scheatics used for easureent, accounting, and reporting of oil and gas facilities. Measureent scheatics are required to ensure easureent, accounting, and reporting copliance and are visual tools showing the current physical layout of the facility. Scheatics should be regularly reviewed and used by groups such as operations, engineering, and production accounting to ensure a coon understanding. For the purpose of this Directive, process flow diagras (PFD), piping and instruentation diagras, and process and instruentation diagras (P&ID) are not considered easureent scheatics Measureent Scheatics Requireents The operator of record, the copany who reports the onthly production to the Regulator generally via Petrinex, is responsible for creating, confiring, and revising any easureent scheatics. The well licensee and physical operator shall provide all assistance they can. The scheatics ust be used by operations and production accounting to ensure that the reported volues are in copliance with the Regulator s reporting and licensing requireents. How the required inforation is shown on a easureent scheatic is up August 1, 2017 Page 1-43

45 to the operator of record to decide as long as the easureent scheatic is clear and coprehensive. The easureent scheatic can be stored electronically or in hard-copy forat. A aster copy of the easureent scheatic ust be retained at a central location and previous versions ust be stored for a iniu of 18 onths. The easureent scheatic ust include the following: Facility nae, facility licensee nae, and operator nae if different Legal Survey Location of surface facility and Unique Well Identifier (UWI), including downhole location, if different Facility boundaries between each reporting facility with associated Petrinex codes and facility subtypes. For larger facilities, an optional field flow diagra ay be used to show facility delineation. See Appendix 8 for an exaple. Flow lines with flow direction that ove fluids in and out of the facility(s) and those that connect the essential process equipent within the facility, including recycle lines and bypasses to easureent equipent. Identify if oil is tied into a gas syste. Flow split or diversion points (headers) with theirlegal Survey Location if they are not on a well or facility lease site. Process equipent that change the state or coposition of the fluid(s) within the facility, such as separators, treaters, dehydrators, copressors, sweetening and refrigeration units, etc. Measureent points and storage tanks or vessels that are used for estiating, accounting, or reporting purposes, including: a. Type of instruentation (charts, EFM, or readouts) b. Type of eter(s) if applicable c. Testing or proving taps required by the Regulator Fuel, flare, or vent take-off points default to estiated if eter not shown Energy source (gas, propane, electricity) used for equipent if not etered or estiated as part of total site fuel. 10. Peranent flare points 11. Fresh water sources, such as lakes and rivers UWIs and Legal Survey Locations are to be in a deliited forat, such as 100/ W5/02 and W5, respectively. Multiple facilities can be depicted on the sae page and a typical scheatic ay be used for wells or facilities with the sae easureent configuration. Additional inforation required on the scheatic: Wells 1. A list of all producing, water source, injection/disposal, and shut-in wells. 2. Reporting event for wells with downhole coingled stratigraphic units or zones. August 1, 2017 Page 1-44

46 3. Identify echanical lift, such as plunger lift, pupjack, etc. SK AB BC Default to ACTIVE if not shown. Default to FLOW if not shown. Default to Active if not shown 4. Suspended wells are optional, if shown, identify the as suspended. 5. Except for: Process Equipent a. Heavy Oil/Crude Bituen Adinistrative Grouping (subtype 343) and Heavy Crude Oil Paper Battery (subtype 313): The well list is not required to be on the scheatic but ust state how any wells are in the battery and ust be available upon request by the Regulator. b. Gas Multiwell Proration SW Saskatchewan and SE Alberta Batteries (subtypes 363 and 366): The well list is not required to be on the scheatic but ust state how any wells there are on each branch coing into the battery location and ust be available upon request by the Regulator. c. Gas Test Battery (subtype 371) and Drilling and Copleting Battery (subtype 381): No easureent scheatic is required until the well is tied to a production battery and starts producing. 1. Norally closed valves that can change production flow. 2. Identify if copressors are electric or gas drive. If they are gas drive, then the HP or KW rating is required unless fuel gas is easured as part of total fuel within a facility. Soe cross-border facilities ay be required to easure fuel for soe copressors individually. 3. Norally open valves, such as eergency shutdown valves (ESDs), pressure-control valves (PCVs), and block valves, are not required as they can be considered default flow. 4. Pressure safety valves (PSV) are not required. Measureent Points 1. Identify non-accounting eters if shown. 2. Originating facility ID or UWI/Legal Survey Locations for truck-in receipt points is not required. Storage Tanks and Vessels 1. Include fluid type for these tanks, vessels, and caverns, such as oil, eulsion, condensate, plant product, waste, or water; tank and vessel capacity ay be shown on separate docuent and should be available upon request. 2. Identify if the tank or vessel is underground or default to aboveground. 3. Identify optional non-reporting cheical storage or pop tanks if shown. 4. Identify if the tank or vessel is tied into a vapour recovery syste (VRU) or flare syste with the default being too vented. August 1, 2017 Page 1-45

47 SK AB BC A Measureent, Accounting and Reporting Plan (MARP) for Theral In Situ Projects For enhanced oil recovery projects requiring a MARP, the easureent scheatic ust include these additional ites: 1. blowdown lines 2. ponds volue and fluid type 3. eter ID and saple point ID 4. tank gauge 5. pups 6. secondary easureent points Measureent, Accounting, and Reporting Plan (MARP) for Theral In Situ Oil Sands Schees For enhanced oil recovery schees requiring a MARP, the easureent scheatic ust include these additional ites: 1. blowdown lines 2. ponds volue and fluid type 3. eter ID and saple point ID 4. tank gauge 5. pups 6. secondary easureent points No Theral In Situ Oil Sand Schees in BC at this tie Measureent Scheatic Updates Changes affecting reporting ust be redlined on the easureent scheatic at the field level when they occur and counicated to the production accountant at a date set by the operator of record to facilitate accurate reporting before the Petrinex subission deadline. 1. Physical changes, such as wells, piping, or equipent additions or reoval, require a easureent scheatic update. 2. Teporary changes within the sae reporting period do not require a easureent scheatic update. The aster copy of the easureent scheatic ust be updated annually to reflect any changes or deletions. There ust be verification of the revisions or, if no revisions, confiration of no change. Docuentation of the verification ay be stored separately fro the easureent scheatic but ust be available on request. August 1, 2017 Page 1-46

48 1.8.3 Ipleentation SK AB BC Operators ust have easureent scheatics for all the applicable facilities outlined in Directive PNG017 by April 1, Fully Ipleented. Fully Ipleented No grandfathering for active facilities. A facility that is reactivated ust have an up-to-date easureent scheatic within three onths of reactivation or after the ipleentation period Measureent Scheatic Availability Scheatics ust be provided by the operator of record to the following external parties upon request: 1. Facility licensee of the subject facility 2. The copany that perfors the voluetric reporting for the facility and the well licensee of wells within a reporting facility 3. The copany that perfors the product and residue gas allocations up to the allocation point(s) 4. Saskatchewan, Alberta and British Colubia Regulators or other cross-border Regulatory bodies 5. Operator of receipt/disposition points all reporting easureent points for the facility only 1.9 Facility Delineation Requireents Delineation of lease sites and geographic areas into reporting facilities is based on the easureent, accounting, and reporting rules described in: SK AB BC This Directive and Directive R01 Voluetric, Valuation and Infrastructure Reporting. AER s Directive 017: Measureent Requireents for Oil and Gas Operations and Directive 007: Voluetric and Infrastructure Requireents. BCOGC Measureent Guideline for Upstrea Oil and Gas Operations Manual does not have a specific section for Facility Delineation Requireents. If further inforation is required contact OGCPipelines.Facilities@bcogc.ca. Facility delineation requires accurate inforation on process flows and easureent points in the field, as well as a sound understanding of the Regulator facility definitions and facility subtypes outlined in the aforeentioned directives. Multiple easureent points and Regulatory flexibility can result in ore than one way of delineating soe facilities. However, the following general guidelines can be used. August 1, 2017 Page 1-47

49 1. All gas and liquid received into and delivered fro a facility ust be continuously or batch easured in a single phase. 2. Wells and the associated equipent are only linked to and reported under batteries (BT), injection facilities (IF), or water source facilities (WT). a. Gas wells are linked to and reported under gas batteries. b. Crude oil wells and bituen wells are linked to and reported under crude oil batteries. c. Disposal wells are linked to and reported under disposal facilities. d. Injection wells are linked and reported under injection facilities. e. Source water wells: SK AB BC are linked to and reported under water source facilities (WT). ay be linked to either a battery or, ore coonly, the injection facility. If there is gas production, then linking to a subtype 902 battery will facilitate gas voluetric reporting. ay be linked to either a battery, processing battery, injection station, or water hub facility. If there is gas production, then linking to a battery will facilitate gas voluetric reporting. 3. Measured and prorated wells ust not be linked to the sae battery and ust be reported under separate reporting codes. August 1, 2017 Page 1-48

50 2 Calibration and Proving Metering devices all require various types of aintenance to ensure operating conditions eet the uncertanity requireents outlined in Section 1 Standary of Accuracy. This Section presents the base requireents and exeptions for aintaining etering devices. The calibration and proving requireents stipulated in this Directive are applicable to easureent devices used to deterine volues for Regulator-required accounting and reporting purposes. These requireents are not applicable to easureent devices used only for a licensee s internal accounting purposes. The requireents are considered inius, and a licensee ay choose to apply ore stringent requireents. If a licensee wishes to deviate fro these requireents or exeptions other than applying ore stringent requireents, see Section 1: Standards of Accuracy to deterine if the deviation requires subission of an application to and approval by the Regulator. 2.1 Frequency The accuracy of easureent devices ay deviate over tie, due to wear, changes in operating conditions, changes in abient conditions, etc. Generally, the ore iportant the accuracy of a easureent device is, the ore frequently it ust be calibrated or proved. Exaple: For an annual frequency, if the last calibration was perfored in May 2006, the operator has to perfor another calibration by the end of June 2007 (end of the calendar quarter) Frequency Exeptions 1. If the use or operation of a easureent device requiring onthly, bionthly or quarterly calibration/proving is suspended for at least seven consecutive days, the scheduled calibration/proving ay be delayed by the nuber of days the device was not in service. Docuentation of the aount of tie the device was not in service ust be kept and ade available to the Regulator on request. If this exeption is being applied, the licensee ust attach a tag to the eter indicating that this exeption is in effect and the next scheduled calibration/proving date. This exeption is not applicable to easureent devices subject to calibration/proving frequencies that are seiannual or longer. 2. If a liquid eter is reoved fro service for bench proving but is put on the shelf and not returned to service, the countdown to the next required bench proving does not start until the eter is returned to service. The licensee ust attach a tag to the eter indicating the installation date, but leaving the original proving tag intact. 3. The Regulator ay request that calibration/proving of a eter be done at any tie or ay shorten or extend the due date for scheduled calibration/proving, depending on the specific circustances at a easureent point. 2.2 Accuracy of Provers and Calibration Instruents Provers and other instruents used for calibration of easureent devices ust be tested for accuracy prior to first being used or iediately following any repairs (prior to being put August 1, 2017 Page 2-1

51 back into service) or alterations being conducted on the, and periodically, in accordance with the following: Portable provers ust be calibrated every two years using easureent standards that are traceable to the standards listed in Section Stationary provers ust be calibrated every four years using easureent standards that are traceable to the standards listed in Section Calibration instruents, such as anoeters, theroeters, pressure gauges, deadweight testers, electronic testers, etc., ust be tested for accuracy every two years against instruents having accuracy traceable to the standards listed in Section Master eters ust be proved quarterly using a calibrated prover. The fluid used to prove the aster eter ust have properties siilar to the fluids easured by the eters it will be used to prove. The aster eter ust be proved at flow rates that are coparable to the conditions it will be used for. The easureent uncertainty of the proving or calibrating device ust be equal to or better than the uncertainty of the device being proved or calibrated Provers and Calibration Procedure Standards The procedures to be followed for these accuracy tests ust be designed to provide consistent and repeatable results and ust take into consideration the actual operational conditions the device will encounter. The calibration and proving procedures ust be in accordance with the following standards: 1. Procedures specified by Measureent Canada (An Agency of Industry Canada), 2. Procedures described in the API Manual of Petroleu Measureent Standards, 3. The device anufacturer s recoended procedures, or 4. Other applicable procedures accepted by an appropriate industry technical standards association. Records of the foregoing accuracy tests ust be kept for a iniu of three years following the expiry of the applicable test and provided to the Regulator on request Gas Meters Gas Meter Calibration Requireents The ter gas eter is broadly used to describe all of the equipent or devices that are collectively used to arrive at an indication of a gas volue. Typically, various values, such as differential pressure, static pressure and teperature, ust be deterined and used to calculate a gas volue. Depending on the specific gas eter, each of those values ay be deterined by individual devices or equipent. Calibration of gas eter eleents requires the instruentation to be subjected to various actual pressures, teperatures, and other values that are concurrently subjected to the calibration equipent. If the eter eleent or end device do not indicate the sae value as the calibration equipent, adjustents ust be ade to the eter eleent and/or end device. August 1, 2017 Page 2-2

52 Soe eter equipent technologies ay require alternative equipent and procedures for calibration, which is acceptable provided that the equipent and procedures are capable of confiring that the eter eleents are functioning properly and are sensing and transitting accurate data to the end device. Orifice eters are coonly used to easure gas volues. Gas orifice eters theselves (the eter run and orifice plate-holding device) do not require calibration/proving. However, the associated eter eleents and the end devices to which they are connected ust be calibrated, as described in Section If devices other than orifice eters are used to easure gas, the associated eter eleents and the end devices to which they are connected ust be calibrated at the sae frequency as orifice eters. The required procedures ust be designed to provide consistent and repeatable results and ust take into consideration the actual operational conditions the device will encounter Gas Meter Calibration Frequency The frequency of eter eleent calibration and end devices ust be: 1. Within the first calendar onth of operation of a new eter 2. By the end of the calendar onth following installation, after service or repairs have been ade to the eter 3. Seiannually thereafter if the eter is used in a gas plant or for sales/delivery point, see Section for details 4. Annually for all other eters See Section for the exeptions that extend calibration frequency Gas Meter Internal Inspection A key contributor to eter accuracy is the condition of the internal coponents of the gas eter. Exaples of internal coponents are orifice plates, vortex shedder bars, and turbine rotors. The procedure to inspect internal coponents is: 1. The internal coponent ust be reoved fro service, 2. It ust be inspected, 3. It ust be replaced or repaired if found to be daaged, and 4. It can then be placed back in service. This procedure ust be in accordance with the following: 1. The required frequency for inspection of the gas eter priary eleent is seiannually for gas plant accounting eters and sales/delivery point eters and annually for all other gas eters. 2. Whenever possible, the inspection should be done at the sae tie as the calibration of the eter eleents and end device, but to accoodate operational constraints the inspection ay be conducted at any tie, provided that the frequency requireent is et. August 1, 2017 Page 2-3

53 3. Inspections ust be done in accordance with procedures specified by the API, the Aerican Gas Association (AGA), other relevant standards organizations, other applicable industry-accepted procedures, or the device anufacturer s recoended procedures, whichever are ost applicable and appropriate. 4. A tag or label ust be attached to the eter or end device that identifies the eter serial nuber, the date of the internal inspection, and any other relevant details. 5. A detailed record of the inspection docuenting the condition of the internal coponents found and any repairs or changes ade to the internal coponents ust be kept for at least one year and provided to the Regulator on request Gas Meter Calibration and Proving Exeptions 1. If the as found calibration check of the gas eter confirs that the accuracy of all readings or outputs are within ±0.25% of full scale, with the exception of ±1 C for the teperature eleent, no adjustent of the instruentation is required. 2. If eter eleents and end devices have been found to not require adjustent for three consecutive calibrations, as indicated in ite 1 above, the iniu tie between routine calibrations ay be doubled. A tag ust be attached to the eter indicating that this exeption is being applied and the date of the next scheduled calibration. The records of the calibrations that qualify the eter for this exeption ust be kept for at least one year and ade available to the Regulator on request. 3. If redundant gas eters are installed for a easureent point or redundant eter eleents and/or end devices are installed on a single gas eter, the iniu tie between routine calibration of the eter eleents and end devices ay be doubled, provided that daily volues fro each end device are copared at least onthly and found to be within 0.25% of each other. If the daily volues are not found to be within 0.25% of each other, iediate calibration of both sets of equipent is required. A tag ust be attached to the eter indicating that this exeption is being applied and the date of the next scheduled calibration. The records of the onthly coparisons and any calibrations that are done ust be kept for at least one year and ade available to the Regulator on request. 4. If rotary, turbine, or other types of gas eters with internal oving parts are used to easure gas, such as fuel gas, they ust be proved at a frequency of once every seven years following an initial proving prior to installation. The calibration of related eter eleents ust follow Section These eters ust also be proved iediately following any repairs or alterations being conducted on the. The proving ay be done with the eter in service, or the eter ay be reoved fro service and proved in a shop at a pressure that is within the noral operating condition for that eter location unless it can be shown that proving at lower pressure conditions will not change the uncertainty of the eter, such as in the scenario of a rotary eter. A tag or label ust be attached to the eter that identifies the eter serial nuber, the date of the proving, and the eter factor deterined by the proving. A detailed report indicating the details of the proving operation ust be either left with the eter or readily available for inspection by the Regulator. (If the detailed report is left with the eter, the foregoing requireent relating to the tag or label is considered to be et.) August 1, 2017 Page 2-4

54 5. For eters used in effluent easureent that require proving, such as a turbine eter, the proving ust be perfored by using a gas aster eter or other provers in single-phase proving runs. For effluent correction factor (ECF) water gas ratio (WGR) testing, see Section If the internal coponents of gas eters have been found to be clean and undaaged for three consecutive inspections, the iniu tie between inspections ay be doubled. When the internal coponents are found to be dirty or daaged on any subsequent inspection, the frequency for inspections will revert back to the original requireent. 7. If the inspection of internal coponents of a gas eter requires the eter to be reoved fro service and there is no eter bypass installed, it is acceptable to defer a scheduled internal coponent inspection until the next tie the gas eter run is shut down, provided that shutting down and depressuring the gas eter run to reove and inspect the internal coponents would be very disruptive to operations, require excessive flaring, or cause a safety concern, and: a. Previous internal coponent inspections have proven to be satisfactory; or b. The eter run is installed in a flow strea where the risk of internal coponent daage is low, e.g., sales gas, fuel gas; or c. The easureent syste at the facility provides sufficient assurance, through voluetric and/or statistical analysis, that internal coponent daage will be detected in a tiely anner. 8. In the scenario of an orifice eter, if the orifice plate is ounted in a quick-change (senior) orifice eter assebly and when attepting to conduct an inspection of the orifice plate the fitting is found to be leaking between the chabers such that the eter run ust be shut down and depressured to safely reove the orifice plate, it is acceptable to defer a scheduled orifice plate inspection until the next tie the gas eter run is shut down, provided that: a. shutting down and depressuring the gas eter run to reove the orifice plate would be very disruptive to operations, require excessive flaring; or b. the orifice eter assebly is scheduled for repairs to be conducted the next tie the gas eter run is shut down to eliinate the cause of the leak and allow future scheduled orifice plate inspections to be conducted; and one of the following ust be true: i. Previous orifice plate inspections have proven to be satisfactory; ii. iii. The eter run is installed in a flow strea where the risk of orifice plate daage is low, e.g., sales gas, fuel gas, etc.; or The easureent syste at the facility provides sufficient assurance, through voluetric and/or statistical analysis, that orifice plate daage will be detected in a tiely anner. 9. Internal etering diagnostics ay be used to deterine if the structural integrity of the priary eleent is within acceptable operating paraeters and checked at the sae required intervals as an internal inspection. Then internal inspection is not required until an alar or error is generated by the device or as recoended by the anufacturer. The operator ust aintain docuentation on the diagnostic August 1, 2017 Page 2-5

55 capability of the easureent syste and ake it available to the Regulator on request. An initial baseline diagnostic profile ust be perfored and docuented during the coissioning process. 10. Single phase in-line proving of the gas eter ay be used to deterine if the priary eleent/eter eleent is within acceptable operating paraeters and proved at the sae required intervals as an internal inspection. Then internal inspection is not required until the uncertainty liits are exceeded. Should the priary eleent inspections be deferred in accordance with any of the foregoing exeptions, the licensee ust be able to deonstrate to the Regulator, on request, that the situation eets the conditions identified. If these exeptions are being used, it ust be clearly indicated on a tag or label attached to the eter or end device. Evidence in battery or facility logs that the internal coponent inspection has been scheduled for the next shutdown ust be available for inspection by the Regulator. For the purposes of these exeptions, shutdown eans any scheduled discontinuation of flow through the eter that is of sufficient duration to allow the operations needed to reove and inspect the internal coponent. If an unscheduled shutdown appears that it will allow sufficient tie to conduct internal coponent inspection operations, the licensee should conduct those inspections prior to the conclusion of this unscheduled shutdown Orifice Meters with Chart Recorder Calibrations The procedure for orifice eter chart recorder (eter eleent and end device) calibration ust be in accordance with the following: Pen arc, linkage, pressure stops, and spacing ust be inspected and if necessary be adjusted. The differential pressure eleent ust be calibrated at zero, full span, and nine ascending/descending points throughout its range. A zero check of the differential under noral operating pressure ust be done before and after the calibration. The static pressure eleent ust be calibrated at: a. zero; b. 50% of full span; and c. full span. If a teperature eleent is in place, the teperature eleent ust be calibrated at three teperatures: a. operating teperature; b. one colder teperature; and c. one warer teperature. If a theroeter is in place and used to deterine flowing gas teperature, the theroeter ust be checked at two points: a. operating teperature; and b. one other teperature. If the theroeter is found not to read within ±1 C it ust be replaced. August 1, 2017 Page 2-6

56 If a theroeter or other teperature easuring device is not left in place and is transported by an operator to deterine flowing gas teperatures at ultiple sites, the accuracy of that device ust be verified at the sae frequency and in the sae anner as a theroeter left in place, and the record of verification ust be readily available for inspection by the Regulator for a period of one year. Subsequent to the eter calibration, a tag or label ust be attached to the eter or end device that identifies the eter serial nuber, orifice plate size and the date of the calibration. A detailed report indicating the tests conducted on the eter during the calibration and the conditions as found and as left ust be either left with the eter or end device or readily available for inspection by the Regulator. If the detailed report is left with the eter, the foregoing requireent relating to the tag or label is considered to be et EFM Meter Calibrations For gas eters using digital (sart) transitters connected to a reote terinal unit (RTU) or electronic flow easureent (EFM) at non-delivery easureent points, the transitter ay be verified or calibrated every five years in accordance with the following conditions: 1. The digital transitter ust be of one of the following types: a. b. c. A transitter with a digital signal that is converted to an analog signal between 4 and 20 illiaperes, which is then sent to an RTU or EFM syste A transitter with a digital signal of one to five volts that is sent directly to an RTU or EFM syste A digital transitter connected to an RTU or EFM via other digital counication protocols, including Foundation Field Bus, Modbus, Profibus, Bristol Standard Asynchronous Protocol (BSAP), etc. This exeption applies only to digital transitters as described above and does not apply to analog transitters. Analog transitters ust be calibrated annually or to the frequency allowed by other exeption(s) in Section For existing digital transitters, if the last verification or calibration results do not necessitate further calibration in accordance with ite #1 in Section (i.e., the accuracy of all outputs were within ±0.25 per cent of full scale), then the next verification or calibration ay be in five years. New or newly installed digital transitters ust be verified or calibrated at the tie of installation and then ust be verified or calibrated after one year of operation. If the first-year verification or calibration results do not necessitate further calibration in accordance with ite #1 in Section (i.e., the accuracy of all outputs were within ±0.25 per cent of full scale) then the next verification or calibration ay be in five years. If calibration is required after the first year of operation, then the transitter ust be verified or calibrated in the subsequent year. August 1, 2017 Page 2-7

57 If calibration is required during any fifth year verification or calibration, then the transitter ust be verified or calibrated in the subsequent year. Transitters ust be installed, set up, and verified or calibrated in accordance with the procedures described in the ost current version of the Industry Measureent Group s Intelligent Transitter Coissioning and Verification industry recoended practice. Note that for new or newly installed digital transitters, the differential pressure transitter ust be zero verified and adjusted at static operating pressure during the first-year verification or calibration. If the verification or calibration confirs that the zero reading is within ±0.25 per cent, then the differential pressure zero does not need to be verified again for the reainder of the five-year ter. If the static operating pressure changes by ore than ±1750 kpa during the five years with no verification or calibration, then the differential pressure ust be zero verified and adjusted at the new static operating pressure within the first onth of the pressure change. When verifying or calibrating the analog output signal transitter, it is the analog output to the RTU or EFM syste that ust be copared to the reference value. Do not decouple the digital transitter fro the analog output to assess only the digital signal. The output signal fro the transitter ust atch the received value at the RTU/EFM syste. A tag ust be attached to the transitter indicating that this exception is being applied and the date of the next scheduled calibration. The records of the calibrations that qualify the eter for this exception ust be kept for at least five years and ade available to the Regulator on request. The procedure for calibration of an EFM syste ust be in accordance with the following: For digital transitters, as defined above, in Section (1), the differential pressure eleent ust be calibrated at: a. zero; b. 50% of calibrated full span; and c. calibrated full span. For analog transitters, the differential pressure eleent ust be calibrated at: a. zero; b. 50% of full span (ascending); c. full span (ascending); and d. either 80% and 20% or 75% and 25% of full span (descending). A zero check of the differential under noral operating pressure ust be done before and after the calibration. The static pressure eleent ust be calibrated at: August 1, 2017 Page 2-8

58 a. zero; b. 50% of full span; and c. full span If a teperature eleent is in place, the teperature probe ust be verified at two teperatures: a. the noral operating teperature; and b. one colder teperature or one warer teperature. The teperature probe ust calibrated or replaced if found not to be within ±1 C. Additionaly, if an EFM syste is used, the teperature probe and transitter ust be verified as a single unit, not decoupled and verified separately, and the indicated value of the transitter that is sent to the EFM should be copared to the reference value. Subsequent to the eter calibration, a tag or label ust be attached to the eter or end device that identifies the eter serial nuber, orifice plate size and the date of the calibration. A detailed report indicating the tests conducted on the eter or end device during the calibration and the conditions as found and as left ust be either left with the eter or end device or readily available for inspection by the Regulator. If the detailed report is left with the eter or end device, the foregoing requireent relating to the tag or label is considered to be et. If data fro the eter or end device are sent to another location(s) for flow calculations via DCS, SCADA, RTU, or other eans of counication, the reading of the calibration ust be verified at the receipt location of such data to ensure accurate data transission. 2.4 Liquid Meters Oil and other liquid production and disposition volues except gas well condensate under certain conditions, see Section 2.6, ust always be reported as liquid volues at 15 C and either equilibriu vapour pressure or kilopascals (kpa) absolute pressure Liquid Meter Proving The frequency and ethodology for calibrating the eter eleent are the sae as in Section 2.3. Meters used to easure hydrocarbons, water, and eulsions are subject to the following general proving requireents. However, there are additional specific requireents depending on the fluid types, as detailed in Sections 2.4 through The design and operation of the entire eter syste ust eet or exceed the eter anufacturer s specifications. The design and operation of the eter installation ust ensure that the conditions of fluid flow through the eter are within the anufacturer s recoended operating range. August 1, 2017 Page 2-9

59 The eter ust be installed upstrea of a snap acting control/dup valve, if present. The size of the prover taps and operation of the prover ust not restrict or alter the noral flow through the eter. Tank-type voluetric or gravietric provers ust be connected downstrea of the eter and downstrea of a snap acting control/dup valve, but other provers, such as ball provers, pipe provers, or aster eters, ay be connected either upstrea provided there is no gas breakout or downstrea of the eter before a snap acting control/dup valve. The location of the proving taps will dictate the proving ethod(s) that can be used. A new hydrocarbon eter ust be proved within the first calendar onth of operation or iediately following any repairs being conducted on the eter or any changes to the eter installation. Note that the resultant eter factor ust be applied back to the volues easured after the coenceent of operation, repair, or change. A new water eter ust be proved within the first 3 onths of operation or iediately following any repairs being conducted on the eter or any changes to the eter installation and no retroactive application of eter factor is required. The eters ust be proved according to the frequency in Table 2.1. Table 2.1. Meter proving frequency requireents and proving ethods Proving ethod Application Live oil/condens ate (eter at well/battery or test eter) Pipe/ copact/ sall Voluetric Proving volue Master vessel/tank Bench Calibrate frequenc Meter type prover eter prover proving transitter y PD/turbine A 1 A A A 2 N/A Annual 7 Vortex/Cori A 3 A 3 A 3 A 2, 3 N/A Annual 7 olis Differential N/A N/A N/A N/A A Annual producer Live oil/condens ate (gas plant inlet separator or cross border) Dead oil, stable HVP liquids, or delivery points 4 PD/turbine A 3 A A A 2 N/A Seiannual Vortex/Cori olis Differential producer A 3 A 3 A 3 A 2, 3 N/A Seiannual N/A N/A N/A N/A A Seiannual PD/turbine A A A 5 N/A N/A Monthly 6 Coriolis/ A A A 5 N/A N/A Monthly 6 ultrasonic Water PD/turbine A A A A 2 N/A Annual 7 August 1, 2017 Page 2-10

60 Proving ethod Application Meter type Pipe/ copact/ sall volue prover Master eter Voluetric vessel/tank prover Bench proving Calibrate transitter Proving frequenc y Vortex/Cori A 3 A 3 A 3 A 2, 3 NA Annual 7 olis/ agnetic/ ultrasonic Differential producer N/A N/A N/A N/A A Annual 1 A = acceptable ethod: N/A = not applicable. 2 See Sections 2.5.1, 2.6.2, and 2.8 for bench proving inforation. 3 For eter proving exeptions, see Section A delivery point ay be eulsion, crude oil, crude bituen, condensate, LPGs, ethane, or NGLs. 5 For live oil/condensate delivery point only. 6 If flow is less than /day, quarterly proving is acceptable. For other exeptions, see Section If flow 2.0 3/day, biennial proving is acceptable The eter ust be proved in line at noral operating conditions unless otherwise exept by the Regulator. If a aster eter is used for proving, it ust have an uncertainty rating equal to or better than the eter it is being used to prove. Each proving run ust consist of a representative volue of the norally etered fluid being directed into the prover or through the aster eter. 10. If a eter is proved after a period of regular operation, an as found proving run ust be perfored prior to conducting any repairs on the eter or replacing the eter. 11. An acceptable initial proving, also referred to as the first proving of a new or repaired eter, and all subsequent proving ust consist of the nuber of consecutive runs, each with a eter factor (MF) within the average of all applicable runs, as specified in Table 2.2. The resultant eter factor will be the average of all the applicable run eter factors. Proving procedures using ore than the specified nuber of runs are allowed, provided that the licensee can deonstrate that the alternative procedures provide a eter factor of equal or better accuracy. Table 2.2. Proving requireents for hydrocarbons, water, and eulsions Hydrocarbon eter type Initial prove: nuber of required consecutive runs Subsequent prove: nuber of required consecutive runs As found MF ± 0.5% of previous As found MF > ± 0.5% of previous Maxiu MF deviation allowed fro average of all applicable runs (%) Live oil field proving (see 2.5) Live oil shop proving (see 2.5) Dead oil, condensate at equilibriu, high vapour pressure liquids (see 2.5 & 2.6.1) Live condensate field proving (see 2.6.2) August 1, 2017 Page 2-11

61 Hydrocarbon eter type Live condensate shop proving (see 2.6.2) Initial prove: nuber of required consecutive runs Subsequent prove: nuber of required consecutive runs As found MF ± 0.5% of previous As found MF > ± 0.5% of previous Maxiu MF deviation allowed fro average of all applicable runs (%) Water field proving (see 2.8) Water shop proving (see 2.8) Whenever possible, the inspection of internal coponents should be done at the sae tie as the eter end device calibration, but to accoodate operational constraints the inspection ay be conducted at any tie, provided the frequency requireent is et. 13. A detailed report indicating the type of prover or aster eter used, the run details, and the calculations conducted during the proving ust be either left with the eter or readily available for inspection by the Regulator. If the detailed report is left with the eter, the requireent stated in point #14 relating to the tag or label is considered to be et. If the proving involved the use of a shrinkage factor instead of degassing, a copy of the saple analysis ust be attached to the proving report. 14. Subsequent to the eter proving, a tag or label ust be attached to the eter that identifies the eter serial nuber, the date of the proving, the type of prover or aster eter used, and the average eter factor. If the eter is connected to an electronic readout, it ay be possible to progra the eter factor into the software to allow the eter to indicate corrected volues. If the eter is connected to a anual readout, it is necessary to apply the eter factor to the observed eter readings to result in corrected volues. 15. LACT eters ay use the proving procedure in API-MPMS, Chapter 4: Proving Systes, instead of the procedure in Section Liquid Meter Proving Exeptions 1. If a eter used to easure fluids at flowline conditions is a type that uses no internal oving parts, e.g., orifice eter, vortex eter, cone eter, Coriolis eter or ultrasonic eter, it does not require proving, provided that all of the following conditions are et: a. The flow through the eter ust be continuous (not interittent) or the eter ust qualify for bench proving or be a Coriolis-type eter with sufficient structural integrity as deterined by internal diagnostics (see point b) and aintained within the rates specified by the eter anufacturer as providing accurate easureent. This exeption does not apply to aster eter proving (see Section 2.2 for requireent). If there is a dup valve as part of the Coriolis or bench-proved easureent syste, the dup valve ust be checked for leaks at the sae inspection or proving frequency set out in Table 2.1. August 1, 2017 Page 2-12

62 b. The design and operation of the entire eter syste ust be in accordance with the eter anufacturer s specifications. c. The eter eleent/end device(s) ust be calibrated at the frequencies specified in Section 2.3, using procedures specified in Section 2.3, by the API MPMS, the AGA, the device anufacturer, or other applicable industryaccepted procedures, whichever are ost appropriate and applicable. d. The internal coponents of the priary eleent ust be reoved fro service at the sae frequency as indicated in Table 2.1, inspected, replaced or repaired if found to be daaged, and then placed back in service, in accordance with procedures specified by the API, the AGA, other relevant standards organizations, other applicable industry-accepted procedures, or the device anufacturer s recoended procedures, whichever are ost applicable and appropriate. Internal etering diagnostics ay be used to deterine if the structural integrity of the priary eleent is within acceptable operating paraeters and checked at the sae required intervals as an internal inspection. Then internal inspection is not required until an alar or error is generated by the device or as recoended by the anufacturer. An initial baseline diagnostic profile ust be perfored and docuented during the coissioning process. The operator ust aintain docuentation on the diagnostic capability of the easureent syste and ake that available to the Regulator on request. e. If a eter is to be proved just like one with internal oving parts, no internal inspection is required. f. Whenever possible, the inspection of internal coponents should be done at the sae tie as the eter end device calibration, but to accoodate operational constraints the inspection ay be conducted at any tie, provided the frequency requireent is et. g. A tag or label ust be attached to the eter (or end device) that identifies the priary device serial nuber and the date of the calibration. h. A tag or label ust be attached to the eter (or end device) that identifies the priary device serial nuber, the date of the internal coponents inspection, and any other relevant details (e.g., the size of the orifice plate installed in the eter). i. A detailed report indicating the tests conducted on the eter during the calibration and the conditions as found and as left ust be either left with the eter (or end device) or readily available for inspection by the Regulator. (If the detailed report is left with the eter, the foregoing requireent relating to the tag or label is considered to be et.) j. A detailed record of the internal coponents inspection docuenting their condition as found and any repairs or changes ade to the ust be either left with the eter (or end device) or readily available for inspection by the Regulator. (If the detailed report is left with the eter or readily available, the foregoing requireent relating to the tag or label is considered to be et.) August 1, 2017 Page 2-13

63 2. If the volue of fluid easured by a delivery point or LACT eter does not exceed /d, the eter proving frequency ay be extended to quarterly. The tag attached to the eter ust clearly indicate that the eter easures /d and that the eter is on a quarterly proving frequency. The required proving frequency will revert back to onthly if the eter begins easuring volues > /d. 3. For delivery point or LACT eters, if the eter factor has been found to be within 0.5 per cent of the previous factor for the average of the previous factor for three consecutive onths, the eter proving frequency ay be extended to quarterly. The tag attached to the eter ust clearly indicate that the eter has been found to have consistent eter factors and is on a quarterly proving frequency. The required proving frequency will revert back to onthly whenever the eter factor deterined during a proving is found to not be within 0.5% of the previous factor. 4. For delivery point eters that easure trucked-in oil, eulsion, and condensate and that have no oving internal parts (e.g., Coriolis eter, ultrasonic eter, orifice eter, vortex eter, cone eter), the eter ay be proved seiannually if the current eter factor is within 0.5 per cent of the average of the previous three onthly factors. The tag attached to the eter ust clearly indicate that the eter has been found to have consistent eter factors and is on a seiannual proving frequency. The required proving frequency will revert back to onthly whenever the eter factor deterined during a proving is not within 0.5 percent of the average of the previous three factors. The eter ust requalify for the exeption before the proving frequency can again be extended to seiannual. The eter ust be proved following repairs to the eter changes to the etering installation. 5. If a eter that required internal inspection is used to easure liquid hydrocarbons and no eter bypass is installed, it is acceptable to defer a scheduled internal coponent inspection until the next tie the liquid eter run is shut down, provided that shutting down and depressuring the eter run to reove and inspect the internal coponents would be very disruptive to operations or present a safety concern and: a. previous internal coponent inspections have proven to be satisfactory; or b. the eter run is installed in a flow strea where the risk of internal coponent daage is low, for exaple. processed or filtered liquids; or c. the easureent syste at the facility provides sufficient assurance, through voluetric and/or statistical analysis, that internal coponent daage will be detected in a tiely anner. 2.5 Oil Meters Live oil and dead oil require distinctly different proving procedures: 1. Live oil - Live oil eters are typically those used to easure volues of oil or oil/water eulsion produced through test separators, but they also include eters used to easure well or group oil or oil/water eulsions that are delivered to other batteries or facilities by pipeline prior to the pressure being reduced to atospheric. If oil production is easured prior to being reduced to atospheric pressure, the proving procedures ust allow for the volue reduction that will occur when the gas in solution with the live oil is allowed to evolve upon pressure reduction. August 1, 2017 Page 2-14

64 2. Dead oil - Dead oil eters are typically those used for delivery point easureent of clean oil that has been degassed to atospheric pressure. These eters ay be found easuring oil being puped fro a battery into a pipeline or easuring oil being puped fro a truck into a pipeline terinal, battery, or other facility. No consideration for gas in solution is required when proving eters used to easure dead oil Additional Proving Requireents for Live Oil Meters To account for the shrinkage that will occur at the etering point due to the gas held in solution with live oil, the aount of shrinkage ust be deterined either by physically degassing the prover oil volues or by calculating the shrinkage based on an analysis of a saple of the live oil or a software siulation. Calculation of shrinkage volues is ost often used to itigate safety and environental concerns if the live oil volues are easured at high pressures or if the live oil contains hydrogen sulphide (H 2 S). Additional proving requireents for live oil are as follows: 1. If the proving procedure includes degassing the prover to physically reduce the pressure of the hydrocarbons to atospheric pressure: a. The prover ust be a tank-type voluetric or gravietric prover; b. Each proving run ust consist of a representative volue of hydrocarbons or hydrocarbons/water eulsion being directed through the eter and into the prover and the liquid volue then being reduced in pressure to atospheric pressure. The resultant volue deterined by the prover, after application of any required correction factors, is divided by the etered volue to deterine the eter factor; and c. The aount of tie required to degas the prover volue and arrive at a stable atospheric pressure in the prover will vary, depending on the initial fluid pressure and the fluid characteristics. 2. If the proving procedure uses a shrinkage factor, rather than degassing, to adjust the prover volue to atospheric conditions: a. A shrinkage factor representative of the fluid passing through the eter ust be deterined and used to adjust the eter volues to atospheric conditions. i. The shrinkage factor ay either be incorporated into the eter factor or be applied to etered volues after they are adjusted by the eter factor; and ii. The shrinkage factor ust be based upon analysis of a saple of the etered fluid taken at noral operating conditions (see Section 14.3); b. Whenever the operating conditions at the eter experience a change that could significantly affect the shrinkage factor, a new shrinkage factor ust be deterined based upon analysis of a saple of the etered fluid taken at the new operating conditions. Consideration ust be given to proving the eter at the new operating conditions to deterine if the eter factor has been affected; and August 1, 2017 Page 2-15

65 c. The tag attached to the eter ust indicate that a shrinkage factor was used instead of degassing the prover and whether the shrinkage factor was incorporated into the eter factor or will be applied separately. 3. When proving a test oil eter, a well that is representative of the battery s average well production characteristics ust be directed through the test separator for each of the four runs. If there are wells in the battery with production characteristics that vary significantly fro the average, consider deterining specific eter factors to be used for each of those wells. 4. In the scenario of a test oil eter, the eter factor ust include a correction factor to adjust the etered volue to 15 C unless the eter is teperature copensated. Although the actual fluid teperature ay vary with abient teperature, it is acceptable to assue that the teperature observed at the tie of proving is reasonably representative of the teperature experienced at the eter until the next proving. This requireent does not apply to eter technologies that do not require correction for teperature. 5. In the scenario of a live oil delivery point eter, the eter factor ust not include a correction factor for teperature. The eter ust either be teperature copensated or a fluid teperature ust be taken daily and the etered volue ust be corrected to 15 C. This requireent does not apply to eter technologies that do not require correction for teperature Oil Meter Exeptions 1. In situations where individual well production rates are so low that proving a test oil eter in accordance with the requireents listed in Section would require ore than one hour for an individual proving run, it is acceptable to odify the proving procedures. The following odifications, in order of the Regulator s preference, ay be used to reduce proving tie: a. Produce several wells through the test separator at one tie to increase the volue available for the proving runs. b. If the degassing procedure is being used, degas the first run only, and then use those data to calculate a shrinkage factor, which can be applied to subsequent runs conducted without degassing. c. Use the highest rate well for all proving runs. d. Conduct only three proving runs. The detailed proving report ust clearly indicate if any of the aforeentioned odifications was used to prove the eter. 2. A live oil eter ay be reoved fro service and proved in a eter shop: SK a. b. If the eter is used to easure test volues of non-heavy oil or eulsion and the average rate of flow of oil in the eulsion streas of all the wells tested through the eter is 2 3 /d and no well exceeds 4 3 /d of oil production in the eulsion strea; or If the eter is used to easure test volues of heavy oil or eulsion (density 920 kg/ 3 ) August 1, 2017 Page 2-16

66 AB BC a. b. If the eter is used to easure test volues of non-heavy oil or eulsion, the average rate of flow of oil/eulsion of all the wells tested through the eter is 2 3 /d and no well exceeds 4 3 /d of oil/eulsion production; or If the eter is used to easure test volues of heavy oil/euslion ( 920 kg/ 3 ) See Measureent Guidelines 3. Shop proving is to be conducted in accordance with the following in addition to the general procedure in Section 2.4 where applicable: a. The eter installation ust be inspected as follows, and corrective action ust be taken when required: i. The flow rate through the eter ust be observed to verify that it is within the anufacturer s recoended operating ranges; and ii. The dup valve ust not be leaking with no flow registered between dups. b. The shop proving ay be conducted with a voluetric or gravietric prover or with a aster eter, as follows: i. Water is typically used as the proving fluid, but varsol or soe other light hydrocarbon fluid ay be used for the proving; and ii. Corrections for the teperature and pressure of the proving fluid ust be ade, where applicable. If the gas held in solution with the fluid produced through the eter is of sufficient volue to significantly affect the fluid volue indicated by the eter, the shrinkage factor ust be deterined to correct for the effect of the gas in solution and provide that factor to the eter calibration shop so it ay be built into the eter factor. 2.6 Condensate Meters Condensate is subject to two different sets of easureent, accounting, and reporting rules. If condensate volues are easured and delivered at equilibriu vapour pressure, the volue ust be deterined and reported as a liquid volue at 15 C and equilibriu vapour pressure. If condensate volues are easured and delivered at flowline conditions, the volue ust be deterined at flowline pressure and corrected to 15 C, but the volue is reported as a gas equivalent volue at base conditions ( kpa absolute and 15 C) Proving Condensate Meters at Equilibriu Conditions Meters that easure condensate stored and delivered as a liquid at atospheric pressure or equilibriu pressure are typically delivery point eters and are therefore subject to the sae proving requireents and exeptions applicable to eters used for dead oil easureent (see Sections 2.4 and 2.5). August 1, 2017 Page 2-17

67 2.6.2 Proving Condensate Meters at Flowline Conditions When a eter that requires proving is used to easure condensate at flowline conditions, it ust be subjected to the proving requireents in Section Condensate Meter at Flowline Conditions Proving Exeptions A eter used to easure condensate at flowline conditions ay be reoved fro service and proved in a eter shop, in accordance with the following: 1. If the eter is used to easure condensate production on a continuous or interittent basis, the rate of flow through the eter ust be 2 3 /d or it ust be 3 3 /d with the gas equivalent volue of the daily condensate volue being 3.0% of the daily gas volue related to the condensate production. If the eter is used on a portable test unit, there is no volue liitation, but consideration should be given to proving the eter in line if significant condensate production is observed during the test. 2. The eter installation ust be inspected as follows, and corrective action ust be taken where required: a. The flow rate through the eter ust be observed to verify that it is within the anufacturer s recoended operating ranges; and b. The dup valve ust not be leaking with no flow registered between dups. 2.7 Other Liquid Hydrocarbon Meters Meters used to easure other high vapour pressure liquid hydrocarbons, such as propane, butane, pentanes plus, gas liquid/liquid petroleu gas (NGL/LPG), etc., are subject to the sae proving requireents and exeptions set out in Sections 2.4 and Water Meters If a eter is used to easure water production, injection, or disposal or injection of other water-based fluids, in addition to the requireents in Section 2.4: 1. The eter ust be installed and proved within the first three onths of operation. Note that the eter factor ay be assued to be until the first proving is conducted. 2. The proving ay be conducted in line at field operating conditions, or the eter ay be reoved fro service and proved in a eter shop using water as the test fluid. The proving ay be conducted using a voluetric prover, a gravietric prover, or a aster eter. If a eter is proved after a period of regular operation, an as found proving run ust be perfored prior to conducting any repairs on the eter or replacing the eter. An acceptable proving ust consist of four consecutive runs one of which ay be the as found run, each providing a eter factor within ±1.5% of the average of the four factors. The resultant eter factor is the average of the four applicable eter factors. Proving procedures using ore than four runs will be allowed, provided that the licensee can August 1, 2017 Page 2-18

68 deonstrate that the alternative procedures provide a eter factor of equal or better accuracy. Following the eter proving, a tag or label ust be attached to the eter that identifies the eter serial nuber, the date of the proving, and the average eter factor. If the eter is connected to an electronic readout, it ay be possible to progra the eter factor into the software to allow the eter to indicate corrected volues. If the eter is connected to a anual readout, it is necessary to apply the eter factor to the observed eter readings to result in corrected volues. A detailed report indicating the type of prover or aster eter used, the run details, and the calculations conducted during the proving ust be either left with the eter or readily available for inspection by the Regulator. If the detailed report is left with the eter, the foregoing requireent relating to the tag or label is considered to be et. 2.9 Product Analyzers If a product analyzer (water cut analyzer) is used to deterine water production, it ust be calibrated annually using procedures recoended by the anufacturer. Following the calibration, a tag or label ust be attached to the product analyzer that identifies the analyzer serial nuber and the date of the calibration. A detailed report indicating the calibration procedure used and the calibration details ust be either left with the analyzer or readily available for inspection by the Regulator. If the detailed report is left with the analyzer or readily available, the foregoing requireent relating to the tag or label is considered to be et Autoatic Tank Gauges Inventory Measureent Calibration If autoatic tank gauge devices are used to indicate fluid levels in tanks for onthly inventory easureent, they ust be calibrated on site within the first onth of operation and annually thereafter. The calibration procedures ust adhere to at least one of following list of procedure standards, as available and applicable: 1. The device anufacturer s recoended procedures; 2. Procedures described in the API Manual of Petroleu Measureent Standards; or 3. Other applicable procedures accepted by an appropriate industry technical standards association. A record of the calibration ust be ade available to the Regulator on request Delivery Point Measureent Calibration If autoatic tank gauge devices are used to indicate fluid levels in tanks for delivery point easureent of oil or oil/water eulsion, such as truck volue receipts at batteries/facilities or batch deliveries into a pipeline, they ust be calibrated on site within the first onth of operation and onthly thereafter. The calibration procedures ust be in accordance with the following list of procedure standards, as available and applicable: 1. The device anufacturer s recoended procedures; August 1, 2017 Page 2-19

69 2. Procedures described in the API Manual of Petroleu Measureent Standards; or 3. Other applicable procedures accepted by an appropriate industry technical standards association. A record of the calibration ust be ade available to the Regulator on request Delivery Point Calibration Frequency Exeption Where the accuracy of an autoatic tank gauge is found to be within 0.5% of full scale for three consecutive onths, the calibration frequency ay be extended fro onthly to quarterly. The record of calibration ust clearly indicate that the device has been found to deonstrate consistent accuracy and is on a quarterly calibration frequency. The records of the calibrations that qualify the device for this exeption ust be kept and ade available to the Regulator on request. The calibration frequency will revert back to onthly whenever the accuracy is found to not be within 0.5% of full scale Manual Tank Gauges for Oil Measureent Tank gauging refers to deterining levels in a tank and using those levels to calculate a volue increase or decrease in the tank. The level ay be deterined by using an autoatic tank gauge device or by anually deterining the level with a gauge tape. In either scenario, the volue of the tank relative to its height at any given point ust be deterined. This is referred to as the tank calibration, or tank strapping, and results in the creation of a tank gauge table Inventory Measureent Calibration If tank gauging is used only for onthly inventory easureent, specific tank calibration procedures are not required. It is acceptable to use gauge tables provided by the tank anufacturer or, if those are unavailable, generic gauge tables applicable to the tank size/type being used Delivery Point Measureent Calibration If tank gauging is used for delivery point easureent of oil or oil/water eulsion, such as truck volue receipts at batteries/facilities or batch deliveries into a pipeline, the specific tanks being used ust be calibrated on site within the first onth of operation and any tie the tank is daaged or altered. The calibration ust result in the creation of a gauge table for each tank, which ust then be used in conjunction with tank gauge readings to deterine volues. Calibration procedures ust be in accordance with applicable ethods stipulated in the API Manual of Petroleu Measureent Standards. A record of the calibration ust be ade available to the Regulator on request Weigh Scales Weigh scales used to easure oil/water eulsion and clean oil receipts at batteries, custo treating plants, pipeline terinals, and other facilities ust be approved and inspected prior to use, in accordance with Measureent Canada requireents. Weigh scales ust be tested for accuracy in accordance with the following schedule: 1. Monthly; August 1, 2017 Page 2-20

70 2. Iediately (by the end of the calendar onth) following any incident in which the scale ay have been daaged; 3. Iediately (by the end of the calendar onth) following any changes or odifications being ade to the scale; and 4. The coplete set of procedures set out by Measureent Canada for deterining weigh scale accuracy ust be used following any daage or odifications and at least annually. The onthly accuracy tests ay be done using the coplete set of procedures set out by Measureent Canada or, as a iniu, using the following abbreviated procedure: 1. Zero check: Deterine if the scale reads zero with no weight on the scale; 2. Add a 10 kg standard weight: Deterine if the scale reads 10 kg; 3. Reove the 10 kg standard weight: Deterine if the scale returns to zero; 4. Add a test load consisting of kg of standard weights or, alternatively, durable object(s) of known weight (iniu 5000 kg): Deterine if the scale reads the correct weight of the test load (acceptable error is ±0.2% of the test load); 5. Add a loaded truck, typical of the loads routinely handled by the scale: Note the total weight of the test load and truck; 6. Reove the test load and note the weight of the truck alone: Deterine if the scale reading correctly indicates the reoval of the test load (acceptable error is ±0.2% of the test load); and 7. Reove the truck: Deterine if the scale returns to zero with no weight on the scale. If as a result of the aforeentioned tests the weigh scale is found to not be accurate, it ust be calibrated and retested until found to be accurate and then sealed by a heavy-duty scale service copany. The service copany ust then send a written report to Measureent Canada docuenting the adjustent and/or repairs. A detailed record of the accuracy tests and any calibration activities ust be kept in close proxiity to the weigh scale, retained for at least one year, and ade available to the Regulator on request. This record ust include the following inforation: 1. Make, odel, serial nuber, and capacity of the weigh scale and any associated equipent; 2. Date of the accuracy test; 3. Details of the tests perfored and the results noted; and 4. Details regarding any alterations or calibration perfored on the weigh scale Weigh Scale Test Frequency Exeptions 1. If the volue of fluid easured by a weigh scale does not exceed /d, the onthly accuracy test frequency ay be extended to quarterly. The detailed record of the accuracy tests ust clearly indicate that the weigh scale easures /d and that the weigh scale is on a quarterly testing frequency. The required testing frequency will revert back to onthly if the weigh scale begins easuring volues in excess of /d. August 1, 2017 Page 2-21

71 2. If the weigh scale has been found to not require calibration adjustents for three consecutive onths, the onthly accuracy test frequency ay be extended to quarterly. The required accuracy test frequency will revert back to onthly whenever a quarterly accuracy test deterines that the weigh scale requires calibration adjustents. August 1, 2017 Page 2-22

72 3 Proration Factors, Allocation Factors, and Metering Difference 3.1 Proration Factors and Allocation Factors Proration is an accounting syste or procedure where the total actual onthly battery production is equitably distributed aong wells in the battery. This syste is applicable when the production of wells producing to a battery is coingled before separation and easureent, and each well s onthly production is initially estiated, based on well test data. In this type of syste, proration factors are used to correct estiated volues to actual volues. In the scenario of an oil proration battery (Figure 3.1), the oil, gas, and water produced by individual wells are not continuously easured. Instead, the wells are periodically tested to deterine the production rates of oil, gas, and water. The rates deterined during the well test are used to estiate the well s production for the tie period beginning with the well test and continuing until another test is conducted. The estiated onthly production so deterined for each well in the battery is totaled to arrive at the battery s total onthly estiated production. The total actual oil, gas, and water production volues for the battery are deterined, and for each fluid, the total actual volue is divided by the total estiated production to yield a proration factor. The proration factor is ultiplied by each well s estiated production to yield the well s actual production. Siilar accounting procedures are used for gas batteries subject to proration. Figure 3.1. Proration Factor Gas Proration Factor To Gas Gathering Syste Wells Test Water Oil & GIS Test rates are used to estiate onthly well production volues of each product. Estiated onthly battery production of each product is deterined by totalling all wells estiated production. Oil Battery Oil Sales Water Disposal Actual onthly battery production volue of each product is deterined by easured delivery and inventory changes. For each product, Proration Factor = Actual Battery Production / Estiated Battery Production For each product for each well, Actual Monthly Well Production = Estiated Monthly Well Production x Proration Factor = easureent point An allocation factor is a type of proration factor. It is used at facilities where only fluids received by truck are handled, such as custo treating facilities and third-party operated oil August 1, 2017 Page 3-1

73 terinals (Figure 3.2). The nae of the factor has been chosen to reflect the differences between batteries that receive fluids fro wells through flow lines where proration factors are used and facilities that receive fluids fro batteries only by truck where allocation factors are used. The purpose of an allocation factor is siilar to a proration factor, in that it is used to correct fluid receipt volues (considered estiates) to actual volues based on disposition easureents taken at the outlet of the facility and also considering inventory change. The allocation factor is deterined by dividing the onthly total actual volue for each fluid by the onthly total estiated volue for each fluid. The total estiated volue of each fluid received fro each source is ultiplied by the allocation factor for that fluid to yield the actual volue received fro that source. Figure 3.2 Allocation Factor Receipts Dispositions Oil Facility Oil Water Pipeline Injection/Disposal Estiated receipts is deterined by easuring each truckload of fluid. For each product, Allocation Factor = Actual Disposition / Estiated Receipt Actual disposition is deterined by easuring each product delivered and inventory changes. For each product, Actual Monthly Receipt fro Each Facility = Total Estiated Monthly Receipt fro Each Facility x Allocation Factor = easureent point The allocation factors discussed in this section are not to be confused with the process whereby products delivered out of a gas plant are allocated back to each well in the syste, based on individual well production volues and gas analyses. Measureent accuracy and uncertainty generally relate to rando errors and, as such, are not directly coparable to proration and allocation factors, which generally relate to bias errors. The Regulator Standards of Accuracy (Section 1) focus on specific easureent points, i.e., inlet or outlet, whereas proration and allocation factors relate to a coparison of inlet (or estiated production) to outlet easureent. It is iportant to note that the acceptable factor ranges, or targets, for different products ay be different due to the products being subjected to different levels of uncertainty. For exaple, the acceptable factor ranges for oil and water in a non-heavy oil proration battery are different, because while the estiated production volues of oil and water are deterined by the sae type of easureent, the outlet volues of the clean oil and water are not deterined by the sae type of easureent. When easureent equipent and procedures confor to all applicable standards, it is assued that the errors that occur in a series of easureents will be either plus or inus and will cancel each other out to soe degree. Where a bias error occurs in a series of easureents, there will be no plus/inus and all of the easureents are assued to be August 1, 2017 Page 3-2

74 in error by the sae aount and in the sae direction. Proration factors and allocation factors are therefore used to equitably correct all easureents for bias errors Acceptable Ranges for Proration and Allocation Factors If easureent and accounting procedures eet applicable requireents, any proration factor or allocation factor should be acceptable, since it is assued that the factor will correct for a bias error that has occurred. The Regulator requires proration factors and allocation factors to be onitored by operators and used as a warning flag to identify when the easureent syste at a facility is experiencing probles that require investigation. The Regulator dees the ranges of proration factors and allocation factors indicated in this section to be acceptable ranges. When a factor is found to exceed these liits, the licensee is required to investigate the cause of the factor being outside the acceptable range and docuent the results of the investigation and the actions taken to correct the situation. Action required by the operator regarding the investigations into the cause of the proration or allocation factor being outside the acceptable range ay include, but is not liited to: 1. Verifying S&W easureent practices. 2. Verifying related fluid easureent syste perforance. 3. Proving or calibration of easureent equipent. 4. Inspecting the priary eleent for eters with no internal oving parts. The Regulator acknowledges that at soe facilities, physical liitations or the econoics applicable to a particular situation ay prohibit the resolution of situations where factors are consistently in excess of the acceptable ranges indicated in this section. In this scenario, the licensee ust docuent the reason(s) that prohibit further action fro being taken. This inforation does not have to be routinely subitted to the Regulator, but ust be available to the Regulator on request for audit. If the cause of a factor being outside these acceptable ranges is deterined and the error can be quantified, the Regulator requires the reported voluetric data to be aended, thereby bringing the factor back into line. If the cause is deterined and action is taken to correct the situation for future onths, but the findings are not quantifiable for past onths, aendents are not required to be subitted Proration Factors Table 3.1 Facility Oil Gas Water Oil battery not producing heavy oil (Petrinex subtype: 322) August 1, 2017 Page 3-3

75 Facility Oil Gas Water Oil battery producing heavy oil priary production and waterflood operations (Petrinex subtypes: 342, 327 and, in AB, 322 for heavy oil outside the oil sands areas) Oil battery theral recovery operations (Petrinex subtypes: 344 and 345) Gas battery SW Saskatchewan and SE Alberta (Petrinex subtypes: 363 and 366) Gas battery outside SW Saskatchewan and outside SE Alberta (Petrinex subtypes: 364 and 367) Gas battery effluent easureent (Petrinex subtype: 362) no stated expectation due to generally low production volues no stated expectation due to the nature of theral production Allocation Factors Table 3.2 Facility Oil Gas Water Custo Treating facilities (Petrinex subtypes: 611 (SK & AB) and 612 (AB only)) Terinals (Petrinex subtypes 671, 672, 673, 674 and 675) Target Range Proration Factor Exeption SK The Regulator acknowledges that at soe ultiwell oil proration batteries where all wells in the battery produce 2 3 /d of oil or the ajority of the wells in the battery produce 2 3 /d of oil and no well produces > 6 3 /d of oil (based on average rates deterined seiannually) ay be prohibited in the resolution of situations where proration factors are consistently in excess of the acceptable ranges indicated in August 1, 2017 Page 3-4

76 AB BC Table 3.1. In this scenario, the licensee ust docuent the reason(s) that prohibit further actions fro being taken. This inforation does not have to be routinely subitted to the Regulator, but ust be available to the Regulator on request for audit. Licencees with low volue oil producing wells are still required to deterine proration factors as per Section 6 and subit the proration factors onthly to Petrinex. An exeption to the foregoing procedure is allowed for conventional oil proration batteries if, based on average rates deterined seiannually, all wells in the battery produce 2 3/d of oil, or the ajority of the wells in the battery produce 2 3/d of oil and no well produces > 6 3/d of oil. In this case, the licensee should still be aware of the proration factors and take corrective action where necessary, but need not expend a great deal of effort to conduct an investigation and docuent the result. An exeption to the foregoing procedure is allowed for conventional oil proration batteries if, based on average rates deterined seiannually, all wells in the battery produce 2 3/d of oil, or the ajority of the wells in the battery produce 2 3/d of oil and no well produces > 6 3/d of oil. In this case the licensee should still be aware of the proration factors and take corrective action where necessary, but need not expend a great deal of effort to conduct an investigation and docuent the result. 3.2 Metering Difference for Fluids other than Oil For voluetric reporting purposes, a etering difference is used to balance, on a onthly basis, any difference that occurs between the easured inlet/receipt volues and the easured outlet/disposition volues at a facility. Metering difference is generally acceptable as an accounting/reporting entity if a difference results fro two or ore easureents of the sae product. Metering differences occur because no two easureent devices provide the exact sae volue, due to the uncertainties associated with the devices. However, a ore significant cause of etering differences is that the product easured at the inlet to a facility is usually altered by the process within the facility, resulting in a different product or products being easured at the outlet of the facility. It should be noted that etering difference differs fro proration and allocation factors in that for facilities where those factors are used, the difference occurs between estiated and actual volues. Metering difference ay be used as follows: Injection/disposal facilities (Figure 3.3) - Receipts into these facilities are typically easured prior to being split up and delivered to individual wells, where each well s volue is etered prior to injection/disposal. August 1, 2017 Page 3-5

77 Figure 3.3 Fuel Flare Vent Receipts Injections/Dispositions Gas Plants, Gas Gathering Systes, Batteries or Fresh Water Sources Injection Syste Wells Metering Difference = Total Injections/Dispositions + Inventory Changes + Fuel + Flare + Vent Total Receipts (onthly reporting basis) = easureent point Batteries - Receipts into these facilities including production fro wells and receipts fro other facilities, are typically easured and the resultant product is easured prior to delivery to another facility. Proration factors continue to apply at proration batteries to reconcile estiated and actual production volues. Gathering systes (Figure 3.4) - Receipts into these facilities are typically easured prior to being subjected to soe sort of liited processing, which ay include liquids reoval and copression, and the resultant product(s) is easured prior to delivery to a sales point or to a gas plant for further processing. Gas plants (Figure 3.4) - Receipts into these facilities are typically easured prior to being processed into salable products, and those products are easured prior to delivery to a sales point. Figure 3.4 Receipts Dispositions Fuel Flare Vent Wells, Gas Gathering Systes or Batteries Gas Plant or Gas Gathering Syste Acid Gas Gas to Pipeline C2, C3,.. Products Condensate/Oil Metering Difference = Total Dispositions + Inventory Changes + Fuel + Flare + Vent - Total Receipts (onthly reporting basis) = easureent point August 1, 2017 Page 3-6

78 3.2.1 Acceptable Metering Difference Range If easureent and accounting procedures eet applicable requireents, etering differences up to ±5.0% of the total inlet/receipt volue are deeed to be acceptable. The Regulator requires the etering difference to be onitored by licensees and used as a warning flag to identify when the easureent syste at a facility is experiencing probles that require investigation. When a etering difference is found to be equal to or greater than 5.0%, the licensee is required to investigate the cause of the unacceptable etering difference and docuent the results of the investigation and the actions taken to correct the situation. The Regulator acknowledges that in soe facilities, physical liitations and/or the econoics applicable to a particular situation ay prohibit the resolution of situations where the etering difference is consistently in excess of the range indicated. In such scenarios, the licensee ust docuent the reason(s) that prohibit further action fro being taken. This inforation does not have to be routinely subitted to the Regulator, but ust be available to the Regulator on request for audit. If the cause of an unacceptable etering difference is deterined and the error can be quantified, the Regulator requires the incorrectly reported production data to be aended, thereby bringing the etering difference back into an acceptable range. If the cause is deterined and action is taken to correct the situation for future onths, but the findings are not quantifiable for past onths, aendents are not required to be subitted. August 1, 2017 Page 3-7

79

80 4 Gas Measureent This section presents the base requireents and exeptions for gas easureent fro any source in the upstrea and idstrea oil and gas industry that are used for deterining volues for reporting to the Regulator. 4.1 General Requireents All gas production and injection ust be continuously and accurately easured with a easureent device or deterined by engineering estiation unless: 1. exeption conditions described in this section are et; or 2. site-specific Regulator approval has been obtained A gas easureent syste ay deviate fro these base requireents if: the conditions in Section are et; or the deviation is provided for in Section 1: Standards of Accuracy. Monthly gas volues ust be reported in units of and rounded to 1 decial place. Standard or base conditions for use in calculating and reporting gas volues are kpa absolute and 15 C. Metering equipent ust be kept in good operating condition. 4.2 Gas Measureent and Accounting Requireents for Various Facility Subtypes This section outlines specific requireents for various facility subtypes. General easureent requireents, including eter design, operation, and aintenance requireents are detailed in other sections Oil Batteries All wells linked to the battery for reporting purposes ust be classified as oil wells. Subject to Section 5.5 exeption criteria, all wells in a ultiwell battery ust be subject to the sae type of easureent. Production fro gas batteries or other oil batteries ay not be connected to an oil proration battery upstrea of the oil battery group gas easureent point unless specific criteria are et and/or Regulator approval of an application is obtained. See Section 5: Site-specific Deviation fro Base Requireents, Measureent by Difference. Any oil facility, that is designed to consue fuel gas exceeding /d on a per site basis ust have fuel gas etered. If it is a part of another facility on the sae site, the overall site fuel gas used ust be easured. SK AB This requireent to easure the fuel gas exceeding /d applies. The /d easureent liit for fuel gas also applies to flare and vent gas streas, excluding heavy crude oil. At sites where fuel gas etering is required, up to /d ay be estiated. For any site that was constructed after May 7, 2007, and was designed for annual average fuel gas use exceeding /d or for any site where August 1, 2017 Page 4-1

81 BC annual average fuel gas use exceeds /d, the fuel gas ust be etered. At sites where fuel gas etering is required, up to /d ay be estiated. It is expected that the operator will eter the whole volue consued rather than just a specific strea for which the /d threshold has been exceeded. If there are ultiple reporting facilities on the sae site, the fuel use has to be separately easured and reported to each individual battery/facility. 5. If the site has ore than one Petrinex reporting facility, only the fuel for the overall site ust be etered; it ust then be allocated to and reported for each facility provided that the facilities have coon working interest ownership and there are no royalty trigger easureent points across the facilities. If there is no coon working interest ownership or there are royalty trigger easureent points across the facilities, then any fuel gas volues greater than /d crossing a reporting facility boundaries ust be etered. For sites with annual average flare/vent rates of /d, the flare/vent gas volue ay be estiated. For any site with an annual average flare/vent rate of > /d, the flare/vent gas ust be etered (see Figure 1.11). Sites requiring flare/vent gas etering ay estiate up to /d. These flare/vent thresholds do not apply to heavy oil and crude bituen batteries. See Section for heavy oil and bituen flaring and venting easureent requireents Single-well Battery (Petrinex facility subtypes: 311 and 325 in SK and 311 and 331 in AB) 1. Gas ust be separated fro oil, eulsion or water, when present, and etered or estiated separated fro the liquid volues as a single phase. Multiwell Group Battery (Petrinex facility subtypes: 321 and 326 in SK and 321 and 341 in AB) 1. Each well ust have its gas separated fro oil or eulsion and etered or estiated as a single phase, siilar to a single-well battery. 2. All separation and easureent equipent for the wells in the battery, including the tanks but excluding the wellheads, ust share a coon surface location. Proration Battery (Petrinex facility subtypes: 322 and 327, in SK and 322, 342, 344, and 345 in AB) 1. All well production is coingled prior to the total battery gas being separated fro oil or eulsion and etered or estiated as a single phase. 2. Individual onthly well gas production is estiated based on well tests and corrected to the actual onthly volue through the use of a proration factor. Crude Oil Multiwell Swab Battery (Petrinex facility subtypes: 314 and 316 in SK only) SK AB BC Monthly gas production fro individual crude oil swab wells ust be etered or estiated (where appropriate) and reported. Crude Oil Multiwell Swab Batteries are not authorized in Alberta. Not Applicable August 1, 2017 Page 4-2

82 4.2.2 Gas Batteries 1. All wells linked to the battery for reporting purposes ust be classified as gas wells. 2. Gas wells ay produce condensate or oil. 3. A ixture of easured and prorated wells (ixed easureent) within the sae battery ay be peritted if: a. Regulator exeption criteria specified in Section 5: Site-specific Deviation fro Base Requireents under Measureent by Difference are et, or; b. Regulator site-specific approval has been obtained, and the easured well(s) have been unlinked fro the ultiwell proration battery and linked to a separate battery facility to deliver gas into the proration battery. 4. Well(s) with no phase-separated easureent, including effluent wells, are not allowed to be linked to a Gas Multiwell Group Battery (facility subtype 361). 5. All gas and recobined liquids wells linked to a Gas Multiwell Battery (either facility subtypes 361, 362, 363, 364) ust be connected by pipeline to a coon point. 6. Gas production fro oil wells or batteries or fro other gas wells or batteries ust not be connected to a gas proration battery upstrea of the gas proration battery group easureent point unless Regulator exeption criteria in Section 5: Sitespecific Deviation fro Base Requireents under Measureent by Difference are et or Regulator site-specific approval is obtained. 7. Well status on Petrinex: SK AB BC Since gas royalties are based solely on onthly production volues, GAS PUMP and GAS FLOW are not used. Only GAS ACTIVE well fluid ode type is used. Gas wells that are designed to operate on an on/off cycle basis using plunger lifts, on/off controllers, anual on/off, etc., or pupjacks ust report well fluid ode type on Petrinex as GAS PUMP instead of GAS FLOW. Petrinex is under developent 8. Any gas facility, that is designed to consue fuel gas exceeding /d on a per site basis ust have fuel gas etered. If the facility is a part of another facility on the sae site, the overall site fuel gas used ust be etered. SK AB BC This requireent to easure the fuel gas exceeding /d applies. The /d easureent liit for fuel gas also applies to flare and vent gas streas, excluding heavy crude oil. At sites where fuel gas etering is required, up to /d ay be estiated. For any site that was constructed after May 7, 2007, and was designed for annual average fuel gas use exceeding /d or for any site where annual average fuel gas use exceeds /d, the fuel gas ust be etered. At sites where fuel gas etering is required, up to /d ay be estiated. BC OGC Measureent Guideline for Upstrea Oil and Gas Operations. This requireent to easure the fuel gas exceeding /d applies fro June and onwards. BC OGC Flaring and Venting Reduction Guideline August 1, 2017 Page 4-3

83 Section Metering Requireents and Guideline - any fuel gas added to acid gas to eet iniu heating value requireents or ground level abient air concentrations where the annual average flow rate exceeds /d. If the site has ore than one Petrinex reporting facility, only the fuel for the overall site ust be etered; it ust then be allocated to and reported for each facility provided that the facilities have coon working interest ownership and there are no royalty trigger easureent points across the facilities. If there is no coon working interest ownership or there are royalty trigger easureent points across the facilities, then any fuel gas volues greater than /d crossing a reporting facility boundaries ust be etered. 9. For sites with annual average flare/vent rates of /d, the flare/vent gas volue ay be estiated. For any site with an annual average flare/vent rate of > /d, the flare/vent gas ust be etered (see Figure 1.11). Sites requiring flare/vent gas etering ay estiate up to /d. These flare/vent thresholds do not apply to heavy oil and crude bituen batteries. See Section for heavy oil and bituen flaring and venting easureent requireents Single-well Battery (Petrinex subtype: 351) Gas ust be separated fro water and condensate or oil (if applicable) and continuously easured as a single phase. Condensate produced ust be reported as a liquid if it is disposed directly fro the battery without further processing. For wells that produce /d of total liquid (i.e., condensate and water) and that direct condensate and water production to lease tanks or to a single eulsion tank, operators ay use the disposition equals production reporting ethodology for reporting condensate and water production. This reporting ethodology eliinates the requireent to report onthly condensate and water tank inventories. If operators choose to use this reporting ethod, a. They ust account for existing tank inventories of condensate and water with the initial reporting and b. If the well status is changed to inactive after ipleentation, the condensate and water tank inventories ust be deposed of (i.e., tank eptied) in the reporting onth that the well status is changed. The disposition equals production ethod of reporting ay also be used for water reporting in the case where the separate condensate is recobined with the gas strea and sent to a gathering syste and the separated water is directed to a lease tank for disposition. Refer to Section for a further explanation of the disposition equals production reporting ethod. Condensate that is recobined with the gas production after separation and easureent ust be converted to a gas equivalent volue and added to the easured single-phase gas volue for reporting purposes. Condensate that is trucked fro the battery to a gas plant for further processing: August 1, 2017 Page 4-4

84 SK AB BC Must be reported as a liquid condensate volue. Must be converted to a gas equivalent volue and added to the easured single-phase gas volue for reporting purposes. Must be converted to a gas equivalent volue and added to the easured single-phase gas volue for reporting purposes. 5. Oil produced in conjunction with the gas ust be reported as oil at base conditions. The gas-in-solution (GIS) with the oil at the point of easureent ust be estiated and added to the gas production volue. See Section Multiwell Group Battery (Petrinex facility subtypes: 361 in SK and 361 and 365 in AB) Each well ust have its own separation and easureent equipent, siilar to a single-well battery. The wells in the group battery ay all be identical with regard to the handling of condensate and water, or there ay be a ixture of handling ethods. The rules for reporting condensate as a gas equivalent or as a liquid are the sae as those for single-well gas batteries (see Figure 4.1). The rules for using the disposition equals production reporting ethodology for condensate and water are the sae as those for single-well gas batteries. See Section The volues easured at each well separator ust be used to report the production, PROD, volue on Petrinex. There ust not be any proration fro any downstrea easureent point. Figure 4.1. Gas group battery delivering to a gathering syste Gas Group Battery (GG) Gas Gathering Systes (GS) Flare Report as DISP at GS Gas Well M M M Report as GEV PROD at well and GAS REC at GS Fuel Gas to sale, gas plant, or other facilties M Gas Well M M M Inlet Sep. = Facility Receipt/Disposition Meter Condensate Storage M Report as Pentane Plus (C5-MX) DISP at GS Gas Well Produced condensate trucked to Sales Report as Liquid COND PROD at well Water Storage M Disposition to IF M = Facility Receipt/Disposition Meter = easureent point There is no group easureent point requireent for fluids fro the gas group wells, but the wells ust deliver to a coon facility, norally a gas gathering syste, with the etering difference reported at the gas gathering syste. Hydrocarbon liquids and/or water ay be tanked and disposed of by truck and reported as liquid DISP. Recobined August 1, 2017 Page 4-5

85 hydrocarbon liquids reported as gas equivalent volue and water reported as liquid water ust be sent to the sae coon facility as the gas. Multiple gas groups can deliver to the sae gas gathering syste. If the gas gathering syste further disposes of the fluids, siilar to Figure 4.1, each fluid type (gas, hydrocarbon liquids, water) disposition ust be easured and reported. The gas gathering syste will also report a etering difference. See Appendix 9 for scheatics of the following scenarios of grouped wells: Scenario 1 1 operator with 1 reporting entity (1 gas group) Scenario 2 1 to 4 operators/equity partners with 4 reporting entities (4 single-well batteries) with licensed copressor facility on one well Scenario 3 1 or 2 operators with 2 reporting entities (1 single-well batteries and 1 gas group) Scenario 4 1 or 2 operators with 2 reporting entities (gas groups) Scenario 5 1 or 2 operators with 2 reporting entities (gas groups) with licensed copressor on one well Multiwell Effluent Measureent Battery (Petrinex facility subtype: 362) The definition of and the requireents for this facility subtype 362 is found in Section 7.4. Where delivery point easureent is required at the group easureent point, the cobined (group) production of all wells in the effluent easureent battery ust have three-phase separation and be easured as single-phase coponents. Where delivery point easureent is not required at the group easureent point, the group production ay be easured using two phase separation with three phase easureent. This eans that a two phase separator with an online product analyzer on the liquid leg of the separator ay be used provided that: a. The easureent syste design eets the requireents of Section 14, Figure 14.1 b. The condensate and water is recobined and delivered to a gas gathering syste or gas plant for further processing. The resulting total actual battery gas volue (including gas equivalent volue [GEV] of condensate) and total actual battery water volue ust be prorated back to the wells to deterine each well s actual gas and water production. a. If condensate is trucked out of the group separation and easureent point without further processing to a sales point, condensate production ust be reported at the wellhead based on the condensate-gas ratio (CGR) fro the well test. b. If liquid condensate is trucked to a gas plant for further processing the condensate: SK AB Must be reported as a liquid condensate volue. Must be reported as a gas equivalent volue (GEV). August 1, 2017 Page 4-6

86 BC Must be reported as a gas equivalent volue (GEV) Multiwell Proration Battery (Petrinex facility subtypes: 363 and 364 in SK and 363, 364, 366, and 367 in AB) The definition of and the requireents for facility subtypes 363, 364, 366, and 367 are found in Section 7. See Section 7 for requireents. Gas Gathering Syste (Petrinex facility subtypes: 621 and 622) A reporting entity consisting of pipelines that ove products (priarily gas) fro one facility to another. The facility ay also include copressor stations, line heaters, and dehydration equipent located on the syste but not associated with any battery, injection facility, gas plant, or other facilities. Inlet easureent usually consists of the battery or facility group easureent point. Outlet easureent usually consists of the gas plant inlet easureent. See Section for water reporting requireents Gas Plant (Petrinex facility subtypes: 401, 402, 403, 404, 405, 406) For gas plant facility subtypes definitions see SK Directive PNG074: Voluetric, Valuation, and Infrastructure Reporting in Petrinex (forerly known as Directive R01) AB Directive 011: BC Petrinex is under developent A syste or arrangeent of equipent used for receiving, easuring, and processing raw gas. Processing refers to the extraction of inert coponents, natural gas liquids, and water fro the raw inlet gas through the use of dehydration, regenerative sweetening, and hydrocarbon liquids recovery processes. Does not include arrangeent of equipent or facilities that recover less than /d of hydrocarbon liquids without using a liquid extraction process (e.g., refrigeration, Jewel Thopson, or desiccant). Does not include an arrangeent of equipent or facilities that reove sall aounts of sulphur (<0.1 tonnes per day [t/d]) through the use of non-regenerative scavernging cheicals and dessicants. Each plant inlet strea ust have inlet separation and continuous easureent, used to report volue on Petrinex, for all liquids and gas before coingling with other streas and ust be for the plant receipt fro upstrea facilities and for plant balance, unless all streas entering a gas plant are on the sae gas gathering syste and are dry (the absence of free liquids). In this case, the gas plant inlet easureent ay consist of the gas gathering syste outlet easureent or battery group easureent. Measureent of all gas dispositions out of the gas plant, such as sales, lease fuel for other facilities, flare and vent gas, acid gas disposition, and any volues used at the gas plant, is required unless otherwise exept by the Regulator. Monthly liquid inventory change ust be accounted for and reported to Petrinex. (See Figure 4.4.) August 1, 2017 Page 4-7

87 Figure 4.4. Typical gas plant easureent and reporting points Receipts Dispositions Fuel Flare Vent Acid Gas Wells, Gas Gathering Systes or Batteries Gas Plant Gas to Pipeline C2, C3, C4...Products Pentane Plus Metering Difference = Total Dispositions + Inventory Changes + Fuel + Flare +Vent - Total Receipts (onthly reporting basis) Except for theral in situ schees, facilities that use either regenerative sweetening processes or hydrocarbon liquid recovery processes ust be reported as gas plants if they produce > /d of hydrocarbon liquid.delineation for an Oil Battery Delivering To or Receiving Fro a Gas Plant on Sae Site Figure 4.5. Oil battery delivering to or receiving fro a gas plant = easureent Gas Gathering Systes/ Battery Gas Plant Raw Gas Flare Acid Gas Acid Gas Flare Dilution Gas Acid Gas Injection or Sulphur Recovery Sales Gas Flare Sales Gas Inlet Separator Sweetening Dehydration Refridgeration Plant Fuel Field Fuel Plant Flare Dehydration Fro Flare Header FWKO Water Storage Off Gas to Flare NGL Storage L Inlet Separator Treater Oil Storage Oil Sales to M Pipeline To Flare Header Stabilizer Condensate/ C5+ Storage Water Storage Proration Oil Battery Water Storage M = Measureent Point August 1, 2017 Page 4-8

88 Oil battery gas and water sent to a gas plant for further processing or disposition and gas for flaring ust be easured and reported as disposition fro the oil battery to the gas plant. The gas plant will report the receipts, total flare, and dispositions. Gas plant condensate, C 5+, and/or NGL sent to an oil battery ust be easured and reported as disposition to the oil battery. SK This is not a royalty trigger point but still requires delivery point easureent. AB BC This is a royalty trigger point requiring delivery point easureent. This is a royalty trigger point requiring delivery point easureent Gas Fractionation Plant (Petrinex facility subtype: 407) In addition to the requireents in Section 4.2.4, condensate delivered to a gas fractionation plant ust be easured and reported as a liquid receipt in cubic etres Injection or Disposal Facility (Petrinex facility subtypes: 501, 503, 504, 505, 506, 507, 510, 511, 512, 514, 516, 517, 518, 519 in SK and 501, 502, 503, 504, 505, 506, 507, 508, and 509 in AB) Gas ust be continuously etered as a single phase. For acid gas injection requireents, see Section 11 - Acid Gas and Sulphur Measureent. For strea injection see Section 12 Heavy Oil Measureent (Section 12.3 and 12.4) Meter Station (Petrinex facility subtypes: 631, 632, 633, 634, 640 in SK and 631, 632, 633, 634, 637, 638, 639, and 640 in AB) Where gas eters are used to deterine wellhead production, allocation pipeline disposition the provisions of this section applies. Gas ust be continuously etered as a single phase Other Facilities (Petrinex facility subtypes: 204, 207, 208, 210, 211, 212, 213, 214, 371, 381, 671, 673, 674, 675, 676, 701, 702, 703, 904, 905, 906, 907 in SK and 204, 206, 207, 208, 209, 371, 381, 601, 611, 612, 651, 671, 672, 673, 675, 701, 702, 801, 901, 902, 903 in AB) Provisions of this section apply where these facilities are required to easure and report gas. Gas ust be easured as a single phase Base Requireents for Gas Measureent Design and Installation of Gas Measureent Devices The design and installation of easureent equipent ust be in accordance with the following: August 1, 2017 Page 4-9

89 General Design and Installation Requireents Gas ust be pressure and teperature corrected and reported to base conditions of kpa and 15 C. Therefore, pressure and teperature easureent devices ust be installed in accordance with Section and In soe cases, such as the eters listed below, anufacture s recoended installation is allowed. In these cases, the Operator ust provide docuentation to the Regulator (if requested) that shows that the eter and the installation eets the uncertainty requireents stipulated in Section 1. Orifice Meters If an orifice eter is used to easure gas, it ust be designed and installed according to the applicable AGA Report #3: Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids (AGA3) listed in Table 4.1. Table 4.1. Orifice eters design requireent (see detailed explanation in this section) Meter run date of anufacture Applicable AGA3 (API MPMS 14.3, Part 2) version Before February 2003 After January 2003 (except for sales/delivery point eters easuring sales specification processed gas) All sales/delivery point eters easuring sales specification processed gas anufactured after January 2003 AGA or earlier eter run with upstrea and/or downstrea ID arking ay be reused or relocated for its designed application except to replace a eter where AGA spec is required. Non-AGA eter run or run not arked with upstrea or downstrea ID grandfathered for the existing voluetric throughput application, if relocated, it ust be refurbished to AGA3 (1985) or later specification but cannot be used for sales/delivery point easureent. February 1991 or April 2000, or later April 2000 or later When a eter such as a gas plant outlet eter is used to check sales/delivery point easureent and is not norally used to report volues to the Regulator, it does not require AGA3 April 2000 specification. However, Operators are advised that when another gas source ties in to the sales pipeline between the check eter and the sales/delivery point eter, the check eter could becoe a sales or delivery point eter, and be subject to the requireents of that type of eter as illustrated in Figures 4.6 and 4.7. August 1, 2017 Page 4-10

90 Figure 4.6 Gas Plant Inlet Plant and Upstrea Meter - runs installed after January Miniu AGA Spec. Required Existing Gas Plant FE Sales Gas Meter - run installed after January AGA Spec. Required FE Plant Outlet Meter - run installed after January Miniu AGA Spec. Required Figure 4.7 Gas Plant Inlet Plant and Upstrea Meter - runs installed after January Miniu AGA Spec. Required Existing Gas Plant FE FE New Gas Source - eter run installed after January AGA Spec. Required Sales Gas Meter - run installed after January AGA Spec. Required FE Plant Outlet Meter - run installed after January AGA Spec. Required A peranently arked plate with the following inforation ust be attached to each eter run and aintained in readable condition (not painted over or covered with insulation, etc.) for inspection: a. Manufacturer s nae b. Serial nuber c. Date of anufacture d. Average upstrea inside diaeter (ID) of the eter run at 25.4 upstrea of the orifice plate in illietres to one decial place (or to three decial places if indicated in inches). August 1, 2017 Page 4-11

91 e. AGA3 version/year (for new runs only after January 31, 2005) and/or AGA3 configuration for runs installed after January 2003 and not using the April 2000 specification. The orifice plate ust be peranently arked with the plate bore in illietres to two decial places or to three decial places if indicated in inches, preferably within 6 of the outside edge of the plate, to avoid interfering with noral flow if the arking creates a dent or protrusion on the plate surface. Teperature easureent ust be installed according to the applicable AGA3 specifications and the teperature ust be deterined in accordance with Turbine and Vortex Meters Turbine or vortex eters, used to easure gas ust be designed and installed according to the provisions of the 1985 or later editions of the AGA Report #7: Measureent of Gas by Turbine Meters (AGA7) or the anufacturer s recoendation and ust eet uncertainty requireents. Teperature easureent is to be installed according to AGA7, i.e., between one and five pipe diaeter downstrea of the eter or the eter anufacturer s recoendation and the teperature as per Section The installation ust include instruentation that allows for continuous pressure, teperature, and copressibility corrections either on site, e.g., electronic correctors, EFM systes or at a later date, e.g., pressure and teperature charts. Rotary Meters Rotary etering systes ust be designed and installed according to the provisions of the 1992 or later edition of the ANSI B109.3: Rotary Type Gas Displaceent Meters or the anufacturer s recoendation and ust eet the uncertainty requireents. Diaphrag Meters Diaphrag eters ust be designed and installed according to the provisions of the 1992 or later edition of the ANSI B109.1: Diaphrag Type Gas Displaceent Meters (up to 500 cubic feet/hour capacity), or ANSI B109.2: Diaphrag Type Gas Displaceent Meters (over 500 cubic feet/hour capacity), and/or the anufacturer s recoendation and ust eet the uncertainty requireents. Venturi or Flow Nozzle Meters Venturi or flow nozzle type of eters ust be installed according to the provisions of the 1991 or later edition of the ISO Standard 5167: Measureent of fluid flow by eans of orifice plates, nozzles and venturi tubes inserted in circular cross-section conduits running full (ISO 5167), other recognized International Standards or the eter anufacturer s recoendation and ust eet the uncertainty requireents. Ultrasonic Meters Ultrasonic eters ust be designed and installed according to the provisions of the 1998 or later editions of AGA Report No. 9: Measureent of Gas by Multipath Ultrasonic Meters (AGA9), applicable standard of an appropriate industry technical standards association or the eter anufacturer s recoendation and ust eet the uncertanity requireents. August 1, 2017 Page 4-12

92 Coriolis Meters Coriolis ass eters ust be designed and installed according to the provisions of the latest edition of AGA Report No. 11: Measureent of Natural Gas by Coriolis Meter, applicable standard of an appropriate industry technical standards association or the eter anufacturer s recoendation and ust eet the uncertainty requireents. Operators have two options for correcting to gas volues at base conditions. Both of these options require an accurate gas coposition deterined in accordance with Section 8 of this Directive. 1. The first option is to easure the ass of the gas. The Operator can correct to base conditions by dividing the ass by the density at base conditions to get volue at base conditions. 2. The second option is to have the eter deterine volue at flowing conditions, and correct the volue to base conditions. In ost cases the coriolis eter will not provide an accurate flowing density, so it is required that the pressure and teperature be accurately easured to deterine volue at flowing conditions, then the volue can be corrected to base conditions. Theral Mass Meters Theral Mass eters ust be designed and installed to applicable standard of an appropriate industry technical standards association or eter anufacturer s recoendation and ust eet the uncertainty requireents. Theral Mass eters should only be used if: a. The coposition does not change; or b. The effect of coposition change on the volue is within the uncertainty requireents for that applicable; or c. The coposition can be deterined and recorded for flow calculation. These eters are not recoended for use at gas plant flare stacks unless the above criteria can be et. Other Meters If eters other than those listed, for exaple cones or wedge eters, et cetera are used to easure gas, they ust be installed according to applicable standard of an appropriate industry technical standards association, accepted standards or the eter anufacturer s recoendation and ust eet the uncertainty requireents. Electronic Flow Measureent Systes (EFM) See Section Sensing Line Installation for Differential eters This section applies to differential eters such as orifice, cone or venturi eters. Note that there are exeptions fro these requireents detailed in the next section. 1. Accounting eters using differential pressure sensing devices ust be equipped with full port valves at the etering tap on the sensing lines. The valves ust be the sae size as the sensing lines (12.7 [1/2 inch] iniu for eter runs 102 [4 inches] in diaeter or larger, and 9.5 [3.8 inch] iniu for eter runs August 1, 2017 Page 4-13

93 less than 102 ). All etering design and installation ust ensure that the sensing line diaeter does not change fro the sensing tap valve to the anifold for deliver point, group point, and sales point easureent. Sharing of etering taps by ultiple differential pressure devices is not allowed. A separate set of taps and valve anifolds ust be used for each device. Equipent and sensing lines ust be suitably winterized to prevent the fro freezing. Sensing lines ust be self-draining towards the sensing taps to prevent liquid fro being trapped in the line if they do not eet the exeption criteria for changes in sensing line diaeter specified in Section Sensing lines should not exceed 1 in length and should have a slope of 25.4 per 300 fro the transitter to the changer Exeptions fro Requireents for Sensing Line Installation for Differential eters SK AB BC Grandfathering of existing differential pressure-sensing tap valves for installation before this Directive coes into force is granted without application unless any of the following situations exist: Grandfathering of existing differential pressure-sensing tap valves for installation before May 7, 2007 is granted without application unless any of the following situations exist: No Grandfathering of existing differential pressure-sensing lines for installations before June 1, The etering device is being upgraded, refurbished, and coissioned within a new application or relocated; The etering device does not eet the single point uncertainty liit, as detailed in Section 1: Standards of Accuracy; The etering point is subject to noticeable pulsation effects, such as physical vibration or audible flow noise, or is downstrea of a reciprocal copressor on the sae site; or The etering point is at a delivery point, group point, sales point, or custody transfer point. Grandfathering of changes in sensing line diaeter fro the sensing tap to the anifold, such as drip pots, installed before ipleentation of this Directive, is granted without application unless: 1. The etering device does not eet the single point uncertainty liit, as detailed in Section 1: Standards of Accuracy; 2. The etering point is subject to noticeable pulsation effects, such as physical vibration or audible flow noise, or is downstrea of a reciprocal copressor on the sae site; 3. The etering point is at a delivery point, group point, sales point, or custody transfer point; or August 1, 2017 Page 4-14

94 SK AB BC 4. The fuel easureent point has a clean, dry fuel source at a facility, such as a gas plant. If the current etering installation does not eet the grandfathering requireent, operators ust ake any necessary changes required to bring the installation into copliance with this Section within one year of when this Directive coes into force. If the current etering installation does not eet the grandfathering requireent, operators ust ake any necessary changes required to bring the installation into copliance with this Section within one year of February 2, Grandfather is not applicable Teperature For all eters the flowing gas teperature ust be easured and recorded according to Table 4.2. Table 4.2. Teperature reading frequency table for gas easureent Miniu teperature reading frequency Criteria or events Continuous Sales/delivery points and/or EFM devices Daily > /d Weekly /d Daily a. Production (proration) volue testing, or b. Nonroutine or eergency flaring and venting Note that the teperature-easuring eleent ust be installed on the eter run if present or near the eter such that it will be sensing the flowing gas strea teperature. Using the surface teperature of the piping or use a therowell location where there is norally no flow is not acceptable. A eter equipped with a teperature copensation device is considered to have continuous teperature easureent Pressure For all eters, pressure easureent ust be located such that applicable standard of an appropriate industry technical standards association is et, and the pressure reading reflects that pressure at the eter. Where the pressure at the eter ay drop below atospheric pressure, absolute pressure easureent is required Volue Calculations The gas volue calculations coply if the following requireents are et: 1. If an orifice eter is used to easure gas, the licensee ust use the 1985 or later editions of the AGA3 to calculate the gas volues. 2. If a positive displaceent eter or a linear type of eter, such as a turbine, ultrasonic, or vortex eter, is used to easure gas, volues ust be calculated August 1, 2017 Page 4-15

95 according to the provisions of the 1985 or later editions of the AGA7. Corrections for static pressure, teperature, and copressibility are required. 3. If a venturi or flow nozzle type of eter is used to easure gas, volues ust be calculated according to the provisions of the 1991 or later edition of the ISO 5167 or the eter anufacturer s recoended calculation procedures. 4. If a Coriolis ass eter is used to easure gas, volues ust be calculated fro the easured ass flow and the base density derived fro a representative gas saple analysis, including corrections for copressibility because the flowing density easured by the Coriolis ass eter is of insufficient accuracy in a gas application and ust not be used to copute volues. 5. If eter types other than those listed in the previous points, such as v-cones or wedge eters, are used to easure gas, volues ust be calculated according to the applicable standard of an appropriate industry technical standards association or the eter anufacturer s recoendation. 6. If condensate production fro a gas well is required to be reported as a gas equivalent volue, the calculation of the gas equivalent factor ust be perfored in accordance with the ethodologies outlined in Section 8.3. The following are the general requireents: a. The gas equivalent volue (GEV) is to be deterined based on the latest condensate saple analysis. b. The gas equivalent volue can be deterined using the volue fractions, ole fractions, or ass fractions of the condensate analysis. c. The gas equivalent volue can be deterined using all of the individual coponents in the condensate analysis, or the C 5 and/or heavier coponents in the saple can be grouped as C 5+, C 6+, C 7+ or other heavier coponent groups. If the heavier coponents are grouped, the gas equivalent factor for the grouped coponents ust be calculated using the olecular weight and/or relative density of the grouped coponents. 7. For existing in-service orifice eter runs that are installed before February 2003 and are not designed to the AGA or earlier specifications at the tie of anufacture or not arked with upstrea or downstrea ID, noinal pipe ID can be used for flow calculations Copressibility Factors Used in Gas Volue Calculations Produced or injected gas volue easureents ust be corrected for pressure, teperature, gas coposition, and the copressibility of the natural gas. Copressibility factor of 1.0 can be applied when the pressure is below 700 kpag. The AGA8 1 (1992 or later) or Redlich-Kwong with Wichert-Aziz sour gas corrections ethod should be used for the calculation of the copressibility factors. However, other ethods can also be used, provided that the licensee docuents the reason for their use. Other ethods that could be used are 1. Pitzer et al. with Wichert-Aziz sour gas corrections 1 See Section 4.6: References for coplete bibliographical details for these citations. August 1, 2017 Page 4-16

96 2. Dranchuk, Purvis, Robinson with Wichert-Aziz sour gas corrections (Standing and Katz) 3. Dranchuk, Abou-Kassa with Wichert-Aziz sour gas corrections (Starling) 4. Hall, Yarborough with Wichert-Aziz sour gas corrections The Regulator will also accept the use of ethods other than those listed. If others are used, a suitable reference and coparison to the AGA8 (1992) ethod or to experiental results and the justification for use ust be docuented and provided to the Regulator for inspection on request. The AGA8 publication includes several approaches for estiating the properties of natural gas for use in the AGA8 calculation. The full copositional analysis (Detail) ethod ust be used rather than the less accurate partial coposition ethod. If paper charts are used, the copressibility factor should be calculated at least once for each gas chart cycle. Flow coputers and other EFM systes used for gas easureent ust calculate and update the copressibility or super copressibility factor at a iniu of once every five inutes, whenever the gas coposition is updated, and whenever the average pressure or teperature changes by ore than ±0.5 per cent fro the previous average 5-inute value used for calculation Physical Properties of Natural Gas Coponents The Regulator adopts the physical properties contained in the ost recent edition of the Gas Processors Suppliers Association (GPSA) SI Engineering Data Book 1 or the Gas Processors Association (GPA) publication, whichever is the ost current. The licensee should ensure that it is using the up-to-date list when buying a new easureent equipent. For standards, such as AGA8, that have ibedded physical constants different in value fro those in GPA 2145 or GPSA SI Engineering Data Book 1, changes to such standards are not required unless they are ade by the standard association. Production Data Verification and Audit Trail and Voluetric Data Aendents General The field data, records, and any calculations or estiations including EFM relating to Regulator-required production data subitted to Petrinex ust be kept for inspection on request. The reported data verification and audit trails ust be in accordance with the following: 1. When a bypass around a eter is opened or when, for any reason, gas does not reach the eter or the recording device, a reasonable estiate of the unetered volue ust be deterined, the ethod used to deterine the estiate ust be docuented, and a record of the event ust be ade. 2. A record ust be aintained that identifies the gas strea being etered, the easureent devices, and all easureents, inputs, ties, and events related to the deterination of gas volues. (See Section 4.3.1: Operations for ore detail on orifice chart recorders.) If EFM is used, the required data ust be collected and retained according to Section Test records: Any docuentation produced in the testing or operation of etering equipent that affects easured volues. This includes the record containing August 1, 2017 Page 4-17

97 volue verification and calibration easureents for all secondary and tertiary eleents. 4. When a gas etering error is discovered, the licensee of the facility ust iediately correct the cause of the error and subit aended onthly production reports to Petrinex to correct all affected gas volues. 5. All flared and vented gas: SK AB BC Must be reported as described in Directive R01 Voluetric, Valuation and Infrastructure Reporting Must be reported as described in Directive 007: Voluetric and Infrastructure Requireents. Must be reported as described in the ost recent version of BC Oil and Gas Coission Flaring and Venting Reduction Guideline 6. Incinerated gas ust be reported as flared gas if an incinerator is used in place of a flare stack, except for acid gas streas at a gas plant that are incinerated as part of noral operations where the incinerated acid gas is reported as shrinkage, not as flared. 7. Whenever possible, the licensee ust report gas as fuel, flared, or vented as occurring at the location where the fuel use, flaring, or venting took place. This will allow industry and Regulator staff to atch flaring or venting that is observed in the field with that reported. 8. When the fuel usage, flaring, or venting location is within a gas gathering syste but is not at a licensed entity: a. it ust be reported as an activity associated with the closest licensed facility (e.g., copressor) within the gas gathering syste; or b. if there is no applicable licensed facility within the gas gathering syste, it ust be reported as an activity associated with the gas gathering syste itself. 9. Licensees ust not prorate or allocate flared and vented volues that occur at a facility to other upstrea facilities and/or well locations. 10. Dilution gas, purge gas, or gas used to aintain a iniu heating value of the flared or incinerated gas ust be reported as fuel. The reported total flare volue ust exclude any of these fuel volues. 11. Production hours for gas wells designed to operate on an on/off cycle basis, such as interittent tiers, pup-off controls, plunger lifts, anual on/off, or pupjacks, that are operating norally and as designed on repeated cycles and where part of the operation involves shutdown of pup equipent and/or shut-in as part of the repeated cycles are to be considered on production even when the wells are not flowing. At least one on/off cycle ust be copleted within a reporting period. Physical well shut-ins that are not part of a repeated cycle and eergency shutdown (ESDs) are considered down tie. The operation personnel have to ake a decision based on the operating environent in other situations where the wells are not shut in but ay or ay not have production. August 1, 2017 Page 4-18

98 12. All gas usage, such as for instruentation, pups, purging, and heating, ust be reported as fuel use on a per-site basis, even if it is vented afterwards. The volue ust be easured on a per site basis if over /d or ay be estiated if not over /d (see Figure 1.11). SK AB BC This requireent to easure the fuel gas exceeding /d applies. The /d easureent liit for fuel gas also applies to flare and vent gas streas, excluding heavy crude oil. All sites where fuel gas is easuring less than /d, will be required to estiate. There are no exeptions. For any site that was constructed after May 7, 2007, and was designed for annual average fuel gas use exceeding /d or for any site where annual average fuel gas use exceeds /d, the fuel gas ust be etered. At sites where fuel gas etering is required, up to /d ay be estiated. BCOGC Flaring and Venting Reduction Guideline: Gas that is used for pilot, purge or blanket gas ust be reported as either flared or vented. Process gas used to operate instruentation or as power gas to drive cheical pups ust be included as vented gas. This does not include fuel gas added to flare or incinerator streas in order to eet iniu heating value requireents. If the site has ore than one Petrinex reporting facility, only the fuel for the overall site ust be etered; it ust then be allocated to and reported for each facility, provided that the facilities have coon working interest ownership and there are no royalty trigger easureent points across the facilities. If there is no coon working interest ownership or there are royalty trigger easureent points across the facilities, then any fuel gas volues crossing reporting facility boundaries ust be etered. The only exception is for integrated oilfield waste anageent facilities (OWMF) with WP, CT, and IF facilities on the sae site, in which case fuel REC is to be reported at the WP and total OWMF fuel use at the sae facility. 13. For sites with annual average flare or vent rates of /d, the flare or vent gas volue ay be deterined by using estiates. For any site with an annual average flare or vent rate of > /d, the flare or vent gas ust be etered (See Figure 1.11). Sites requiring flare or vent gas etering ay estiate up to /d. These flare or vent thresholds do not apply to heavy oil batteries. See Section for heavy oil flaring and venting easureent requireents Gas Lift Systes for Both Oil and Gas Wells There are four gas source scenarios, and each one ay be subject to different easureent, reporting, and sapling and analysis requireents when gas is injected into the wellbore to assist in lifting the liquids to the surface. SK GAS LIFT is not used for reporting. AB The Directive 007 requireent is to update/change the well to GAS LIFT status for oil wells that use gas lift and to GAS PUMP status. BC BC Oil and Gas Coission Flaring and Venting Reduction Guideline Section 11 Measureent and Reporting August 1, 2017 Page 4-19

99 Scenario 1 There is no external gas source for the lift gas used given the raw gas is being separated and recirculated continuously at the well with copressor(s). Regular sapling and analysis frequency for the well type applies (see Section 8.4). Figure 4.8. Lift gas fro existing well Scenario 1 Lift gas re-injection Option 1: No easureent required Option 2: Measureent required Separator Gas Hydrocarbon Liquid Water To Gas Gathering Syste / Gas Plant / Sales Well = Measureent Point Scenario 1 Option 1: If the lift gas is taken fro upstrea of the production easureent point, then there is no reporting requireent. Option 2: If the lift gas is taken fro downstrea of the production easureent point, then easureent of the lift gas is required and the total well gas production will be the difference between the total easured production volue and the easured lift gas volue. Scenario 2 This scenario applies to the lift gas received back fro a downstrea gas plant/facility that is classified as return gas (no royalty iplications). Measureent is required at the battery level for any gas coing back fro the gas plant/facility after sweetening/processing and reported as REC, but such easureent is not delivery point easureent. Part of this return gas could be used for fuel at the well. The lift gas injected into the wellbore ust be easured and regular sapling and analysis frequency for the well type applies (see Section 8.4). There are two possibilities under Scenario 2 (see Figures 4.9 and 4.10). For proration tested wells, the gas lift volue during the test period ust be netted off the total test gas production volue to deterine the estiated gas production volue for each well. August 1, 2017 Page 4-20

100 Figure 4.9. Lift gas using return gas fro plant Scenario 2a Test Taps Well A Test Taps Lift Gas Meter Group Gas Meter Hydrocarbon liquid Gas Plant Gas Sales Water Well B Lift Gas Meter = Measureent Point Return Gas Scenario 2a For continuously easured wells, the gas lift volue ust be netted off the total easured gas production volue to deterine the actual gas production volue for each well. Figure Lift gas using return gas fro plant Scenario 2b Well A Prod. Gas Meter Hydrocarbon Liquid Water Well B Prod. Gas Meter Hydrocarbon Liquid Lift Gas Meter Hydrocarbon liquid Gas Plant Gas Sales Water Lift Gas Meter = Measureent Point Return Gas Scenario 2b Scenario 3 (Does not exist in Saskatchewan) This scenario applies to lift gas that coes fro external sources with royalty iplications. Any gas coing fro a non-royalty paid gas source ust be easured and reported at the battery/facility level as PURREC and as PURDISP at the sending facility. The well easureent and reporting requireent is the sae as Scenario 2 and the gas sapling and analysis frequency for this type of gas lift well is seiannual. Scenario 4 August 1, 2017 Page 4-21

101 This scenario applies to lift gas that coes fro royalty exept sources. SK The easureent and reporting requireent is the sae as Scenario 2. AB BC The easureent and reporting requireent is the sae as Scenario 2 with the additional requireent that prior approval ust be obtained fro Alberta Energy to use the royalty-paid strea ID# WG for the SAF/OAF subission to identify royalty-exept gas that is to be used as gas lift. The lift gas coes fro royalty exepted sources, such as TCPL or ATCO Gas The gas sapling and analysis frequency for this type of gas lift well is seiannual. August 1, 2017 Page 4-22

102 Voluetric Data Aendents SK AB Section does not apply in Saskatchewan. A nuber of operational, easureent, and production accounting scenarios ay occur that can create errors in voluetric reporting in Petrinex. The errors ay need to be corrected and aended volues reported in Petrinex. The scenarios that require voluetric aendents are described as follows: 1. A gas etering error is discovered at a well or facility. In this case, the licensee of the facility ust iediately correct the cause of the error and subit aended onthly production reports to Petrinex to correct all affected gas volues. 2. The cause of a proration factor being outside target range is deterined, and the error can be quantified. The reported production data ust be aended, thereby bringing the factor back into line. If the cause is deterined and action is taken to correct the situation for future onths, but the findings are not quantifiable for past onths, no aendents need to be subitted. 3. The cause of a etering difference being outside target range is deterined, and the error can be quantified. The incorrectly reported production data ust be aended, thereby bringing the etering difference back into line. If the cause is deterined and action is taken to correct the situation for future onths but the findings are not quantifiable for past onths, no aendents need to be subitted. 4. The volue of gas plus gas equivalent (where applicable) calculated by a substitute gas analysis and condensate analysis (where applicable) is found to be in error > /d, and the per cent change fro the originally reported volue is > 2.0 per cent. Retroactive voluetric adjustents ust be calculated using the actual gas and, where applicable, condensate copositions. Reported volues of condensate or NGL that are in error by ore than 1.5 per cent and ±5.0 3 /onth ust be corrected and retroactive voluetric aendents ade in Petrinex. BC Section does not apply in British Colubia Chart Operations The chart drive for a circular chart recorder used to easure gas well gas production or group oil battery gas production ust not be ore than 8 days per cycle unless the exeption criteria specified in Section 5: Site-Specific Deviation fro Base Requireents are et or regulator site-specific approval is obtained. A 24-hour chart drive is required for test gas easured associated with Class 1 and 2 proration oil wells. An 8-day chart drive ay be used for test gas easureent associated with Class 3 and 4 proration oil wells. See August 1, 2017 Page 4-23

103 Section 6.5 Proration Well Testing for ore detail on classes of wells. If the ode of operation causes painting on the chart of because of cycling or on/off flows, a 24-hour chart is required for any gas easureent point for EFM ust be used. The Operator ust ensure that: 1. The eter location is properly identified on the chart. 2. The chart is correctly dated. 3. The on and off chart ties are recorded on the chart to the nearest quarter hour if not actual. 4. The correct orifice plate and line size are recorded on the chart. 5. The tie to the nearest quarter hour of any orifice plate change is indicated on the chart, along with the new orifice plate size. 6. It is noted on the charts if the differential, pressure, or teperature range of the recorder has been changed or if they are different fro the ranges printed on the chart 7. The flowing gas teperature is recorded on the chart in accordance with Table Proper chart reading instructions are provided when the pen fails to record because of sensing line freezing, clock stoppage, pens out of ink, overlapping traces, or other reasons. Exaple instructions include: a. drawing in the estiated traces, b. requesting to read as average flow for the issing period, or c. providing an estiate of the differential and static pressure. 9. Any data or traces that require correction ust not be covered over or obscured by any eans The Operator should ensure that: A notation is ade on the chart with regard to whether or not the eter is set up for atospheric pressure for square root charts. The accuracy of the eter clock speed is checked and the chart reader is instructed accordingly of any deviations. The differential pen is zeroed once per chart cycle. Differential pen recordings are at 33% or ore within the chart range whenever possible. Static pen recordings are at 20% or ore within the chart range whenever possible. When there is a painted differential band, instructions are provided as to where it should be read. There are various ways to read a painted chart: a. If the differential pen norally records at the top of the painted band but spikes quickly down and up during separator dup cycles, it is reasonable to read the differential near the top of the band or vice versa. b. If the differential pen is in constant up and down otion, it is reasonable to read the differential at the root ean square (RMS) of the band or in a sine wave otion alternating between the top and botto of the painted area. August 1, 2017 Page 4-24

104 7. The pen trace colours confor to the industry-accepted practice (RED for differential, BLUE for static, and GREEN for teperature). However, any colour ay be used, provided the colour used is docuented Regulator Site-Specific Requests If an inspection of a easureent device or of procedures reveals unsatisfactory conditions that significantly reduce easureent accuracy, the Regulator will direct that the licensee ipleent changes to iprove easureent accuracy, and this direction will becoe a condition of operation for that facility or facilities. Exaples of unsatisfactory conditions applicable to orifice chart recorders are as follows: 1. Thick pen traces that will cause excessive error when reading the traces. 2. Painting traces. 3. Differential or static pens recording too low on the chart in scenarios where it is unavoidable because of low flow rate, high shut-in pressure, and equipent or operating pressure range liitations. Chart Reading The chart integrator/planieter operator ust ensure the following: 1. Visible gaps between the integrator/planieter traces and chart traces are iniized. 2. The counter is read correctly. 3. The integrator is calibrated as per the specified calibration frequency and after each change of pens. 4. The correct integrator or square root planieter constants are noted. 5. The correct integrator setback is recorded. 6. The correct coefficient, using all of the required factors, is recorded. Digital Chart Reading Technology Soe chart reading technology uses digital scanning technology to scan and store an iage of the chart and the use of coputer progras to read and interpret the digital iage of the chart and the pen traces. The use of digital technologies to read charts does not require prior approval of the Regulator, but the licensee using any new technology ust be able to deonstrate that the following requireents are et: 1. The equipent and/or procedures used to read the chart ust not alter or destroy the chart such that it cannot subsequently be read using conventional equipent and/or procedures. 2. The accuracy and repeatability of the new equipent and/or procedures ust be equal to or better than conventional equipent and/or procedures. The following requireents are specific to the use of digital scanning technology for reading charts: August 1, 2017 Page 4-25

105 The original chart ust be retained for at least 12 onths, 18 onths for gas production associated with heavy oil or crude bituen, or alternatively the licensee ay choose the following procedure for audit trail: a. An original scanned iage of the chart, both front and back, ust be stored so that it cannot be changed. If the chart back is blank, the back does not need to be scanned provided there is a stateent entered in the record to that effect. There ust be a ethod to confir that a set of front and back scans belong to the sae chart if scanned and stored. No alteration or editing of the original scanned iage is allowed. b. At least two separate electronic copies of the scanned iages ust be retained and one copy ust be stored off site at a different physical address/location for the applicable required period. Note that although the Saskatchewan and Alberta Regulators accept the electronic subission for audits, other jurisdiction ight not. Therefore the original chart should be kept for other jurisdictional audits. Editing or alterations ay only be ade to a copy of the original scanned iage of the chart. If the edited version is used for accounting purposes, the edited or altered iage ust be stored for the applicable required period and in the sae anner as in ite #1. An iage of the chart showing how the chart pen traces were read or interpreted ust be stored for the applicable required period and in the sae anner as in ite #1. If there are any changes or additions to those requireents and recoendations specific to chart scanning, these ust be docuented and ade available for instructing chart analysts. An additional requireent specific to chart scanning is as follows: a. When a differential pen is not zeroed correctly, the zero line ust be adjusted to the correct position if it is obvious on the chart such as when the zeroing was out when changing charts but the pen was not adjusted and/or as docuented by the operator. Other situations will require the judgent of the chart analyst and confiration fro the facility operator. Any zero adjustent ust only reposition the zero line and ust aintain the entire span of the pen. The distance between the actual zero and the pen trace ust not be altered. For Regulator inspection/audit purposes, the licensee ust upon request: a. subit any original paper charts or the scanned original iages or ake the available for on-line viewing; and b. subit all edited iages or ake the available for on-line viewing. Note that the software used to open the scanned iages should be readily and freely available on the arket. In case there is any specific/proprietary iage reader software required to view the scanned and stored chart iages, it ust also be subitted. Upon request of the operator, the vendor ust deostrate the accuracy of the scanning and integration technology by perforing three consecutive scans, with a August 1, 2017 Page 4-26

106 7. rotation of the chart iage of about 120 before each scan, and integrations of the sae chart iage. The calculated volues fro each reading ust be within ±0.5% of the average of the three scans and integrations. The Regulator ay check the accuracy of the chart-reading technology and volue calculations by providing charts with known calculated volues. The volues deterined by the chart reading technology ust be within ±0.5% of the Regulator s known values Exeptions fro Base Requireents Gas in Solution with Oil Volues under Pressure In soe scenarios, a gas volue ust be deterined, such as where the gas is dissolved in an oil volue under pressure, and there is no opportunity to easure the gas volue prior to it being coingled with other gas volues. In that scenario, the gas volue ay be deterined by estiation, regardless of its daily volue rate. An exaple of such a gas volue is the gas held in solution with oil volues leaving a test separator at an oil proration battery, where the test oil volues are cobined with production fro other wells downstrea of the test separator. The purpose of estiating the gas in solution is to deterine the total gas produced by a well during a production test, since the gas volue easured by the test gas eter will not include the gas that is still in solution with the test oil volue. A single gas in solution (GIS) factor ay be deterined and used to estiate the gas volue held in solution with the oil strea for each oil strea where the production sources (producing foration) are the sae and test separator operating conditions are siilar. Additional GIS factors are required for wells in the battery that produce fro different forations and where other test separators operate at different pressure and/or teperature conditions. Licensees should also consider deterining seasonal GIS factors where abient teperature differences ay significantly affect the factors or when operating conditions change significantly. The GIS factor ay be deterined by one of the following applicable tests/procedures: 1. A 24-hour test ay be conducted such that the production fro a well or group of wells is directed through the test and group separation/treating equipent, with all other wells shut in or directed around the equipent. The total volue of gas released fro the oil after it leaves the test separator ust be easured. This volue divided by the stock tank volue of oil deterined at the test separator provides a GIS factor. 2. A saple of oil taken under pressure containing the gas in solution that will be released when the oil pressure is reduced ay be subitted to a laboratory where a pressure-volue-teperature (PVT) analysis can be conducted. The analysis ust be based on the actual pressure and teperature conditions that the oil saple would be subjected to downstrea of the saple point, including ultiple stage flashing. The GIS factor is calculated based on the volue of gas released fro the saple and the volue of oil reaining at the end of the analysis procedure. 3. A saple of oil taken under pressure containing the gas in solution that will be released when the oil pressure is reduced ay be subitted to a laboratory where a copositional analysis can be conducted. A coputer siulation progra ay be used to deterine the GIS factor based on the copositional analysis. August 1, 2017 Page 4-27

107 4. A rule of thub estiate ( of gas/ 3 of oil/kpa of pressure drop) ay be used as the GIS factor for non-heavy oil production until a ore accurate, specific GIS factor is deterined. It ay be used on a continuous basis, without the need for deterining a ore accurate GIS factor, if well oil production rates do not exceed 2 3 /d or if all battery gas production is vented or flared. 5. Other ethods listed in the Canadian Association of Petroleu Producers (CAPP) Guide for Estiation of Flaring and Venting Volues fro Upstrea Oil and Gas Facilities ay be used Gas Produced fro Gas Wells and Non-Heavy Oil Wells For gas streas associated with the producing of non-heavy oil wells or gas wells up to per day of the annual average gas rate ay be deterined through estiation. No specific approval is required, but the operator ust keep the estiation/testing docuentation for Regulator audit. Exaples of the gas streas that ay be estiated up to /d include well test gas, battery group gas, single-well battery gas, fuel gas used on a per site basis, and oil/condensate tank vented gas. A gas strea that ust be easured regardless of daily volue is dilution gas added to an acid gas strea to ensure coplete cobustion due to the iportance of accurately deterining those volues. Initial qualification of gas streas where volues ay be estiated can be based on existing historical data or deterined by conducting one of the applicable tests/procedures in Section Qualifying gas volues ay be estiated by using a gas-oil-ratio (GOR) factor if gas volue estiates will vary in conjunction with oil volues or by using an hourly rate if gas volues are not dependent upon oil volues. These factors ust be updated annually to confir continuing eligibility for estiation and to update the factors used to estiate gas volues. The factors ust also be updated iediately following any operational changes that could cause the factors to change. Licensees should also consider deterining seasonal GOR factors if abient teperature differences ay significantly affect the factors. Updated factors ay be deterined by one of the applicable tests/procedures described in Section Exeption for Gas Produced fro Gas Wells and Non-Heavy Oil Wells Crude oil ultiwell proration batteries (Petrinex facility subtype 322) ay use a onthlycalculated; battery-level GOR (onthly battery gas production onthly battery oil production) to calculate individual well gas production in accordance with the following conditions: 1. All wells using the battery-level GOR ust produce /d of gas 2. Any well producing > /d of gas is not eligible to use the battery-level GOR, and well gas production ust be deterined using test rates obtained during proration testing 3. Monthly gas and oil volues fro wells not eligible to use the battery-level GOR ust be subtracted fro the total battery gas and oil volues before calculating the battery-level GOR. For gas, the volue to be subtracted would be the total estiated gas deterined fro proration testing for all the ineligible wells; for oil, the volue would be the total prorated oil production for all the ineligible wells. 4. New wells added to the battery ust produce /d of gas for a iniu of six onths before being eligible to use the battery-level GOR. August 1, 2017 Page 4-28

108 5. If there is no coon ownership of all wells in the battery, written notification has been given to all working interest participants, with no resulting objections. 6. If there is no coon Crown or Freehold royalty and only Freehold royalties are involved in all wells in the battery, written notification has been given to all Freehold royalty owners, with no resulting objection received. If there is a ix of Freehold and Crown royalties involved, the licensee ust apply to the Regulator for approval if any Freehold royalty owner objects Gas Produced in Association with Heavy Oil Production See Section for details. Methods for Deterining Factors/Rates Used in Estiating Gas Volues If gas volues are estiated using a GOR: 1. A 24-hour test ay be conducted such that all the applicable gas and oil volues produced during the test are easured including vented gas. The gas volue is to be divided by the oil volue to deterine the GOR factor. 2. A saple of oil taken under pressure containing the gas in solution that will be released when the oil pressure is reduced ay be subitted to a laboratory where a PVT analysis can be conducted. The analysis ust be based on the actual pressure and teperature conditions the oil saple would be subjected to downstrea of the saple point. The GOR factor will be calculated based on the volue of gas released fro the saple and the volue of oil reaining at the end of the analysis procedure. 3. A saple of oil taken under pressure containing the gas in solution that will be released when the oil pressure is reduced ay be subitted to a laboratory where a copositional analysis can be conducted. A coputer siulation progra ay be used to deterine the GOR based on the copositional analysis. 4. Other ethods listed under the Canadian Association of Petroleu Producers (CAPP) Guide for Estiation of Flaring and Venting Volues fro Upstrea Oil and Gas Facilities ay be used If gas volues are estiated using an hourly rate: 1. A eter ay be used to easure the gas strea for a iniu of one hour. The gas volue easured during this test ay be used to deterine the hourly rate that will be used to estiate gas volues. 2. If applicable, such as for fuel gas volues, the hourly rate ay be deterined based on the equipent anufacturer s stated gas consuption rates and the actual operating conditions. Exaple Calculations for Estiating Gas Volues Using GOR and GIS Factors Deterination of Total Produced Gas for a Single-Well Oil Battery Figure 4.11 depicts a single-well battery where a three-phase separator is used to separate oil, gas, and water production fro a well. The oil in the separator is under pressure until it is directed to the storage tank, which is at atospheric pressure (zero kpa gauge). When the oil pressure drops at the tank, the GIS within the oil will be released. The gas leaving the separator in this exaple is etered, while the GIS released at the tank is estiated using a August 1, 2017 Page 4-29

109 GOR factor. Total gas production fro the well is deterined by adding the etered gas and the GIS released at the oil storage tank. If a single-well battery uses a two-phase separator, the procedure for deterining total gas production is the sae as for a three-phase separator. If the gas production rate eets the qualifying criteria for estiation and all production fro the well produces directly to a tank without using a separator, the total gas production ay be deterined by using only a GOR factor. Figure Single-well oil battery exaple Well Metered Gas 200 kpa GIS (stock tank vapours) Separator Oil Tank 0 kpa Water Tank = Measureent Point Saple Calculation: Total Gas Volue at a Single-Well Battery (Figure 4.11) Monthly well data (hypothetical) given for this exaple: Gas eter volue = (fro chart readings) Oil eter volue = (fro eter or tank gauging) Pressure drop = 200 kpa GIS factor = gas/ 3 oil or gas/ 3 oil/kpa pressure drop (deterined using a ethod other than the rule of thub) Step 1: Calculate GIS volue: / 3 x = = or / 3 /kpa x x 200 kpa = = Step 2: Calculate the total battery gas production for the onth: = Note that total reported battery gas production is to be rounded to one decial place. Deterination of Total Produced Gas for an Oil Proration Battery Figure 4.12 depicts a ultiwell oil proration battery where production testing of individual wells is done by directing individual well production through a test separator at the ain August 1, 2017 Page 4-30

110 battery site or through a test separator at a satellite facility located away fro the ain battery site. In this exaple, the oil, gas, and water leaving the test separator at the satellite are recobined with the satellite group production and directed to the group separation and easureent equipent at the ain battery site. The oil and water leaving the test separator at the ain battery site are recobined with the battery group production, but the gas leaving the test separator recobines with the group gas downstrea of the group gas easureent point. The oil in the group separator is under pressure until it is directed to the storage tank, which is at atospheric pressure (zero kpa gauge). When the oil pressure drops at the tank, the GIS with the oil will be released. The total gas production at the battery will be the su of all the easured test gas at the battery site, the easured group gas at the battery, and the GIS released at the oil storage tank. Trucked oil volues received at the battery ust not be included with the total battery oil volue when deterining the GIS released at the oil storage tank. At soe facilities a vapour recovery unit (VRU) ay be installed to collect any GIS that ay be released at the oil storage tank. If the VRU is equipped with a eter or the recovered gas is directed through the group gas eter, a GIS calculation will not be required because the easured VRU gas will either be added to or included in the other easured gas volues. Figure Multiwell proration oil battery exaple Test separator at satellite 600 kpa Well A Other wells Oil and water Metered gas Gas Satellite Gas to plant Well X Other wells Group inlet = Measureent Point Gas Test separator 200 kpa Oil and water To ain battery Water tank Gas Group separator or treater 100 kpa Oil to storage tank GIS (stock tank vapours) Storage tank 0 kpa Saple Calculation: Total Gas Production at the Oil Proration Battery (Figure 4.12) Monthly battery data (hypothetical) given for this exaple: Oil production at the proration battery = for the onth (fro eter and/or tank gauging) Total test gas easured at the battery site = (fro chart readings) August 1, 2017 Page 4-31

111 Measured group gas production = (fro chart readings) Pressure drop fro the group vessel to oil storage tank = 100 kpa GIS factor = gas / 3 oil or / 3 /kpa (deterined using a ethod other than the rule of thub) Step 1: Calculate the GIS volue: / 3 x = = or / 3 /kpa x x 100 kpa = = Step 2: Calculate the total produced gas volue for the battery: = Note that total reported battery gas production is to be rounded to one decial place. Deterination of Individual Well Test Gas for an Oil Proration Battery Figure 4.12 depicts a ultiwell oil proration battery where production testing of individual wells is done by directing individual well production through a test separator at the ain battery site or through a test separator at a satellite facility located away fro the ain battery site. In either scenario, the oil leaving the test separator is under pressure and will be subjected to two stages of pressure drop one at the group separator and one at the storage tank. The total gas produced by a well during a test will be the su of the gas easured as it leaves the test separator and the GIS that will evolve fro the test oil volue after leaving the test separator. In the exaple, the test separators at the battery and satellite operate at significantly different pressures, and the oil leaving the test separator at the satellite will contain ore GIS than the oil leaving the test separator at the battery. Saple Calculation: Test Gas Production for Wells in the Satellite (Figure 4.5) Satellite test data (hypothetical) given for this exaple for well A: Metered test oil = (fro oil eter) Metered test gas = (fro chart readings) GIS factor = gas/ 3 oil or gas/ 3 oil/kpa pressure drop (cobined GIS for both stages of pressure drop fro test pressure at 600 kpa to group pressure at 100 kpa to oil storage tank pressure at atospheric pressure or zero kpa gauge, deterined using a ethod other than the rule of thub) Step 1: Calculate the GIS volue: / 3 /kpa x x 600 kpa = = or / 3 x = = Step 2: Calculate the total test gas produced for well A for this test: = Note that test gas volues ust be deterined to two decial places (in ). Saple Calculation: Test Gas Production for Wells in the Battery (Figure 4.5) Battery test data (hypothetical) given for this exaple for well X: August 1, 2017 Page 4-32

112 Metered test oil = (fro oil eter) Metered test gas = (fro chart readings) GIS factor = gas/ 3 oil or gas/ 3 oil/kpa pressure drop (cobined GIS for both stages of pressure drop fro test pressure at 200 kpa to group pressure at 100 kpa to oil storage tank pressure at atospheric pressure or zero kpa gauge, deterined using a ethod other than the rule of thub) Step 1: Calculate the GIS volue: / 3 /kpa x x 200 kpa = = or / 3 x = = Step 2: Calculate the total test gas produced for well X for this test: = Note that test gas volues ust be deterined to two decial places (in ). 4.4 Electronic Flow Measureent (EFM) for Gas An EFM syste is defined as any flow easureent and related syste that collects data and perfors flow calculations electronically. If it is part of a Distributed Control Syste (DCS), Supervisory Control and Data Acquisition syste (SCADA) or Prograable Logic Controller syste (PLC), only the EFM portion has to eet the requireents in this section. All EFM systes previously approved by AER under Guide 34 ay continue as approved. The following systes are not defined as an EFM: 1. Any eter with an electronic totalizer or pulse counter that does not perfor flow calculations with or without built-in teperature copensation. 2. A Reote Terinal Unit (RTU) that transits any data other than flow data and does not calculate flow Acceptable Base Requireents for EFM If an EFM is used to calculate volues for Regulator accounting purpose, the licensee ust be able to verify that it is perforing within the Regulator allowed deviation liits defined in this section. When any paraeter that affects the flow calculation is changed, such as orifice plate size, eter factor, fluid analysis, or transitter range, a signoff procedure or an event log ust be set up to ensure that the change is ade in the EFM syste. All data and reports ust be retained for a iniu of 12 onths. Hardware and software requireents: 1. The EFM data storage capability ust exceed the tie period used for data transfer fro the EFM syste. 2. The EFM syste ust be provided with the capability to retain data in the event of a power failure, e.g., battery backup, UPS, EPROM. 3. Syste access ust have appropriate levels of security, with the highest level of access restricted to authorized personnel. August 1, 2017 Page 4-33

113 4. The EFM syste ust be set to alar on out-of-range inputs, such as teperature, pressure, differential pressure (if applicable), flow, low power, and counication failures. 5. Any EFM configuration changes or forced inputs that affect easureent coputations ust be docuented either electronically via audit trails or on paper. The values calculated fro forced data ust be identified as such EFM Perforance Evaluation Test A perforance evaluation test ust be copleted within two weeks after the EFM is put into service and iediately after any change to the coputer progra or algoriths that affects the flow calculation on a per software version basis. The evaluation ust be docuented for Regulator audit purposes on request. For existing EFM systes, the Regulator encourages licensees to conduct their own perforance evaluations. A perforance evaluation ust be conducted and subitted for Regulator audit on request. The Regulator considers either one of the following ethods acceptable for perforance evaluation: 1. Conduct a perforance evaluation test on the syste by inputting known values of flow paraeters into the EFM to verify the volue calculation, coefficient factors, and other paraeters. The first seven test cases included in this section are for gas orifice eters (AGA3 flow calculations), each with different flow conditions and gas properties. Test Case 8 is for the AGA7 flow calculation for positive displaceent or linear eters. Other anufacturers recoended equations can also be used to evaluate the EFM perforance. The seven AGA3 test cases could also be used to evaluate any copressibility or super copressibility factors used in other flow calculations using the sae gas coposition, pressure, and teperature in the calculation as inputs. 2. Evaluate the EFM calculation accuracy with a flow calculation checking progra that perfors within the allowed deviation liits for all the factors and paraeters listed in the test cases. A snapshot of the instantaneous flow paraeters and factors, flow rates, and configuration inforation is to be taken fro the EFM and input into the checking progra. If the instantaneous EFM flow paraeters, factors, and flow rates are not updated siultaneously, ultiple snapshots ay have to be taken to provide a representative evaluation. Note that soe DCS or other control systes have built-in and/or anual input of pressure and teperature for flow calculations. Since the pressure and teperature are not continuously updated, they are not acceptable for Regulator accounting and reporting purposes unless Regulator approval is obtained. The voluetric flow rate (Q) obtained fro a perforance evaluation test ust agree to within ±0.25% of those recorded on the saple test cases or other flow calculation checking progras. If the ±0.25% liit is exceeded, the EFM ust be subjected to a detailed review of the calculation algorith to resolve the deviation proble. For gas orifice eters, if no AGA3 factor or paraeter outputs are available, the acceptable voluetric gas flow rate liit is lowered to ±0.15%. Test Cases 1 to 7 for Verification of Orifice Meter Gas Flow Calculation Progras August 1, 2017 Page 4-34

114 The Regulator has developed test cases to verify that the EFM syste correctly calculates gas flow rates fro orifice eters. The seven test cases were calculated on the following basis: 1. They are for flange taps only. 2. The atospheric pressure is assued to be kpa(a) (13.5 psia). 3. The heaviest carbon coponent was assued to be noral heptane. 4. The ideal gas relative density was converted to the real gas relative density. 5. The sae static pressure value is used for pressure taps that are located upstrea (U/S) or downstrea (D/S) of the orifice plate. 6. The AGA3 (1985) results were calculated based on upstrea conditions for both upstrea and downstrea static pressure tap in iperial units and the Y2 factor is also provided for reference. The etric conversion factor for the calculated gas volue is The copressibility factors were calculated using the Redlich-Kwong (RK) equation with the Wichert-Aziz correction for sour gas. 7. The AGA3 (1990) results were calculated using the Detail AGA8 (1992) copressibility factor calculation and using the upstrea expansion factor Y1, as recoended by the AGA3 (1990), Part 1, Section 1.8, even though the pressure tap ay be downstrea of the orifice plate. The Y2 factor is also provided for reference when applicable. 8. The orifice plate aterial is assued to be 316 stainless steel and the eter run to be carbon steel at reference teperature of 20 C, isentropic exponent (k) = 1.3, viscosity = centipoise. 9. The base conditions ( kpa[abs] and 15 C) are used in the calculated teperature base factor (F tb ) and pressure base factor (F pb ). Test Case 8 for Verification of AGA7 Gas Flow Calculation Progras The Regulator has developed a test case to verify that the EFM syste correctly calculates gas flow rates using the AGA7 equations. The test case was calculated on the following basis: 1. The heaviest carbon coponent was assued to be noral heptane. 2. The copressibility factors were calculated using the Detail AGA8 (1992) or the Redlich-Kwong (RK) equation with the Wichert-Aziz correction for sour gas. Table 4.3. Allowable deviation liits for the AGA3 (1985) equation AGA3 (1985) factors Allowed deviation liit fro test cases Y, F a, F r, and F tf ±0.01% F b ±0.1% F gr, F pv ±0.2% Q ±0.25% or ±0.15% without the above factors August 1, 2017 Page 4-35

115 Table 4.4. Allowable deviation liits for the AGA3 (1990) equation AGA3 (1990) factors Allowed deviation liit fro test cases Y 1, and E v ±0.01% C d and Z b ±0.1% Z f ±0.2% Q ±0.25% or ±0.15% without the above factors Table 4.5. Allowable deviation liits for the AGA7 equation AGA7 factors Allowed deviation liit fro test cases F p (flowing pressure) and F t (flowing teperature) ±0.1% S (copressibility) ±0.2% Q ±0.25% or ±0.15% without the above factors August 1, 2017 Page 4-36

116 TEST CASE 1 (for AGA3 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Ideal gas relative density Meter Data (flange taps) Meter run I.D ( inches) Orifice I.D (0.375 inches) Flow Data (24 hr) Static pressure kpa(a) ( psia) Differential pressure kpa ( inches H 2 O) Flowing teperature C ( F) Gas Volue Result AGA3 (1985) AGA3 (1990) Factors U/S Tap D/S Tap Factors U/S Tap D/S Tap F b C d Y Y Y 2 N/A Y 2 N/A F tb E v F gr Z b F a Z f F r Q /24 hr F pb F tf F pv C' Q /24 hr August 1, 2017 Page 4-37

117 TEST CASE 2 (for AGA3 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Ideal gas relative density Meter Data (flange taps) Meter run I.D (4.026 inches) Orifice I.D (1.875 inches) Flow Data (24 hr) Static pressure kpa(a) ( psia) Differential pressure kpa ( inches H 2 O) Flowing teperature C (122.0 F) Gas Volue Result AGA3 (1985) AGA3 (1990) Factors U/S Tap D/S Tap Factors U/S Tap D/S Tap F b C d Y Y Y 2 N/A Y 2 N/A F tb E v F gr Z b F a Z f F r Q /24 hr F pb F tf F pv C' Q /24 hr August 1, 2017 Page 4-38

118 TEST CASE 3 (for AGA3 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Ideal gas relative density Meter Data (flange taps) Meter run I.D ( inches) Orifice I.D ( inches) Flow Data (24 hr) Static pressure kpa(a) ( psia) Differential pressure kpa ( inches H 2 O) Flowing teperature C (140.0 F) Gas Volue Result AGA3 (1985) AGA3 (1990) Factors U/S Tap D/S Tap Factors U/S Tap D/S Tap F b C d Y Y Y 2 N/A Y 2 N/A F tb E v F gr Z b F a Z f F r Q /24 hr F pb F tf F pv C' Q /24 hr August 1, 2017 Page 4-39

119 TEST CASE 4 (for AGA3 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Ideal gas relative density Meter Data (flange taps) Meter run I.D ( inches) Orifice I.D (3.500 inches) Flow Data (24 hr) Static pressure kpa(a) ( psia) Differential pressure kpa ( inches H 2 O) Flowing teperature C (72.23 F) Gas Volue Result AGA3 (1985) AGA3 (1990) Factors U/S Tap D/S Tap Factors U/S Tap D/S Tap F b C d Y Y Y 2 N/A Y 2 N/A F tb E v F gr Z b F a Z f F r Q /24 hr F pb F tf F pv C' Q /24 hr August 1, 2017 Page 4-40

120 TEST CASE 5 (for AGA3 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Ideal gas relative density Meter Data (flange taps) Meter run I.D ( inches) Orifice I.D (3.750 inches) Flow Data (24 hr) Static pressure kpa(a) ( psia) Differential pressure kpa ( inches H 2 O) Flowing teperature C (93.2 F) Gas Volue Result AGA3 (1985) AGA3 (1990) Factors U/S Tap D/S Tap Factors U/S Tap D/S Tap F b C d Y Y Y 2 N/A Y 2 N/A F tb E v F gr Z b F a Z f F r Q /24 hr F pb F tf F pv C' Q /24 hr August 1, 2017 Page 4-41

121 TEST CASE 6 (for AGA3 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Ideal gas relative density Meter Data (flange taps) Meter run I.D ( inches) Orifice I.D (0.750 inches) Flow Data (24 hr) Static pressure kpa(a) ( psia) Differential pressure kpa ( inches H 2 O) Flowing teperature C (44.96 F) Gas Volue Result AGA3 (1985) AGA3 (1990) Factors U/S Tap D/S Tap Factors U/S Tap D/S Tap F b C d Y Y Y 2 N/A Y 2 N/A F tb E v F gr Z b F a Z f F r Q /24 hr F pb F tf F pv C' Q /24 hr August 1, 2017 Page 4-42

122 TEST CASE 7 (for AGA3 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Ideal gas relative density Meter Data (flange taps) Meter run I.D ( inches) Orifice I.D (0.50 inches) Flow Data (24 hr) Static pressure kpa(a) (43.50 psia) Differential pressure kpa (25.5 inches H 2 O) Flowing teperature C (35 F) Gas Volue Result AGA3 (1985) AGA3 (1990) Factors U/S Tap D/S Tap Factors U/S Tap D/S Tap F b C d Y Y Y 2 N/A Y 2 N/A F tb E v F gr Z b F a Z f F r Q /24 hr F pb F tf F pv C' Q /24 hr August 1, 2017 Page 4-43

123 TEST CASE 8 (for AGA7 Flow Calculations) Gas Analysis N ic CO nc H 2 S ic C nc C C C C Flow Data (24 hr) Uncorrected volue Static pressure kpa(a) ( psia) Flowing teperature C (44.96 F) Gas Volue Result AGA7 (Voluetric Flow) Factors F p F pb F t F tb Using AGA8 copressibility equations, S Q /24 hr Using RK copressibility equations, S Q /24 hr August 1, 2017 Page 4-44

124 4.5 Measureent Reports for EFM Systes The required inforation on each report ust be stored using electronic edia (not necessarily on the EFM) or printed edia and can exist individually on different forats or reports and generated on deand for audit, as follows: 1. Daily for daily report required data 2. Monthly for onthly report required data 3. Event and alar logs at regular intervals before inforation is overwritten 4. Meter reports generated on request for audit Daily Report The daily report ust include: 1. Meter identification 2. Daily accuulated flow, with indicating flags for estiated flows ade by the syste or by the operation personnel and alars that have occurred for overranging of end devices 3. Hours on production or hours of flow (specify) 4. Flow data audit trail include at least one of the following: a. Instantaneous values for flow rate, differential pressure (if applicable), static pressure, and teperature taken at the sae tie each day, or b. Average daily values for differential pressure (if applicable), static pressure, and teperature, or c. Hourly accuulated flow rate and average hourly values for differential pressure (if applicable), static pressure, and teperature Existing EFM systes that do not have any of the audit trail capabilities specified in Section 4.5, and cannot develop the capability due to syste liitations, should be evaluated for upgrading, especially when new production is tied into the facilities. The Regulator ay request upgrades, where audit/inspection results indicate they are warranted Monthly Report This report is for the entire syste, providing data for each easureent point. It is to contain the following at each easureent point as applicable: 1. Monthly cuulative flow 2. Flags indicating any change ade to flow volues 3. Total hours on production or hours of flow (specify) August 1, 2017 Page 4-45

125 4.5.3 Meter Report The eter report details the configuration of each eter and flow calculation inforation. These values are used as part of the audit trail to confir that the flow calculation is functioning correctly. Without the there is no way of verifying the accuracy of the syste. The eter report ust include the following as applicable and be produced on deand: Instantaneous Flow Data, including: a. Instantaneous flow rate b. Instantaneous static pressure c. Instantaneous differential pressure d. Instantaneous flowing teperature e. Instantaneous relative density (if live) f. Instantaneous copressibility (if live) g. Instantaneous gas coponent (if live) h. Optional: instantaneous (AGA3) factors (see the orifice eter test cases in Section for output inforation) Current Configuration Inforation for Differential Meters or Other Types of Meters, whichever are applicable: a. Meter identification b. Date and tie c. Contract hour d. Atospheric pressure e. Pressure base (unless fixed) f. Teperature base (unless fixed) g. Meter tube reference inside diaeter h. Orifice plate reference bore size i. Static pressure tap location j. Orifice plate aterial k. Meter tube aterial l. Calibrated static pressure range. Calibrated differential pressure range n. Calibrated teperature range o. High/low differential cutoff p. Relative density (if not live) q. Copressibility (if not live) r. Gas coponents (if not live) August 1, 2017 Page 4-46

126 s. Meter factor and/or K-Factor t. Effluent correction factor Event Log This log is used to note and record exceptions and changes to the flow paraeter, configuration, prograing, and database affecting flow calculations, such as, but not liited to: 1. Orifice size change 2. Transitter range change 3. Date of gas/liquid analysis update 4. Algorith changes 5. Meter factor, K-Factor, or effluent correction factor changes 6. Other anual inputs Alar Log The alar log includes any alars that ay have an effect on the easureent accuracy of the syste. The tie of each alar condition and the tie of clearing of each alar ust be recorded. Alars to be reported ust include, but are not liited to, 1. Master terinal unit failures 2. Reote terinal unit failures 3. Counication failures 4. Low-power warning 5. High differential pressure (for differential easureent devices) 6. High/low voluetric flow rate (for other types of easureent) 7. Over-ranging of end devices August 1, 2017 Page 4-47

127 4.6 References Aerican Gas Association Transission Measureent Coittee Report No. 8 (AGA8), Noveber Copressibility and Supercopressibility for Natural Gas and Other Hydrocarbon Gases. Dranchuk, P.M., and Abou-Kassa, J.H., Calculation of Z Factors for Natural Gases Using Equations of State, The Journal of Canadian Petroleu Technology, Vol. 14, No. 3, July- Septeber 1975, pp Dranchuk, P.M., Purvis, R.A., and Robinson, D.B., Coputer Calculation of Natural Gas Copressibility Factors Using the Standing and Katz Correlation, Institute of Petroleu Technical Series No. 1, IP , Gas Processors Association, GPA 2145: Table of Physical Constants for Hydrocarbons and Other Copounds of Interest to the Natural Gas Industry. Gas Processors Suppliers Association, SI Engineering Data Book. Hall, K.R., and Yarborough, L., A New Equation of State for Z Factor Calculations, The Oil and Gas Journal, June 18, 1973, pp Pitzer, K.S., Lippan, D.Z., Curl, R.F., Huggins, C.M., and Petersen, D.E., The Voluetric and Therodynaic Properties of Fluids II. Copressibility Factor, Vapour Pressure and Entropy of Vapourization, Journal of the Aerican Cheical Society, Vol. 77, No. 13, July Redlich, O., and Kwong, J.N.S., On the Therodynaics of Solutions. V. An Equation of State. Fugacities of Gaseous Solutions, Cheical Review 44, 1949, pp Wichert, E., and Aziz, K., Calculate Z s for Sour Gases, Hydrocarbon Processing, Vol. 51, May 1972, pp Yarborough, L., and Hall, K.R., How to Solve Equation of State for Z-Factors, The Oil and Gas Journal, February 18, 1974, pp August 1, 2017 Page 4-48

128 5 Site-specific Deviation fro Base Requireents Section 1: Standards of Accuracy states that a licensee ay deviate fro the Regulator s iniu easureent, accounting, and reporting requireents without specific approval if no royalty, equity, or reservoir engineering concerns are associated with the volues being easured and the licensee is able to deonstrate that the alternative easureent equipent and/or procedures will provide easureent accuracy within the applicable uncertainties. This section describes situations where a licensee ay deviate fro the iniu requireents without Regulator approval, provided that specific criteria are et. Licensees ay also apply for approval to deviate fro the iniu requireents if the specific criteria are not et; this section indicates what inforation ust be included in such an application. If these exeptions or approvals are in use, Regulator inspectors and auditors will review the licensee s records for deonstrated copliance with the criteria specified in this section or in the applicable approval. Approvals will reain in place indefinitely, including after transfer of the facility to another licensee, provided that conditions specified in the approval are et. If a Regulator audit or inspection finds that approval conditions are not being et, the approval ay be revoked and the licensee ay be required to eet applicable base requireents iediately, or other appropriate requireents ay be specified. 5.1 Site-specific Exeptions Deviation fro base easureent, accounting, and reporting requireents is allowed without subission of an application to the Regulator, provided that all the qualifying criteria listed under the subsequent Exeption sections are et. Qualifying Criteria These criteria detailed in the subsequent sections ust be et to qualify for the exeption. If the qualifying criteria have been et and the exeption is ipleented, it ay reain in place indefinitely, as long as it does not eet any of the revocation clauses and no physical additions to the facility are ade, e.g., new wells or stratigraphic units or zones. If additions or changes are ade to the facility, the qualifying criteria ust be et for all the wells or stratigraphic units or zones added to the facility for the exeption to reain in place. Docuentation Requireent To support the qualifying criteria, as long as the exeption applies, the licensee or operator ust retain all the data and docuentation and the last three testing records (if applicable). The Regulator ay revoke an exeption when the licensee fails to produce the supporting data or docuentation during an audit or inspection. The licensee will have thirty days to eet the applicable base requireents or at the Regulator s discretion, the licensee can negotiate a plan to coply with the exeption requireents within an approved tiefrae. 5.2 Site-specific Approval Applications SK The operator ay apply for a site specific easureent exeption through the IRIS generic application process, if all the necessary docuentation associated with an application is subitted and there is significant evidence to support the exeption, refer to Section 5 of Directive PNG017. (see August 1, 2017 Page 5-1

129 AB BC industry/oil-and-gas/oil-and-gas-licensing-operations-and-requireents/oil-andgas-drilling-and-operations/easureent-requireents/apply-for-a-easureentexeption ) For Measureent Deviations under Directive 17 applications are sent to Directive017Applications@aer.ca Site-Specific Applications under the BCOGC Measureent Guideline for Upstrea Oil and Gas Operations are sent to OGCPipelines.Facilities@bcogc.ca If the exeption criteria cannot be et or if a specific situation is not covered in this section, the licensee ay be allowed to deviate fro base easureent, accounting, and reporting requireents upon approval of an application subitted to the Regulator. If a licensee anticipates that proposed changes to the facility ay not eet the approval conditions, the licensee ay reconfigure the facility to eet base easureent, accounting, and reporting requireents or subit a new application for site-specific approval of deviation fro the base requireents. Approval ust be in place prior to ipleentation. Subission of an application does not guarantee that an approval will be granted. The following inforation is required for all applications for site-specific deviation fro base requireents. Other specific inforation that ay be required is described in the appropriate sections that follow. 1. Well and/or facility list, including: a. Battery code and locations b. Well locations - unique well identifier c. Licence nuber(s) d. EOR project code where applicable e. Respective pool or stratigraphic unit or zone designations and unique identifier for each stratigraphic unit or zone f. Indication as to unit or non-unit operation, if applicable g. Mineral ownership type (i.e. Crown/Freehold) h. Crown royalty status (e.g. new/old, etc.) i. Ownership and royalty equity issues, if any j. Latest six onths gas, oil/condensate, and water flow rates (or expected flow rates for new wells) k. Up-to-date easureent scheatic(s) for the existing syste(s) and the proposed new gas or oil source(s), including all tie-in locations, if applicable l. Facility plot plan for the existing syste and the proposed new gas or oil source(s), if applicable 2. Justifications for deviation fro easureent requireents, e.g., econoics, inial ipact on easureent accuracy. August 1, 2017 Page 5-2

130 5.3 Chart Cycles Extended Beyond the Required Tie Period Chart cycle is the tie required for a circular chart to coplete one 360 o revolution. An extension of the required chart cycle tie ay be applicable under the following scenarios: 1. The gas well orifice eter chart cycle is greater than eight days; 2. The single-well oil battery orifice gas eter chart cycle is greater than 24 hours; or 3. The Class 3 and 4 oil well test orifice gas eter chart cycle is greater than eight days. Mixing of wells with EFM systes and wells using extended cycle paper charts within the sae battery is allowed without approval fro the Regulator. Group, sales, or delivery point eters and Class 1 and 2 oil well test gas eters do not qualify for exeption fro chart cycle requireents, and approvals for extension of the chart cycle for those eters will not norally be granted Exeptions Orifice eter gas chart cycles ay be extended without Regulator site-specific approval if all the qualifying criteria in Section are et and an application is not required Qualifying Criteria Qualifying criteria that ust be et includes the following: 1. For a gas ultiwell battery, all wells in the battery are gas wells. A single-well battery does not qualify for this exeption on its own; the entire group battery or gas gathering syste ust be considered. 2. For an oil battery, all wells in the battery are oil wells, and each well is linked to either an oil single-well battery or to an oil ultiwell group battery, where each well has its own separation and easureent equipent. 3. All wells are subjected to the sae type of easureent (all well production is separated and all coponents are easured, or all well production is subject to effluent easureent) and the sae chart cycle. 4. All wells flowing to the battery: a. have coon working interest ownership, and where there is no coon ownership, written notification has been provided to all working interest participants and no objections have been received; b. are producing fro Crown ineral leases or are producing Freehold owned inerals (i.e. there is no ixture of Crown and Freehold inerals), and where the wells are producing Freehold inerals and the Freehold ownership is not coon, written notification has been provided to all Freehold owners and no objections have been received. 5. The onthly average voluetric gas flow rate for each well is /d including the gas equivalent of condensate for gas ultiwell battery easureent. 6. The differential pen records at 33% within the chart range, and the static pressure pen should record at 20% within the chart range. Painted traces ust not exceed 4% of the differential pressure or static pressure range. Painting occurs when there August 1, 2017 Page 5-3

131 are quick up and down oveents of the pen and there is no visible separation between the up and down traces for a period of tie. 7. Teperature ust be recorded at a iniu of once per week and if that is not possible, then continuous teperature easureent (teperature pen) is required. 8. The wells that are within the sae battery as the extended chart cycle wells and are designed for and/or operate on on/off flows, e.g., plunger lifts, pup-off controls, interittent tiers, ust be easured using EFM. In addition, an extended chart cycle with EFM is allowed. Exception: wells producing gas at a rate /d do not have to eet qualifying critieria 6 to 8 to qualify for extended chart cyles; however, all other criteria ust be et Revocation of Exeptions If any of the following scenarios exists or occurs, the exeption is revoked: 1. Gas fro an oil battery is delivered to a gas battery. 2. There is ixed easureent within the battery other than with EFM. 3. The oil well is not linked to either an oil single-well battery or to an oil ultiwell group battery where each well has its own separation and easureent equipent. 4. The working interest participants for any well flowing to the battery have changed and a new working interest participant objects to the exeption. 5. Any well within the battery has exceeded the /d onthly average actual gas production rate including gas equivalent of condensate for gas wells. 6. Painted traces for any well exceeded 4% of the differential pressure range or the static pressure range. 7. A new well with on/off flows is added to an effluent easureent battery or one or ore of the existing wells has been odified to operate on on/off flows but EFM is not used. Base easureent requireents ust be reinstated if the exeption is revoked due to any of the scenarios stated in Section Applications The following inforation ust be subitted with an application to extend orifice eter gas chart cycles if the criteria in Section are not et: 1. All of the inforation listed in Section If there is no coon ownership or no coon Crown or Freehold royalty, docuentation to address royalty and equity issues deonstrating that written notification was given to all Freehold ineral owners and working interest participants, with no resulting objection received. 3. A discussion of the ipact on easureent accuracy of interingling base chart cycles and extended chart cycles in a coon battery and how it ay relate to concerns about working interest equity and/or royalty considerations. August 1, 2017 Page 5-4

132 4. A iniu of two current, consecutive, representative gas charts. Additionally, the licensee has the option to run the charts on the proposed chart cycle to gather test data for subission and then revert back to the required chart cycle after a axiu test period of 31 days. The original copies of any such charts created ust be subitted with the application. The trial run ust be clearly identified on the charts Considerations for Site-specific Approval 1. Differential and static pressures are stable, with essentially uninterrupted flow: a. On/off flow as designed, including plunger lifts, pup-off controls, interittent tiers, etc., that cause painting or spiking, do not norally qualify for chart cycle extension. b. The effects of painting are iniized. The aount of painting that is acceptable is decided case by case. c. The differential pen should record at 33% within the chart range and the static pressure pen should record at 20% within the chart range. 2. There are inial equity and royalty concerns. 3. Reservoir engineering concerns: the concern for well easureent accuracy declines, fro a reservoir perspective, as the pool depletes. The applicant ust provide its assessent/opinion, but the Regulator has to decide on a case-by-case basis if the concerns are relevant. 4. All gas eters producing into the sae group easureent point use the sae chart cycle, so that they are subject to the sae type of error. 5.4 Gas Proration outside SW Saskatchewan and SE Alberta Shallow Gas Stratigraphic Units or Zones or Area For wells outside the boundary of and/or producing fro stratigraphic units or zones other than those approved for the SW Saskatchewan and SE Alberta Shallow Gas Stratigraphic Units or Zones or Area (see Section 7.2), it ay be acceptable to use a proration syste for gas well production instead of having easureent for every well. If a proration syste is ipleented, all wells in the battery ust be subject to the proration syste Exeptions Gas wells ay be produced without individual well easureent and be connected to a proration battery without Regulator site-specific approval if all the qualifying criteria in Section are et and no application is required Qualifying Criteria 1. All wells are classified as gas wells. 2. All freehold owners are notified without consideration of the coonality of their interest. 3. All wells flowing to the battery: August 1, 2017 Page 5-5

133 a. have coon ownership, and where there is no coon ownership, written notification has been provided to all working interest participants and no objections have been received; b. have coon Crown or Freehold royalty, and where the wells are producing Freehold inerals and the Freehold ownership is not coon, written notification has been provided to all Freehold owners and no objections have been received 4. The licensee has discussed and addressed reservoir engineering issues with its own reservoir engineering staff or external knowledgeable personnel to ensure inial reservoir engineering concerns and has docuented the results for audit. 5. Total liquid production at each well in the battery is 2 3 /d based on the onthly average flow rates recorded during the six onths prior to conversion. If a group of new wells not previously on production are to be constructed as a proration battery, the qualifying flow rates ust be based on production tests conducted under the anticipated operating conditions of the proration battery. 6. The axiu average daily well gas flow rate of all wells in the battery is /d including gas equivalent volue of condensate, with the highest daily well flow rate including gas equivalent volue of condensate and except as allowed below in ite 9. If an existing battery with easured gas well production is being converted to a proration battery, qualifying flow rates ust be based on the onthly average flow rates recorded during the six consecutive onths prior to conversion. If a group of new wells not previously on production are to be constructed as a proration battery, the qualifying flow rates ust be based on production tests conducted under the anticipated operating conditions of the proration battery. 7. Periodic well tests are conducted under noral operating conditions to deterine hourly flow rates that will be used to estiate onthly well production based on onthly well operating hours. The well tests are conducted for a iniu of 12 hours, and all gas, condensate, and water volues are separated and easured during the test. For gas wells with inial water production of water/ gas and no condensate or oil, the testing duration ust be sufficient to clearly establish stabilized flow rates and single-phase testing is allowed. 8. Following the coenceent of production at the proration battery, all wells are tested within the first onth, then again within six onths, and then annually after that. New wells added to the battery at soe future date ust be tested within the first onth of production, then again within six onths, and then annually after that. 9. For new wells tying into a gas proration battery and that will be producing ore than /d but that are expected to drop below /d within six onths, every well ust be tested onthly for the first six onths with a separator or until the production rate has stabilized and annually thereafter. If the gas production rate for any of the wells is ore than /d after six onths of production or the liquid production rate is higher than 2 3 /d, a separator ust be installed to continuously separate and easure the well production, and the easureent-by-difference rules in Section 5.5 apply in this scenario. 10. August 1, 2017 Page 5-6

134 SK AB BC This qualifying criteria does not apply in Saskatchewan For coalbed ethane (CBM) wells and wells producing fro above the base of groundwater protection each with water production water/ gas and no condensate, if at any tie ore than /onth of net water production is realized at the group easureent point, the operator ust investigate the source of the water production by retesting and using at least a two-phase separator at the suspected gas well(s) within 30 days and then prorate the water production accordingly. Not Applicable 11. The flow rates established fro the well tests are used to deterine estiated onthly well production fro the date of the test until the date of the next test, except that the test conducted during the first onth of production is also used to estiate the wells production for the producing days prior to the test. The total easured group gas and liquid production are prorated to the wells, based on each well s estiated production, to deterine the actual well production Revocation of Exeptions If any of the following scenarios exists or occurs, the exeption is revoked: 1. An oil well is added to the battery, or one or ore of the existing gas wells has been reclassified as an oil well. 2. The axiu average daily flow rate of all wells in the battery for any onth exceeded /d, or the highest single well flow rate exceeded /d except as allowed in Section , ite Total liquid volue exceeded 2 3 /d during a 24 hour test period or prorated to 24 hours if the test period is not 24 hours. 4. A new well has been added to the proration battery with a daily flow rate over except as allowed in Section ite 9 or whose additional volue will cause the average daily well gas flow rate of all wells in the battery to exceed /d. 5. Wells within the proration battery or new wells added to the battery were not tested as required. 6. The gas proration ethodology in ite 11 under Qualifying Criteria in Section was not followed. Base easureent requireents ust be reinstated if the exeption is revoked due to any of the scenarios listed above. Applications The following inforation ust be subitted with an application to use a proration syste, instead of individual gas well easureent, to deterine gas well production if the criteria in Section are not et: 1. All of the inforation listed in Section 5.2; August 1, 2017 Page 5-7

135 2. A discussion of the stage of depletion for pools involved and the ipact of any reduction in well easureent accuracy that ay result fro gas proration as it relates to reservoir engineering data needs - discussion of this atter by the licensee with its own reservoir engineering staff or knowledgeable external personnel is required and ust be addressed in the application; 3. A clear explanation and flow diagra of proposed well and group easureent devices and locations, the proposed accounting and reporting procedures, and the proposed ethod and frequency of testing; 4. If there is no coon ownership or no coon Crown or Freehold royalty, docuentation to address royalty and equity issues deonstrating that written notification was given to all Freehold ineral owners and working interest participants, with no resulting objection received Considerations for Site-specific Approval 1. All wells ust be classified as gas wells. 2. There are inial equity, royalty, and reservoir engineering concerns. 3. All wells should have siilar flow rates. 4. Econoic considerations: Would ipleentation of a proration syste reduce costs enough to significantly extend operations? Have other options been considered? 5. Total liquid production at each well in the battery should be 2 3 /d based on the onthly average flow rates recorded during the six onths prior to conversion. If a group of new wells not previously on production are to be constructed as a proration battery, the qualifying flow rates ust be based on production tests conducted under the anticipated operating conditions of the proration battery. 5.5 Measureent by Difference Measureent by difference (MbD) is defined as any situation where an uneasured volue is deterined by taking the difference between two or ore easured volues. It results in the uneasured volue absorbing all the easureent error associated with the easured volues. In the scenario of a proration battery, either effluent easureent or periodic testing without continuous easureent, new gas or oil source errors ay be difficult to detect because the proration testing errors in the original syste can hide the new source errors. Despite these concerns, a properly designed and operated easureent syste can iniize the risk and attain reasonable accuracy, provided that the easured source gas or oil rates are a sall proportion of the total syste delivery rates. MbD is not allowed for ultiwell group batteries, single-well batteries, or sales points unless special approval is obtained fro the Regulator Gas Measureent by Difference For proration batteries, MbD can include, but is not liited to, the following scenarios. Note: All scheatics are exaples only; systes ay be configured differently. Scenario 1 August 1, 2017 Page 5-8

136 Separator Measured gas source(s) other than fro the designated SW Saskatchewan or SE Alberta Shallow Gas Stratigraphic Units or Zones or Area delivering into a Gas Multiwell Proration SW Saskatchewan or SE Alberta Battery (Figure 5.1): Figure 5.1 Test Taps SW Saskatchewan & SE Alberta Shallow Gas Wells Gas Well Test Taps Group Gas To Gathering Syste or Sales Gas Well Test Taps Gas Well Produced Water Gas Measured Gas Source Gas Well = easureent point Scenario 2 Measured gas source(s) delivering into a Gas Multiwell Proration Outside SW Saskatchewan or SE Alberta Battery (Figure 5.2): August 1, 2017 Page 5-9

137 Group Separator Figure 5.2 Gas Well Test Taps Test Taps Proration Gas Wells Outside SE Alberta & SW Saskatchewan Shallow Gas Zones/Areas Group Gas To Gathering Syste or Sales Gas Well Test Taps Group Condensate Gas Well Gas Measured Gas Source Produced Water Gas Well = easureent point Scenario 3 Measured gas source(s) delivering into a gas ultiwell effluent easureent battery with battery condensate separated, etered and recobined with battery gas (Figure 5.3): Figure 5.3 Gas Well A Gas Well B Wet Measureent Line Heater Wet Measureent Wet Measureent Group Gas Group Condensate Water Disposal To Gas Gathering Syste Gas Well C Gas Measured Gas Source Gas Well D = easureent point Scenario 4 Measured gas source(s) delivering into a gas ultiwell effluent easureent battery with battery condensate separated and sent to a tank for disposition to sales. (Figure 5.4): Note August 1, 2017 Page 5-10

138 Group that this scenario can also occur at gas ultiwell proration batteries outside SW Saskatchewan or SE Alberta. In this scenario, the condensate fro the easured gas source ay be reported as a liquid condensate disposition to the effluent battery, rather than being included in the easured gas volue. If this reporting option is used, the following conditions ust be adhered to: 1. MbD ratios and qualifying criteria for both gas and oil (condensate) are applicable at the effluent battery (see Section 5.5.3). 2. The condensate eter at the easured gas source ust eet delivery point easureent requireents and be proven to base conditions. 3. A live condensate saple and analysis ust be obtained at the easured gas source and used to conduct a flash siulation analysis to calculate a GIS at the easured gas source. The liquid condensate disposition fro the easured gas source will be the etered condensate and the gas disposition will be the etered gas volue plus the calculated GIS. 4. The effluent battery condensate production will be the battery disposition inus the easured gas source condensate receipt plus change in inventory. Figure 5.4 Gas Well Gas Well Wet Measureent Line Heater Wet Measureent Wet Measureent Group Gas Water Disposal Condensate Disposition To Gas Gathering Syste Gas Well Gas Measured Gas Source Gas Well Water Disposal = easureent point Scenario 5 Measured gas source(s) delivering into an oil ultiwell proration battery (Figure 5.5): August 1, 2017 Page 5-11

139 Group Test Group Figure 5.5 Flare Gas Well Oil Well Measured Gas Source Treater Fuel Copressor Oil Storage Vented Gas Oil Sales Gas to Gathering Syste, Gas Plant or Sales Oil Well Oil Well Water Storage Water Disposal = easureent point For the easured gas source(s), the applicable condensate etering and reporting option described in Table 5.6 in Section ust be used. Scenario 6 Measured oil facility delivering gas into a gas proration battery (Figure 5.6): Figure 5.6 Gas Well A Wet Measureent Line Heater Wet Measureent Group Gas Group Condensate To Gas Gathering Syste Gas Well B Wet Measureent Water Disposal Gas Well C Oil Battery Gas fro Oil Battery Measured Gas Source = easureent point Measured Gas Source into Gas Proration Battery If any easured gas source will be tied into a gas proration battery: 1. The gas and liquids fro all tied-in gas sources ust be separately and continuously etered. If the R ratio in Table 5.1 cannot be et, the operator ay consider the August 1, 2017 Page 5-12

140 tied-in easured gas wells as continuous or 31-day test and include the as part of the gas proration battery. However, these wells ust be tagged as continuous test. 2. The onthly gas volue, including the GEV of condensate where appropriate, received fro a tied-in easured gas source and any other receipts ust be subtracted fro the total onthly battery disposition gas volue including GEV of condensate where appropriate to deterine the battery onthly gas production volue. 3. Table 5.1 indicates when gas easureent by difference ay be acceptable by exeption and when subission of an application ay be required. Table 5.1 Prorated gas flow rate (excluding all easured gas source) R* Application Required /d < 1.00 No > /d 0.35 No > /d > 0.35 and 0.75 No** > /d > 0.75 Yes * Ratio of volue of all tied-in easured gas volues (including GEV of condensate where applicable) to the total battery gas disposition volue (including fuel, flare, and vent volues). ** Must eet additional qualifying criteria, see Section Measured Gas Source into Oil Proration Battery If any easured gas source is tied in to an oil battery: 1. The gas and liquids fro the tied-in gas source(s) ust be separately and continuously etered. 2. The onthly gas volue (including, where appropriate, the GEV of the portion of the condensate that will flash into the gas phase at the battery) received fro a tied-in easured gas source and any other receipts ust be subtracted fro the total onthly oil battery gas disposition volue to deterine the onthly battery gas production volue. See Table 5.6 for reporting options. 3. If condensate is received fro a tied-in easured gas source, the portion of the onthly condensate volue that will reain in a liquid state at the oil battery ust be subtracted fro the battery total onthly oil battery disposition (plus/inus inventory changes and inus any other receipts) to deterine the onthly battery oil production volue. See Table 5.6 for reporting options. August 1, 2017 Page 5-13

141 Test Group Test Scenario 1 Figure 5.7. Measured gas coing into oil battery with easureent by difference Sweeet Oil Well Test Meter A Measured Gas MbD Proration Oil Battery Gas Gathering Systes Sweeet Oil Well M Sweet Oil Well Test Meter B Treater Fuel Oil Storage Vent Gas M Oil Sales to Pipeline Sweet Oil Well Sweet Oil Well Water Storage M Disposal M = battery receipt/disposition easureent point = easureent point Facility delineation in Figure 5.7 is deterined by where the easured gas enters the oil battery relative to where the oil battery gas is easured. To calculate actual battery gas production: Total battery gas disposition to the gas gathering syste is the etered volue after copression. The battery gas production is calculated by subtracting the easured gas receipt volues fro the su total of the battery disposition to the gas gathering syste fuel, flare, and vent. The resultant battery gas production volue is then prorated to the flowlined oil wells. The aount of easured gas that can be delivered into the oil battery is liited by the easureent by difference (MbD) percentage in Section 5.5. To calculate battery oil production: If the easured gas streas have condensate, see Section 5.5.1, Table 5.6 and Section 14.3 on how to calculate and report blending shrinkage, flashing shrinkage, disposition, and receipt. August 1, 2017 Page 5-14

142 Test Group Separator Test Scenario 2 Figure 5.8. Measured gas battery delivering hydrocarbon liquids and water to an oil battery Test Meter A Flare Report as DISP at gas BT & REC at oil BT Sweeet Oil Well Sweeet Oil Well Sweet Oil Well Test Meter B Proration Oil Battery Group M Gas Gathering Systes (GS) M Treater Battery Fuel fro GS M Vent Gas Oil Storage M M M Oil Sales Gas Battery M Sweet Oil Well Sweet Oil Well Water Storage M Disposal M = battery receipt/disposition easureent point = easureent point To calculate actual oil battery gas production: The su total of the group separator and treater gas is prorated back to flowlined oil wells. The gas etered off the separator at the easured gas battery is reported as a delivery to the gathering syste. This is a preferred scenario as there is no gas easureent by difference restriction, but oil easureent by difference still applies to the easured condensate delivered to the oil battery. Condensate Receipt into Oil Battery: Condensate easured at the gas battery separator ay be reported as a liquid disposition, a GEV disposition, or a cobination of both (depending on the coposition and volue) fro the gas facility into the oil battery. See Section , Table 5.1 and Section , Table 5.2 and Section 14.3 on exeptions and how to calculate and report blending shrinkage, flashing shrinkage, disposition, and receipt. 4. Table 5.2 indicates when gas easureent by difference ay be acceptable by exeption and when subission of an application ay be required. Table 5.2 Prorated gas flow rate (excluding all easured gas source) R* Application Required /d < 1.00 No > /d 0.35 No > /d > 0.35 and 0.75 No** > /d > 0.75 Yes * Ratio of volue of all tied-in easured gas volues (including GEV of condensate where applicable) to the total battery gas disposition volue (including fuel, flare, and vent volues). ** Must eet additional qualifying criteria, see Section August 1, 2017 Page 5-15

143 Test Group Separator Measured Gas Source into Single-Well Battery Where a easured gas source will be tied into a single-well battery, as shown in Figure 5.9, this situation does not qualify for an exeption, and an application ust be subitted to and approved by the Regulator prior to ipleentation. Figure 5.9 Gas Oil or Condensate Gas Gathering Syste, Gas Plant, or Sales Oil or Gas Well (no easureent ) Produced Water Measured Gas Source = easureent point Oil Measureent by Difference For oil streas, easureent by difference can include but is not liited to the following scenarios. Scenario 1 Measured oil and/or oil-water eulsion fro a battery delivering into an oil proration battery by truck (Figure 5.10): Figure 5.10 Measured Oil Source Oil/ Eulsion Storage Copressor Flare To Gas Gathering Syste Sweet Oil Well Treater Fuel Oil Storage Vented Gas OIl Sales to Pipeline Sweet Oil Well Sweet Oil Well Water Storage Water Disposal = easureent point August 1, 2017 Page 5-16

144 Test Group Group Scenario 2 Measured oil and/or oil-water eulsion (and gas if applicable) under pressure fro a battery delivering into an oil proration battery by pipeline (Figure 5.11): Figure 5.11 Battery A Battery A Oil Wells Battery B Water Disposal To Gas Gathering Syste Measured Oil/ Gas Source Treater Vapour Recovery Unit Oil Storage Oil Sales Oil Well Oil Well Battery B Oil Wells Water Storage Disposal Oil Well = easureent point Scenario 3 Measured oil and/or eulsion fro a easured gas source delivering into a gas proration battery or gas plant (Figure 5.12): For specific easureent and reporting inforation, see Section #8. Figure 5.12 Gas Well Test Taps Test Taps Proration Gas Wells Outside SE Alberta & SW Saskatchewan Shallow Gas Zones/Areas Group Gas To Gathering Syste or Sales Gas Well Test Taps Separator Group Condensate Water Disposal Gas Well Gas Measured Gas Source Produced Water Gas Well = easureent point Water Disposal August 1, 2017 Page 5-17

145 Measured Oil and/or Oil-Water Eulsion Source into Oil Battery If any easured oil and/or oil-water eulsion source will be delivered to a battery including trucked-in volues: 1. Measured oil and/or oil-water eulsion delivery/receipt volues ust be deterined using equipent and/or procedures that eet delivery point easureent uncertainty requireents. In the scenario of oil-water eulsions, the easureent uncertainty requireents apply to total volue deterination only. 2. Measured oil volues ust be deterined and reported at base conditions. 3. The liquids received fro the easured oil and/or oil-water eulsion source(s) ust be subtracted fro the total onthly battery oil and water disposition volues plus/inus inventory changes and inus any other receipts to deterine the onthly battery oil and water production volues. 4. Table 5.3 indicates when oil easureent by difference is acceptable by exeption and when subission of an application is required. Table 5.3 Measured oil delivery/receipt volue R* Application Required /onth Not applicable No > /onth 0.25 No > /onth 0.25 < R 1.00 No** > /onth > 1.00 Yes * Total easured oil delivery/receipt volue divided by the onthly battery oil production ** Must eet additional qualifying criteria, see Section Consideration should be given to incorporating pipeline easured oil and/or oilwater eulsion source(s) delivered by pipeline as a satellite of the battery if the battery is an oil proration battery and including it in the battery s proration syste. In that scenario, easureent by difference would be avoided. A pipelined single oil well or oil wells in a ultiwell group ay also be considered as continuous or 31- day test and included as part of the oil proration battery. However, wells ust be tagged as continuous test Exeptions Measureent by difference is allowed without Regulator site-specific approval if all of the applicable criteria in this section are et. If the easureent by difference will involve existing production, initial qualifying flow rates ust be based on average calendar daily flow rates (onthly flow rate divided by nuber of production hours in the onth ultiplied by 24) recorded during the six onths prior to ipleentation of the easureent by difference. If new easured production is to be connected to a proration battery, the qualifying flow rates ust be based on production tests conducted under the anticipated operating conditions. August 1, 2017 Page 5-18

146 Group Exeptions for All Measured Gas Streas For easured gas source(s) fro either gas or oil batteries tied into a gas proration battery or an oil battery Qualifying Criteria 1. Voluetric criteria for easured gas tying into a proration battery Table 5.4 Prorated gas flow rate (excluding all easured gas source) R* /d < 1.00 > Ta 3 /d 0.35 > /d 0.35 < R 0.75** *R: Ratio of volue of all tied-in easured gas (including GEV of condensate where applicable) to the total gas disposition volue fro the receiving battery (including fuel, flare and vent volues). ** Additional l qualifying criteria apply, see Section Exaple: Figure 5.13 Gas Well A Gas Well B Wet Measureent Line Heater Wet Measureent Wet Measureent Group Gas Group Condensate V gtot Water Disposal To Gas Gathering Syste Gas Well C Gas V gnew Measured Gas Source Gas Well D = easureent point For the gas battery in Figure 5.13, V gtot = /d (total of easured gas and GEV of condensate delivered out of the battery, including volues received fro Gas Well D) V gnew = /d (total of easured gas and GEV of condensate delivered to the battery fro Gas Well D) Prorated gas flow rate = V gtot V gnew = = /d August 1, 2017 Page 5-19

147 R = 30/100 = 0.3 Since the prorated flow rate is above /d and R is below 0.35 for the Gas Well D tie-in, it is within the acceptable exeption range. 2. All proration wells flowing to the battery: a. have coon working interest ownership, and where there is no coon ownership, written notification has been provided to all working interest participants and no objections have been received; b. have coon Crown or Freehold royalty, and where the wells are producing Freehold inerals and the Freehold ownership is not coon, written notification has been provided to all Freehold owners and no objections have been received. 3. The gas and liquid phases fro the tied-in easured gas source(s) are separately and continuously etered. 4. Gas volues received at a gas battery fro the tied-in easured gas source(s) include the GEV of the easured condensate volues if the condensate is recobined with the easured gas volues fro the new tied-in gas source. 5. If the tied-in easured gas source(s) produces condensate and is connected by pipeline to an oil battery, the applicable condensate etering and delivery/reporting options descibed in Table 5.6 in Section ust be used. 6. In the scenario of an oil battery or a gas proration battery, the onthly gas volue, including the GEV of condensate. Where appropriate, received fro a tied-in easured gas source and any other receipts, is subtracted fro the total onthly battery gas volue, including the GEV of condensate, where appropriate, to deterine the onthly battery gas production volue. 7. In the scenario of an oil battery, the onthly liquid condensate volue, where appropriate, received fro a tied-in easured gas source, is subtracted fro the total onthly oil disposition, plus inventory changes, shrinkage, if applicable, and inus any other receipts, to deterine the onthly battery oil production volue. 8. Oil and/or eulsion fro a tied-in easured gas source ay be delivered to a gas proration battery, or gas plant in accordance with the following: a. The oil or eulsion ust be easured with a eter proved to stock tank conditions b. A live oil saple ust be taken annually and a ultiphase flash liberation or coputer siulation ust be perfored in order to deterine the GIS factor of the entrained gas in the oil which ust be added to the easured gas volue. c. The oil or eulsion disposition ust be reported as a liquid oil volue and kept whole, as it is reported through the gathering syste and gas plant. d. Blending shrinkage requireents in Section ust be adhered to. August 1, 2017 Page 5-20

148 e. The oil and gas MbD exception qualifying criteria set out in Section ust be adhered to Additional Qualifying Criteria: 0.35 < R Single point easureent uncertainty of the easured gas source gas eter and of the prorated battery group gas eter ust be 2.0%. EFM ust be installed on both the gas and condensate eters at the easured gas source eter(s) and the proration battery group separator. Gas proration factor targets, as set out in Table 3.1 ust be aintained. Potential reservoir engineering/anageent concerns have been considered and deterined to be acceptable Revocation of Exeptions: R 0.35 If any of the qualifying criteria specified in Section is not adhered to, then an exeption is revoked. Base easureent requireents ust be reinstated if an exeption is revoked Revocation of Exeptions: 0.35 < R 0.75 If any of the qualifying criteria in Section or the additional qualifying criteria in Section is not adhered to, then an exeption is revoked. However, if the gas proration factor at the proration battery exceeds the proration factor targets as set out in Section 3.1.1, then the operator ust take steps to bring the proration factor back within range within two onths after the initial violation onth. If the gas proration factor cannot be restored to within the target range within two onths, the exeption is revoked and the operator ust restore the R factor to 0.35 or lower or obtain a site specific approval. Base easureent requireents ust be reinstated if an exeption is revoked Exeption for Measured Oil Receipts Received by Truck or Pipeline at an Oil Proration Battery Qualifying Criteria 1. Voluetric Criteria for Measured Oil Delivered by Truck or Pipeline to an Oil Proration Battery: Table 5.5. Measured Oil Delivered by Truck or Pipeline to an Oil Proration Battery Measured oil delivery/receipt volue R* /onth Not applicable > /onth 0.25 > /onth 0.25 < R 1.00** * Total easured oil delivery/receipt volue divided by the onthly battery oil production ** Additional qualifying criteria apply, see Section August 1, 2017 Page 5-21

149 2. The onthly battery oil and water production volues are deterined by subtracting the onthly easured oil and water receipt volues fro the total onthly battery oil and water disposition volues plus inventory change and inus any other receipts. 3. All wells linked to the proration oil battery (the proration wells): a. have coon working interest ownership, and where there is no coon ownership, written notification has been provided to all working interest participants and no objections have been received; b. have coon Crown or Freehold royalty, and where the wells are producing Freehold inerals and the Freehold ownership is not coon, written notification has been provided to all Freehold owners and no objections have been received. 4. If easured gas fro a easured live oil/eulsion production source is also coingled with the production at an oil battery (pipelined receipt), the exeption criteria for gas easureent by difference ust also be et Additional Qualifying Criteria: 0.25 < R Delivery point easureent ust be installed at the proration battery to eter the easured oil receipts (trucked in or pipelined) and the delivery point easureent uncertainty is 0.5%, irrespective of the daily volue of the etered receipts. 2. Oil (and gas if applicable) proration factor targets, as set out in Table 3.1 ust be aintained. 3. Proving requireents and frequency for the delivery point easureent devices ust be adhered to. 4. Blending requireents in Section ust be adhered to. 5. Potential reservoir engineering/anageent risks have been considered and deterined to be acceptable Revocation of Exeptions: R 0.25 If any of the qualifying criteria specified in Section are not adhered to then an exeption is revoked. Base easureent requireents ust be reinstated if an exeption is revoked. If an exeption is revoked, the operator ust: 1. Deliver all oil receipts over /onth elsewhere; 2. Set up another treater train with separate receipt easureent, tankage, and disposition easureent to process the trucked in or pipelined receipts prior to coingling with the battery production; or 3. Obtain Regulator site specific special approval to continue Revocation of Exeptions: 0.25 < R 1.00 If any of the qualifying criteria in Section or the additional qualifying criteria in Section are not adhered to, then an exeption is revoked. August 1, 2017 Page 5-22

150 Test Group Group However, if the oil (and gas if applicable) proration factor(s) at the proration battery exceeds the proration factor targets as set out in Table 3.1, then the operator ust take steps to bring the proration factors back within range within two onths after the initial violation onth. If the proration factors cannot be restored to within the target range within two onths, the exeption is revoked and the operator ust restore the R factors to 0.25 or lower for oil and 0.35 or lower for gas or obtain a site specific approval to continue. Base easureent requireents ust be reinstated if an exeption is revoked. If an exeption is revoked the operator ust: 1. Deliver all oil receipts over /onth elsewhere; 2. Set up a treater train with separate receipt easureent, tankage, and disposition easureent to process the trucked in or pipelined receipts prior to coingling with the battery production; or 3. Obtain Regulator site specific approval to continue. Figure Oil Syste Exaple Battery A Battery A Oil wells Battery B Water Disposal To Gas Gathering Syste Measured Oil/ Gas Source Treater Vapour Recovery Unit Oil Storage Oil Sales Oil Well Oil Well Battery B Oil Wells Water Storage Disposal Oil Well = easureent point Note that with the addition of Battery A production, if the easureent by difference eets all the qualifying criteria and the total oil delivery volue at Battery B is over /d, the delivery volue ust be deterined by a easureent device(s) and/or procedures having ±0.5% uncertainty, which ight require changes in easureent equipent and/or procedures at Battery B. For this exaple (Figure 5.14), given the following data: Battery A oil production volue = /d Battery B oil production volue = /d before tying in Battery A Battery A gas production volue = /d Battery B gas production volue = /d before tying in Battery A August 1, 2017 Page 5-23

151 Step 1: Calculate the onthly easured oil volue fro Battery A delivered to the proration battery (Battery B) and the percentage of the prorated oil production: Monthly easured oil production volue fro Battery A = /d x 30 days = Battery A oil volue as a percentage of Battery B oil production volue = 20 3 /d / /d = 22.2% Step 2: Calculate the R ratio for the coingled gas: R = 15.0/( ) = 0.43 Since the Battery A onthly easured oil volue is below /onth, the oil voluetric criteria are et. The gas R ratio is also below 0.75 so an application is not required in this case, provided all prequalifying criteria are et Applications The following inforation ust be subitted with an application to add easured gas or oil/eulsion sources to a prorated battery if the applicable qualifying criteria and additional qualifying criteria in Section are not et: 1. All of the inforation listed in Section 5.2; 2. A discussion of the stage of depletion for pools involved, and the ipact of any reduction in well easureent accuracy that ay result fro easureent by difference as it relates to reservoir engineering data needs; discussion of this atter by the proponent with its own reservoir engineering staff or knowledgeable external personnel is required and ust be addressed in the application; 3. If there is no coon ownership or no coon Crown or Freehold royalty, docuentation to address royalty and equity issues deonstrating that written notification was given to all Freehold ineral owners and working interest participants, with no resulting objection received Considerations for Site-specific Approval There are inial equity, royalty, and reservoir engineering concerns. Econoic considerations, including an assessent of whether ipleentation of a proration syste would reduce costs enough to significantly extend operations, and an assessent of the other options that have been considered. The gas and liquids fro the tied-in easured source(s) ust be separately and continuously easured. If the tied-in easured gas source(s) produces condensate and it is connected by pipleline to an oil battery, the licensee ust choose the applicable condensate delivery/reporting options fro Table 5.6: August 1, 2017 Page 5-24

152 Table 5.6. Options for condensate (diluent) delivery to an oil battery Condensate received at oil battery (fro all easured Condensate reporting options gas sources) /day and 5.0% of total prorated oil production > /day or > 5.0% of total prorated oil production 1. Prove the tied in easured gas source condensate eter to live conditions. 2. Obtain a live condensate liquid saple and send the saple to a lab for a liquid analysis (to C 30+ ). 3. Multiply the onthly etered condensate volue by the liquid volue fraction fro the analysis to derive the coponent volues. 4. Report the C 6+ (Hexane plus) as a liquid condensate disposition fro the easured gas source to the oil battery. 5. Most of the light ends (H 2 to NC 5 ) will flash out of the liquid condensate at the oil battery treater. Add the light ends (H 2 to NC 5 ) coponent gas equivalent volues to the dry flow easured gas coponent volues and report this as the total gas disposition fro the easured gas source to the oil battery. 1. Prove the tied in easured gas source condensate eter to live conditions. 2. Obtain a live condensate liquid saple (to C 30+ ) and perfor a coputer flash siulation to deterine how uch gas will flash out of the condensate at each production stage, (i.e. separator and treater) at the oil battery. This will allow for a shrinkage factor to be deterined. 3. Report the condensate stock tank volue derived fro the etered condensate volue and the siulation shrinkage factor as a liquid disposition fro the easured gas source to the oil battery. 4. The flash siulation will also derive the volue and coposition of the light ends that will flash out of the condensate at each production stage within the battery. Add the light end (flashed) condensate coponent gas volues to the dry flow easured gas coponent volues and report this as the total gas disposition fro the easured gas source to the oil battery. 5. If there are changes to the process (teperature, pressure) at either the easured gas source or oil battery, or if the easured gas source has new richer or leaner wells tied in, a new condensate saple ust be obtained and a new coputer flash siulation conducted. August 1, 2017 Page 5-25

153 In the scenario of an oil battery or a gas proration battery, the onthly gas volue including GEV of condensate where appropriate received fro a tied-in easured gas source and any other receipts ust be subtracted fro the total onthly battery gas volue including GEV of condensate where appropriate to deterine the onthly battery gas production volue. In the scenario of an oil battery, the onthly liquid condensate, oil, or oil-water eulsion volue, where appropriate, received fro a tied-in easured source ust be subtracted fro the total onthly oil and/or water disposition plus/inus inventory changes and inus any other receipts to deterine the onthly battery oil and/or water production volue Fuel Gas Measureent by Difference Section (12) describes the requireents for fuel gas easureent and reporting at sites where there ay be ultiple facility reporting codes and the fuel gas consuption is > /d. Situations ay occur where fuel gas is etered and consued at one site and soe of the etered fuel gas is then sent to another site (separate geographic location) where it is consued (see Figure 5.15). Three acceptable fuel gas MbD scenarios are described below. Figure 5.15 Oil Battery BT Copressor Fuel Meter #2 Separator Oil Wtr Test Taps Fuel Meter #1 Fuel Meter #3 Gas Well Gas Well Gas Well = etering point Gas Well Gas Well Gas Proration Battery BT Separator Group Gas Meter Copressor Produced Condensate Produced Water 1. Site fuel gas at BT is easured at fuel eter #1. The volue of fuel gas sent to BT is /d, and the volue of fuel gas consued at the copressor at BT is > /d. In this case, fuel gas MbD is acceptable for the reported fuel gas BT , and the reported fuel gas at BT will equal fuel eter #1 inus fuel eter #2. If the fuel gas sent to BT is > /d and the fuel gas consued at the copressor at BT is /d then fuel gas MbD is acceptable for the reported fuel gas at BT , August 1, 2017 Page 5-26

154 and the reported fuel gas at BT will equal fuel eter #1 inus fuel eter #3. 2. Site fuel gas at BT is etered at fuel eter #1. The volue of fuel gas sent to BT is > /d, and the volue of fuel gas consued at the copressor at BT is > /d. In this case, MbD is acceptable for the fuel gas used at either BT or BT ; depending on which site is expected to have the higher reported fuel gas volue. If the fuel gas volue at BT will be less than the fuel gas volue at BT , then fuel gas MbD is acceptable for BT , and the reported fuel gas at BT will equal fuel eter #1 inus fuel eter #2. If the fuel gas volue at BT will be less than the fuel gas volue at BT , then fuel gas MbD is acceptable for BT , and the reported fuel gas at BT will equal fuel eter #1 inus fuel eter #3. 3. Site fuel gas at BT is easured at fuel eter #1. The onthly volue of fuel gas sent to BT is < /d, and the onthly volue of fuel gas consued at the copressor at BT is < /d. In this case, reported fuel gas volues for BT and BT ay be prorated fro the etered onthly fuel gas volue at fuel eter #1 and will be based on each battery s percentage of the total estiated onthly fuel gas volues at both batteries. For exaple, reported onthly fuel gas volues at BT = fuel eter #1 BT estiated fuel (BT estiated fuel + BT estiated fuel). Battery fuel gas estiates should be based on sound engineering estiates. 5.6 Surface Coingling of Multiple Gas Stratigraphic Units or Zones or Wells If gas wells have been copleted in ultiple stratigraphic units or zones and those stratigraphic units or zones are segregated in the wellbore and produced separately to surface or if there are ultiple individual gas wells on the sae surface location, production fro each stratigraphic unit or zone or each well usually has to be easured separately prior to coingling. Where applicable, such stratigraphic units or zones or wells ay be coingled at surface prior to the cobined production being easured, if the qualifying criteria in Section are et or upon Regulator approval of an application. Proportionate onthly production volues ust still be deterined and reported for each stratigraphic unit or zone or well, in accordance with the applicable criteria and considerations described in Sections and The following criteria and considerations do not apply to wells that qualify for the Gas Multiwell Proration SW Saskatchewan and SE Alberta Battery procedures if specific stratigraphic units or zones are approved (without application) for coingling in the wellbore. Coingling of stratigraphic units or zones in the wellbore require approval fro the Regulator. August 1, 2017 Page 5-27

155 5.6.1 Exeptions Surface coingling of two gas stratigraphic units or zones in a gas well or separate gas wells on the sae surface location prior to easureent is allowed without Regulator sitespecific approval if all the qualifying criteria in Section are et and no application is required Qualifying Criteria Both stratigraphic units or zones or wells: a. have coon working interest ownership, and where there is no coon ownership, written notification has been provided to all working interest participants and no objections have been received; b. have coon Crown or Freehold royalty, and where the wells are producing Freehold inerals and the Freehold ownership is not coon, written notification has been provided to all Freehold owners and no objections have been received. Monthly average of total liquid production fro both stratigraphic units or zones is 2 3 /d. The cobined daily flow rate of both stratigraphic units or zones or wells is , including GEV of condensate (if recobined). If the stratigraphic units or zones or wells to be coingled will involve existing production, initial qualifying flow rates are based on onthly average flow rates recorded during the six onths prior to ipleentation of the coingling. If new stratigraphic units or zones/wells are to be coingled, the initial qualifying flow rates are based on production tests conducted under the anticipated operating conditions. Shut-in wellhead pressure of the lower pressure stratigraphic zone/well is 75% of the shut-in wellhead pressure of the higher-pressure stratigraphic unit or zone. The cobined production fro both stratigraphic units or zones/wells is easured continuously. Separation before easureent is required for both phases. Check valves are installed on each flow line upstrea of the coingling point. Testing requireents: a. Each stratigraphic unit or zone or well ust be tested once per onth for the first six onths after coingling, then annually thereafter, and/or iediately following any significant change to the producing conditions of either stratigraphic unit or zone or well. b. The tests ust be conducted for at least 24 hours and ust involve the separation and easureent of all gas and liquid production. c. If condensate is recobined with the gas production of the coingled stratigraphic units or zones or wells, a saple of the condensate ust be taken annually and analyzed and used to deterine the factor to be used to deterine the GEV. d. The tests for both stratigraphic units or zones or wells ust be done consecutively with stabilization periods. August 1, 2017 Page 5-28

156 Separator e. Any of the three test ethods ay be used. Methods (i) and (ii) are preferred given the testing is conducted under noral flowing conditions is perfored without shutting in stratigraphic units or zones or wells, so that inial stabilization tie is required. i. Test taps ust be installed upstrea of the coingling point but downstrea of the check valve so that a test separator unit can be hooked up to test each stratigraphic unit or zone or well individually (Figure 5.16). Test Method (i) Figure 5.16 Flowing Gas Well Zone A (Tubing) Test Taps Zone B (Casing or Another Tubing) Gas Metered & Recobined Condensate To Gas Gathering Syste Test Taps Produced Water = easureent point ii. Install peranent bypasses or taps to hook up teporary bypasses downstrea of the check valve so that one stratigraphic unit or zone or well will be bypassing the existing separation and etering equipent while the other stratigraphic unit or zone or well is tested using the existing equipent. Note that the production fro the bypassed stratigraphic unit or zone or well ust be estiated based on the production test rates (Figure 5.17). Test Method (ii) August 1, 2017 Page 5-29

157 Separator Figure 5.17 Flowing Gas Well Zone A (Tubing) Zone B (Casing or Another Tubing) Separator/ Meter Bypass Lines Gas Metered & Recobined Condensate To Gas Gathering Syste Produced Water = easureent point 8. iii. Shut in one producing stratigraphic unit or zone at a tie and use the existing separation and easureent equipent to test each stratigraphic unit or zone or well individually after stabilization. The production rates deterined for each stratigraphic unit or zone or well by the periodic tests ust be used to estiate the onthly production for each stratigraphic unit or zone or well fro the date they are conducted until the date the next test is conducted. The onthly easured cobined production ust be prorated to each stratigraphic unit or zone or well based on the estiates, and those prorated volues ust be reported as the onthly production for each stratigraphic unit or zone or well Revocation of Exeptions If any of the following scenarios exists or occurs, the exeption is revoked: 1. The cobined production fro both stratigraphic unit or zones or wells was not easured continuously or there was no separation before easureent. 2. Check valves were not installed on each flow line upstrea of the coingling point. 3. Testing requireents in ite 7 under Qualifying Criteria in Section were not followed. 4. The gas proration ethodology in ite 8 under Qualifying Criteria in Section was not followed. Base easureent requireents ust be reinstated if the exeption is revoked due to any of these scenarios. Applications The following inforation ust be subitted with an application to coingle production at surface prior to easureent fro ultiple stratigraphic units or zones in a gas well or ultiple wells on the sae surface location if the qualifying criteria in Section are not et: August 1, 2017 Page 5-30

158 1. All of the inforation listed in Section 5.2; 2. Shut-in and proposed operating pressures at the wellhead for all stratigraphic units or zones or wells; 3. Operating pressure for the gathering syste at the well s easureent point; 4. Proposed testing procedures to deterine the individual stratigraphic unit or zone or well production rates; 5. Proposed accounting procedures for prorating total volues to the individual stratigraphic units or zones or wells; and 6. All wells flowing to the battery: a. have coon working interest ownership, and where there is no coon ownership, written notification has been provided to all working interest participants and no objections have been received; b. have coon Crown or Freehold royalty, and where the wells are producing Freehold inerals and the Freehold ownership is not coon, written notification has been provided to all Freehold owners and no objections have been received Considerations for Site-specific Approval 1. Generally, there is 2 3 /day of total liquid production fro all stratigraphic units or zones or wells. 2. All stratigraphic units or zones or wells ust be classified as gas stratigraphic units or zones or wells. 3. There are inial equity, royalty, and reservoir engineering concerns. 4. The cobined production of all stratigraphic units or zones or wells ust be continuously easured. If there are gas and liquid coponents, they ust be separately easured. 5. Check valves ust be in place on the flow line upstrea of the coingling point. 6. Testing requireents: a. Each stratigraphic unit or zone or well ust be tested once per onth for the first six onths after coingling, then annually after that, and/or iediately following any significant change to the producing conditions of either stratigraphic unit or zone or well. b. The tests ust be conducted for at least 24 hours in duration and ust involve the separation and easureent of all gas and liquid production. c. If condensate is recobined with the gas production of the coingled stratigraphic units or zones or wells, a saple of the condensate ust be taken annually and analyzed and used to deterine the factor that will be used to deterine the GEV. d. The tests for all stratigraphic units or zones or wells ust be done consecutively, with stabilization periods. August 1, 2017 Page 5-31

159 e. Any of the three test ethods described in the exeptions in Section ay be used, with the consideration that ore than two stratigraphic units or zones or wells ay be involved. Methods (i) and (ii) are preferred, because the testing is conducted under noral flowing conditions without shutting in stratigraphic units or zones or wells, so that inial stabilization tie is required. The Regulator ay specify test procedures if specific circustances warrant the. 7. The production rates deterined for each stratigraphic unit or zone or well by the periodic tests ust be used to estiate the onthly production for each stratigraphic unit or zone or well fro the date they are conducted until the next test is conducted. The onthly easured cobined production ust be prorated to each stratigraphic unit or zone or well based on the estiates, and those prorated volues ust be reported as the onthly production for each stratigraphic unit or zone or well. August 1, 2017 Page 5-32

160 6 Non-Heavy Oil Measureent This section presents the base requireents and exeptions for non-heavy crude oil and eulsion easureents fro wells and batteries in the upstrea oil and gas industry that are used in deterining volues for reporting to Petrinex. The requireents for crude oil/eulsion volues transported by truck are detailed in Section 10. Non-heavy crude oil has the following characteristics: 1. It is a ixture ainly of pentanes and heavier hydrocarbons that ay be containated with sulphur copounds, 2. It is recovered or is recoverable at a well fro an underground reservoir, 3. It is liquid at the conditions under which its volue is easured or estiated, and 4. It has a density of less than 920 kg/ 3 at base conditions. 6.1 General Requireents Crude oil ay be found in association with water in an eulsion. In such scenarios, the total liquid volue ust be easured, and the relative volues of oil and water in the eulsion ust be deterined by obtaining and analyzing a representative saple of the eulsion, by using a product analyzer, or by other eans if applicable. Applications for which estiation of water content is appropriate e.g., inventory, are covered in ore detail later in this section. A licensee ust easure produced crude oil/eulsion volues by tank gauging, weigh scale, or eter unless otherwise stated in this Directive. The Regulator will consider an oil easureent syste to be in copliance if the base requireents detailed in Section 6.2 are et. The Regulator ay stipulate additional or alternative requireents for any specific situation based on a site-specific assessent and will infor licensees in writing of any additional or alternative requireents respecting their facilities General Measureent, Accounting, and Reporting Requireents for Various Battery Types General Accounting Forula Production = Total disposition + Closing inventory Opening inventory Total receipts Oil Batteries All wells in the battery ust be oil wells. Liquid production fro an oil battery ust be easured as an oil, water, or oil/water eulsion volue. This easureent ay be perfored at the battery site, a truck delivery/receipt point, or a pipeline delivery point. The eter factor obtained fro eter proving ust be applied to the eter volues until another prove is conducted. All wells in a ultiwell oil battery ust be subject to the sae type of easureent: easured or prorated. If there is a ixture of easured and prorated wells within the sae battery, the exeption criteria in Sections 5.5 ust be et or a Regulator site-specific approval ust be obtained. August 1, 2017 Page 6-1

161 Production fro gas batteries or other oil batteries cannot be connected to an oil proration battery upstrea of the oil proration battery group easureent point(s) unless specific criteria are et or Regulator site-specific approval is obtained as per Sections 5.5. For oil delivered to a gas syste, see Section Any oil well that produces fluids fro any stratigraphic unit is considered on production and a battery code is required to report the production on Petrinex even for a test. SK AB BC See Directive R01: Voluetric, Valuation and Infrastructure Reporting. See Manual 011: How to Subit Voluetric Data to the AER, Appendix 8 for load fluid reporting. Not Applicable Single-well Battery (Petrinex facility subtypes: 311 in SK and 311 and 331 in AB) Oil/eulsion ust be separated fro gas and easured. Multiwell Group Battery (Petrinex facility subtypes: 321 in SK and 321 and 341 in AB) Each well ust have its own separation and easureent equipent, siilar to a singlewell battery. All separation and easureent equipent for the wells in the battery, including the tanks but excluding the wellheads, ust share a coon surface location. Proration Battery (Petrinex facility subtypes: 322 in SK and 322 and 342 in AB) All well production is coingled prior to the total battery oil/eulsion being separated fro the gas and easured. Individual onthly well oil production is estiated based on periodic well tests and corrected to the actual onthly volue through the use of a proration factor. Double proration, whereby the proration oil battery disposition volue(s) is prorated to group/receipt easureent points and then further prorated to the wells (see Figure 6.1), is allowed without special approval subject to the following conditions: 1. All prorated oil/eulsion ust be easured using easureent systes that eet delivery point requireents before coingling with other oil/eulsion receipts. 2. All easured oil/eulsion receipts to the battery and the easured oil/eulsion production ust be prorated against the total oil and water disposition of the battery. August 1, 2017 Page 6-2

162 Test Group Figure 6.1 Truck/ Pipeline Meter (C) Oil/ Eulsion Storage Double Proration Accounting Copressor Flare To Gas Gathering Syste Fuel Sweet Oil Well Vented Gas Sales Meter (A) Treater Oil Storage OIl Sales Sweet Oil Well Eulsion Meter (B) Sweet Oil Well Water Storage Water Disposal = easureent point Sales oil and water disposition volues with inventory change ust be prorated to the total truck/pipeline volues easured and the total well eulsion volues easured (first proration). This proration using PF1 has to be done off-sheet and not reported on Petrinex. PF1 = [eter (A) + INVCL INVOP] [eter (B) + eter (C)] Prorated eter (B) volue = eter (B) x PF1 Prorated individual truck-in and/or pipeline volues = eter (C) volues for each load received x PF1 PF2 = prorated eter (B) volue total estiated production volue The prorated oil and water volue at the eulsion eter (B) is further prorated using PF2 (second proration) to the tested oil wells. The oil and water proration factors PF2 ust then be reported on Petrinex Gas Batteries Producing Oil All wells in the battery ust be gas wells. Oil production, receipt, disposition, and inventory volues ust be reported as liquid oil. Oil volues ust not be converted to a gas equivalent volue (GEV) and ust not be added to the gas volues. If oil is recobined with the gas and delivered to a gas plant through a gas gathering syste, the oil volue as deterined at the battery ust be reported as a receipt of OIL by the gas plant. The gas plant ust report the oil disposition as appropriate Single-well Battery (Petrinex facility subtype: 351) Oil/eulsion ust be separated fro gas and easured. August 1, 2017 Page 6-3

163 Multiwell Group Battery (Petrinex facility subtypes: 361 in SK and 361 and 365 in AB) Each well ust have its own separation and easureent equipent, siilar to a singlewell battery and its gas production ust be connected by pipeline to a coon location for further processing Base Requireents for Oil Measureent Syste Design and Installation of Measureent Devices The syste design and installation of oil/eulsion easureent devices ust be in accordance with Sections 14.2, 14.3, and EMF systes ust be designed and installed according to the requireents in Section 6.8. Any EFM syste designed and installed in accordance with API MPMS, Chapter 21.2, is considered to have et the audit trail and reporting requireents, but a perforance evaluation is still required in accordance with Section Voluetric Calculations Crude oil volue easureents ust be deterined to a iniu of two decial places and rounded to one decial place for onthly reporting. Where there is ore than one volue deterination within the onth at a reporting point, the volues deterined to two decial places ust be totalled prior to the total being rounded to one decial place for reporting purposes Teperature Correction Requireents Teperature easureent used for volue correction ust be representative of the actual fluid teperature. Total onthly oil volues for wells (production) and batteries (production, receipts, dispositions, and delivery point) ust be reported in cubic etres at a base teperature of 15 C and rounded to the nearest tenth of a cubic etre (0.1 3 ). Battery or facility opening and closing inventory volues for onthly reporting ust be rounded to the nearest but do not require correction to 15 C. The teperature correction (Correction for the effect of Teperature on Liquids [CTL]) factor ust be deterined in accordance with API MPMS, Chapter In a proration battery, if well test oil volues are deterined by a eter, teperature copensation ust be applied using one of the following ethods: 1. Apply a coposite eter factor that incorporates a CTL factor. To arrive at a coposite eter factor, divide the teperature corrected prover volue by the indicated eter volue for each prover run. 2. Apply a CTL factor in real tie using an electronic flow easureent syste. 3. Apply a CTL factor to the total test volue based on a single teperature easureent taken during the test. See Section 14.4 for ore details. August 1, 2017 Page 6-4

164 Pressure Correction Requireents Correction to a 0.0 kpa gauge (atospheric pressure) ust be perfored for continuous flow crude oil pipeline easureent where custody transfer easureent is perfored. See Section 14.5 for ore details. Shrinkage Factor See Section 14.3 for details. General Volue Calculations See Section 14.9 for details. Production Data Verification and Audit Trail The field data, records, and any calculations or estiations, including EFM, relating to Regulator-required production data subitted to Petrinex ust be kept for inspection upon request. The reported data verification and audit trails ust be in accordance with the following: 1. Test records: any records and docuentation produced in the production proration testing of wells that affect easured volues. 2. Proving records: any records and docuentation produced in the proving of eters and calibration of the prover and all peripheral devices if the prover and peripheral devices are owned and operated by the licensee. 3. S&W records: any records and docuentation produced in the deterination of relative oil/water percentages that affect volues. 4. Delivery and receipt records: any records and docuentation produced in the deterination of delivery or receipt volues. 5. Estiation records: any records and docuentation related to the estiation of reported volues, including estiation ethodology, record of event, and approvals. 6. Tank gauging records: any records and docuentation produced in the deterination of reported volues. 7. Volue loss records: any records and docuentation for volues lost due to incidents such as theft, spills, and fires. 8. EFM: any records and docuentation either electronic, agnetic, or paper for produced in the deterination of easured volues in accordance with the EFM requireents in Section 6.8. Records of the foregoing ust be provided to the Regulator on request Production Data Verification and Audit Trail SK AB Section does not apply in Saskatchewan. Monthly voluetric data aendents are required if significant and correctable reporting errors are identified, and they ust be copleted in accordance with the requireents in Directive 007 and Manual 011. The following criteria ay be used August 1, 2017 Page 6-5

165 to deterine aendent requireents for ost cases: For ultiwell batteries, any error that results in a change in the total battery production ust be corrected regardless of the agnitude of the change since the error will affect the production for all the wells in the battery. Any errors that results in a change in the reported oil production at a well in excess of a predeterined volue ay warrant an aendent. The graph in Figure 6.2 illustrates the voluetric error criteria that ust be used to deterine when voluetric aendents are required. Figure 6.2: Criteria for deterining when voluetric aendents are required on a per well basis BC Not Applicable August 1, 2017 Page 6-6

166 Field Operations Production Hours Physical well shut-ins and eergency shutdowns (ESDs) are considered downtie. Other occurrences resulting in downtie include wax or hydrates plugging lines and soe other failures. If the well has no oil production but still has gas production, it is considered to be on production. The operations personnel have to ake a deterination based on the operating environent in other situations when the wells are not physically shut in but ay not have oil and gas production. Oil wells are considered on production even when the wells are not puping or flowing in situations where: The wells are operating on an on/off cycle basis, such as interittent tiers, pupoff controls, and plunger lifts; The well are operating norally and as designed on repeated cycles; and Part of the operation involves shutdown of pup equipent and/or periodic shut-in of the wells as part of the repeated cycle Fluid Sapling Requireents for S&W Deterination (and Density) See Section 14.6for density deterination details S&W Analysis Conduct water-cut sapling and analysis for each test. See Section 14.8 for S&W deterination details and Appendix 3 for water-cut procedures Proration Well Testing Proration testing requireents for non-heavy crude oil wells are detailed in Table 6.1. Table 6.1. Proration testing requireents for non-heavy crude oil wells No. Class a Nae Oil rate ( 3 /d) Miniu test frequency Miniu tie between tests b (days) Miniu test duration c (hours) 1 High > 30 3 per onth d Mediu > 6 but 30 2 per onth e Low > 2 but 6 1 per onth Stripper 2 1 every quarter a Classification for each well ust be deterined at least sei-annually based on the average daily oil rate since the last assessent. If a well experiences operational changes that cause a change in the oil rate that could affect the classification, the operator ust iediately change the classification. The average daily oil rate ust be based on producing days (not calendar days). b Miniu separation tie between tests if iniu nuber of tests are conducted - the tie between tests ay be reduced if ore than the iniu nuber of tests are conducted. c Licensees should conduct longer duration tests for wells exhibiting erratic rates to obtain ore representative test data. August 1, 2017 Page 6-7

167 d For Class 1 wells, the iniu test frequency is based on the assuption that the well is on production for the entire calendar onth. The test frequency ay be reduced to two per onth if the well is shut in for at least 10 days within the onth and to one per onth if the well is shut in for at least 20 days within the onth. e For Class 2 wells, the iniu test frequency is based on the assuption that the well is on production for the entire calendar onth. The test frequency ay be reduced to one per onth if the well is shut in for at least 15 days within the onth Well Test Considerations If there is a change in operating conditions during a test, such as due to a power failure or a change in choke setting, the test ust be rejected and a new test ust be conducted. If there is insufficient or lost test data, such as due to eter failure, the test ust be rejected and a new test ust be conducted. If there is a significant change in oil, gas, or water for a test, the validity of the test should be questioned and a retest should be considered. Sufficient purge tie ust be allowed to ensure that liquids fro the previous test are displaced by the new test well liquids. The pressure difference between the test separator and the group line ust not exceed 200 kpa. A well test ay be stopped early for operational reasons and still be considered valid. Reasons for the short test ust be docuented and ade available to the Regulator upon request. Coon Flow Lines For coon flow lines, a well test ust be conducted, with all other wells on the coon flow line shut in following adequate purge tie. Cobined (cascade) testing is allowed for coon flowlined wells, provided that the conditions in Section 6.7 are et. However, the cobined test ust be conducted first, and then the low gas producing well ust be shut in to test the high gas producing well, allowing sufficient purging and stabilization tie. Field Header and Coon Flow Line Purging If a field header is located in the sae building as the test separator, the test separator ust be purged by allowing at least two liquid dups to occur prior to starting the well test. The field header ust clearly identify which well is tied to the header valves. If a field header is not located in the sae building as the test separator, sufficient purge tie ust be allowed to ensure that liquids fro the previous test are replaced by the new test well liquids. If two or ore wells are tied into a coon flow line, only one well ust be produced during the well test, and the other well(s) ust be shut in. Siilar to a field header situation, sufficient purge tie ust be allowed to ensure that liquids fro the previous production condition are replaced by the new test well liquids. Sufficient purge tie ust be calculated as follows: Purge tie = test line volue new test well liquid flow rate Exaple: Calculate the iniu purge tie required for the following test line: Test line diensions = 1500 length, 88.9 OD pipe, 3.2 wall thickness August 1, 2017 Page 6-8

168 Previous well test flow rates = oil/d, water/d Step 1 d = ( x 2) 1000 = Test line volue = (3.142 x d 2 x length) 4 = (3.142 x (0.0825) 2 x 1500) 4 = Step 2 Purge tie required = Test line volue ( 3 ) Well flow rate ( 3 /hr) Well total liquid flow rate = ( ) 24 hr = /hr Purge tie required = /hr = 11.0 hr Therefore, the iniu purge tie required is 11.0 hours. 6.5 Oil Proration Battery Accounting and Reporting Requireents Prorated production is an accounting syste or procedure in which the total battery production is allocated to wells based on individual well tests. Production fro ultiple oil wells ay be coingled before separation and continuous single-phase easureent of the coponents (see Figure 6.3). Individual well production ust be tested in accordance with Table 6.1 to deterine the production rates that can be used to estiate the well s onthly production volue. The estiated onthly well production volue is corrected using a proration factor. In suary, the following ust be perfored (see Section for details): 1. Test production volues of gas (in ) and oil and water (in 3 ) rounded to two decial places. 2. Record test duration hours to two decial places with the nearest quarter hour as the iniu resolution. 3. Deterine the hour production rate for each product fro the well. 4. Deterine the estiated well production by ultiplying the hour rate by the onthly hours of production. 5. Deterine the actual prorated production volue by ultiplying the estiated well production by the proration factor (the total actual battery production volue divided by the total estiated battery production volue). August 1, 2017 Page 6-9

169 Group Test Figure 6.3. Proration testing battery Oil Well A Test Gas SP Gas Accounting Fuel Flare Vented Gas Gas Gathering Systes Oil Well B Test Oil/Eulsion Treater Oil Storage Oil Delivery Oil Sales Pipeline Water Storage Water Disposal = easureent point The iniu test frequency and duration requireents (see Table 6.1) apply to all nonheavy oil wells under priary production and waterflood operations included in proration batteries. Monitoring the perforance of iscible floods and other enhanced oil recovery schees usually requires testing criteria other than rate alone and therefore testing requireents for iscible flood schees are set out in each schee approval. Licensees ust onitor the classification for wells producing to a battery and eet the required testing frequency and duration for each well (see Table 6.1) unless otherwise approved by the Regulator. Many low-rate and stripper wells exhibit erratic production rates due to high water-oil ratios or gas-oil ratios, and oversized production lines and test separators can ake accurate easureent difficult. Longer test duration can iprove test accuracy for any of these wells. To allow licensees the opportunity to conduct longer duration tests, class 3 and 4 wells are allowed to use up to an eight-day cycle chart drive for easureent of test gas production volues. The use of autoatic well testing equipent and procedures with EFM provides licensees the opportunity to conduct tests of shorter durations than specified in Table 6.1. The autoation coputer can onitor the test and use statistical calculation ethods to ensure that a representative rate is obtained prior to terinating the test. This practice is acceptable when: 1. the accuulated oil test volue is polled at a frequency of at least once per hour; 2. the criteria for stabilization ensures that the uncertainty for the onthly well oil volue does not exceed half of the axiu uncertainty of onthly volue stipulated in Section 1, Standards of Accuracy; and 3. the coputer progra is properly docuented and available to the Regulator upon request. August 1, 2017 Page 6-10

170 The test-to-test ethod, whereby data fro a test are used to estiate production until the next test is conducted, ust be used to estiate the production volue fro each oil well based on the test rate and the total production hours. This production estiation ethod and the proration ethodology are outlined in Sections 6.5.1and A licensee ay use its own worksheet forat, provided that the required data are retained and available to the Regulator upon request Proration Estiated Volue Calculation Calculate the estiated production of each well fro the test data using the saple worksheet below (Table 6.2). 1. Calculate the test rate/hour for crude oil, gas, and water: Rate per hour = test production volue (including GIS volues for gas) test duration (hr.) Enter the test rate per hour rounded to four decial places. 2. Calculate the hours of production for each test rate during the reporting onth. Include only the hours of prorated production: a. hours of production fro the first day of the onth to the start of the first test for the onth data fro the last test conducted during the previous onth will be used to estiate production until the first test for the onth is conducted, and b. hours of production fro the start of each test conducted during the onth up to the start of the next test, or the end of the onth, whichever is applicable. Enter the hours produced rounded to the nearest hour. 3. Calculate the estiated production of oil, gas, and water for the production hours applicable to each test rate: Estiated production = test rate per hour x hours produced Enter the estiated production of oil, gas, and water rounded to one decial place. 4. Calculate the totals for each well: Add the hours produced that are applicable to each test rate and enter the total. Add the estiated production of oil, gas, and water, and enter the totals. Note that if a GOR is used to estiate the well gas production in accordance with Section 4.3.8: Estiated well gas production = estiated well oil production x GOR August 1, 2017 Page 6-11

171 UID Table 6.2 WI W400 Test date Test oil Test gas Hourly test rate Estiated production Test water Test duration c Oil Gas Water Prod Oil Gas Water Vessel dd hours 3 /hr /hr 3 /hr hours Prior o Totals UID WI W400 Test date Test oil Test gas Hourly test rate Estiated production Test Test water duration c Oil Gas Water Prod Oil Gas Water Vessel dd hours 3 /hr /hr 3 /hr hours Prior o a a Totals UID WI W400 Test date Test oil Test gas Hourly test rate Estiated production Test water Testdurati on c Oil Gas Water Prod Oil Gas Water Vessel dd hours 3 /hr /hr 3 /hr hours Prior o. 1 b b Totals Note that test gas volues ust include gas-in-solution (GIS) volues (see Section 4.3.8). a Tests on July 3 and 4 were coparable and consecutive, e.g., there were no operational changes. Therefore, the results are cobined and used as one 48-hour test. b Tests on July 1 and 2 were not coparable due to operational changes, e.g., choke/pup speed. Therefore, they are used as separate 24-hour tests. c Test duration ust be reported to the nearest quarter hour as the iniu resolution (record hours to two decial places), e.g., 2 hr. and 45 in are entered as 2.75 hr. August 1, 2017 Page 6-12

172 6.5.2 Calculate Proration Factors and Monthly Production 1. Calculate the total estiated battery production for oil, gas, and water: Total estiated battery production = su of all the wells total estiated production 2. Calculate the total actual battery production and proration factors for oil, gas, and water: For oil and water, For gas, Total actual battery production = total onthly disposition + closing inventory opening inventory total receipts Total actual battery production = total onthly disposition (including fuel, flare, vent) total receipts Proration factor = total actual battery production total estiated battery production The proration factors for oil, gas, and water ust be rounded to five decial places. If a GOR is used to estiate the total battery gas production volue in accordance with Section 4.3.8: Estiated battery gas production = actual battery oil production x GOR Estiated battery gas production = actual battery gas production Gas proration factor = Calculate each well s onthly prorated production volues for oil, gas, and water: Monthly prorated oil volue = well estiated oil production x oil proration factor Monthly prorated gas volue = well estiated gas production x gas proration factor Monthly prorated water volue = well estiated water production x water proration factor 4. Check that total well production equals total actual battery production for oil, gas, and water. If the volues are not equal due to rounding, inor adjustents to the onthly volues ay be required. Su of prorated well production = total actual battery production 6.6 Condensate Receipts at an Oil Battery If condensate that could be flashed into the gas phase is received by pipeline at an oil battery, the licensee ust choose fro the applicable condensate reporting options in Section 5.5. The volue of condensate received fro an external source that will be reported as a GEV, that volue ust be subtracted fro the total onthly battery gas disposition volue to deterine the onthly battery gas production volue. When condensate is received by truck at an oil battery where a portion of the condensate could flash into the gas phase, the flashed condensate ust be reported as a GEV receipt volue and the unflashed condensate ust be reported as a liquid condensate receipt. Note that this ay also be applicable to other light hydrocarbons delivered into an oil battery. August 1, 2017 Page 6-13

173 6.7 Cobined (Cascade) Testing When a prorated oil well has such low gas production that it cannot properly operate test equipent, a licensee ay test two wells siultaneously - cobined (cascade) test - through the sae test separator. In such scenarios, the following procedure ust be followed: 1. Establish oil, gas, and water production volues for a high gas producing well by testing it individually through the test separator. 2. Conduct a test for both the high gas producing well and a low gas producing well together through the sae test separator iediately after testing the high gas producing well, allowing tie for stabilization. The testing sequence ay be reversed with the testing of the cobined wells first. 3. The operating condition of both wells ust not be changed. If it is, a new set of tests is required. 4. Total test oil, gas, and water volues deterined for the cobined (cascade) test inus the test oil, gas, and water volues for the high gas producing well will be the test volues for the low gas producing well. 5. Both wells should have siilar S&W percentages. If any of the calculated oil, gas, or water volues for the low gas producing well are negative, the tests are not valid and both tests ust be repeated. The use of cobined (cascade) testing does not require special approval fro the Regulator. Exaple Well A = High gas producing Well B = Low gas producing Table 6.3 Test Results Well Test date Oil ( 3 ) Gas ( ) Water ( 3 ) Well A + B July Well A July Well B = (Well A + B) - Well A July Electronic Flow Measureent for Oil Systes See Section for details. August 1, 2017 Page 6-14

174 6.9 Reporting Requireents and Scenarios for Wells Producing Oil The following scenarios are the required reporting scenarios for both oil wells and gas wells producing oil. See Section 13 for condensate scenarios Oil Wells Scenario 1 Oil separated fro well effluent and sold fro battery facilities. Report as OIL PROD and OIL DISP at the battery in Petrinex. Figure 6.4. Scenario 1 Scenario 1 Gas To gas gathering syste / gas plant / sales Oil well Well effluent Separator Oil Storage tank at battery Vented Gas Oil sales = easureent point Scenario 2 Oil separated fro well effluent, easured, and trucked to a tank at the gas plant. Report as OIL PROD and OIL DISP at battery and OIL REC at the gas plant in Petrinex. Figure 6.5. Scenario 2 Scenario 2 Gas To gas gathering syste / gas plant / sales Well effluent Oil well Separator Oil Storage tank at battery Vented Gas Oil Vented Gas Gas processing plant Storage tank at gas plant Oil transfer Total sales of oil and pentanes plus = easureent point August 1, 2017 Page 6-15

175 Scenario 3 Oil separated fro well effluent, easured, coingled with gas, and sent to a gas plant. Report as OIL PROD and OIL DISP at battery and OIL REC at the gas plant in Petrinex. Shipents reported at the gas plant will be the total cobined sales of this transferred oil and the plant pentanes plus products. Note: The total plant inlet volues reported would norally include the gas equivalent of the inlet condensate, but in this scenario, the inlet condensate volues used to calculate the total plant inlet ust be the net of the oil production that has been transferred to the plant. The reported plant inlet volues and the pentanes plus production will be the easured volues less this transferred oil production. Figure 6.6. Scenario 3 Scenario 3 Gas Well Effluent Oil well Separator Oil Gas Processing Plant Pentanes Plus (C5-MX) Vented Gas Storage Tank at Gas Plant Gas Oil Oil Separator Plant Inlet Separator Coingled Strea Total sales of oil and pentanes plus Gas Well Effluent = easureent point Scenario 4 Oil separated fro well effluent at battery, gas copressed as part of noral battery operations, and additional liquids recovered as a result of copression and coingled with battery oil production. Report total fluid as OIL PROD and prorate to wells in the battery and total OIL DISP in Petrinex. August 1, 2017 Page 6-16

176 Figure 6.7. Scenario 4 Scenario 4 Gas To gas gathering syste / gas plant / sales Copressor at battery site Oil well Wellhead separator Oil Vented Gas Storage tank at battery Liquids Gas Oil sales = easureent point Scenario 5 Oil separated fro well effluent at battery, gas copressed not as part of noral battery operations, and additional liquids recovered as a result of copression. Report total OIL PROD and total OIL DISP at the battery in Petrinex. Hydrocarbon liquids recovered as a result of copression will be reported as pentanes plus (C5-MX) at the gathering syste in Petrinex. Figure 6.8 Scenario 5 Scenario 5 Battery Gas gathering syste Gas Oil well Well Efluent Separator Oil Vented Gas Copressor station Liquids To gas gathering syste / gas plant / sales Vented Gas Oil sales Storage tank at battery Storage tank at copressor site Pentane plus sales = easureent point Gas Well Producing Oil Scenario 6 Oil separated fro well effluent, easured, and sold fro battery. Report as OIL PROD and OIL DISP at the battery in Petrinex. August 1, 2017 Page 6-17

177 Figure 6.9. Scenario 6 Scenario 6 Gas To gas gathering syste / gas plant / sales Well effluent Vented Gas Gas well producing oil Oil Storage tank at battery Oil sales = easureent point Scenario 7 Oil separated fro well effluent, easured, coingled with gas, and sent to a gas plant. Report as OIL PROD and OIL DISP at battery and OIL REC at the gas plant in Petrinex. Shipents reported at the gas plant will be the total cobined sales of this transferred oil and the plant pentanes plus (C5-MX) products. Note: The total plant inlet volues reported would norally include the gas equivalent of the inlet condensate, but in this scenario, the inlet condensate volues used to calculate the total plant inlet ust be the net of the oil production that has been transferred to the plant. The reported plant inlet volues and the pentanes plus production will be the easured volues less this transferred oil production. Figure Scenario 7 Scenario 7 Gas Well effluent Gas well producing oil Separator Oil Gas processing plant Vented Gas Gas Plant inlet separator Oil Other gas well effluent Coingled strea Pentanes Plus (C5-MX) Storage tank at gas plant Oil Total sales of oil and pentanes plus = easureent point Scenario 8 Oil separated fro well effluent, easured, and trucked to a gas plant process or a storage tank at the gas plant. August 1, 2017 Page 6-18

178 Report as OIL PROD and OIL DISP at battery and OIL REC at the gas plant in Petrinex. Shipents reported at the gas plant will be the total cobined sales of this transferred oil and the plant pentanes plus (C5-MX) products. Figure Scenario 8 Scenario 8 Gas To gas gathering syste / gas plant / sales Well effluent Vented Gas Gas well producing oil Oil Storage tank at battery Oil Gas processing plant = easureent point Oil and Pentanes Plus (C5-MX) Vented Gas Storage tank at gas plant To plant process or To plant storage tank Oil transfer Total sales of oil and pentanes plus August 1, 2017 Page 6-19

179

180 7 Gas Proration Batteries This section presents the requireents and exeptions relating to easureent, accounting, and reporting for gas proration batteries. Gas well operators have the option of not easuring the gas and/or separated liquids for each well. If the gas and liquids are not separated and easured, they can be prorated. Operators that decide to install prorated systes in accordance with the provisions of this section are accepting higher uncertainty at the wellhead, offset by lower capital and operating costs. Prorated wells are tested periodically to deterine the typical flow rate. The gas and liquids fro a nuber of wells are easured at a group eter, and the volue at the group eter is prorated back to the individual wells based on the ost recent test and the hours on strea. The easureent uncertainty assigned to individual wells within gas proration batteries is greater than for wells where the gas is separated and easured. For this reason, operators should understand the ipact of this type of easureent when dealing with partners and third parties. Prorated wells can be tied in to the sae syste as easured wells but under separate battery codes. In these scenarios, the easured wells are kept whole, and the difference between the proration battery disposition and the easured well volue is prorated to all the proration wells. This is referred to as easureent by difference (see Section 5.5), since the easured volue is subtracted fro the group easureent before proration. Measureent by difference increases the uncertainty of the prorated well volue estiate. 7.1 General Requireents The three types of gas proration batteries include: 1. Gas ultiwell proration SW Saskatchewan and SE Alberta batteries (Petrinex facility subtype 363), 2. Gas ultiwell proration outside SW Saskatchewan and SE Alberta batteries (Petrinex facility subtype 364), and 3. Gas ultiwell effluent easureent batteries (Petrinex facility subtype 362). All wells in a gas proration battery ust be gas wells and ust be connected by flow line to a coon group separation and easureent point. All gas proration batteries require periodic well tests to be conducted to deterine production rates, production ratios, and/or ECF that will be used in the deterination of onthly estiated well production volues. Monthly estiated well production volues are ultiplied by proration factors to deterine the actual well production volues for reporting purposes. All wells ust be tested annually unless otherwise stated in Section 7. All voluetric calculations ust be in , to the required decial places listed in Table 7.1. August 1, 2017 Page 7-1

181 Table 7.1. Required decial places for voluetric calculations in prorated gas batteries Type of calculations Nuber of decials to be calculated to Nuber of decials to be rounded to Production and estiated production 2 1 Well test gas, GEV of test condensate, test condensate, or test water WGR, condensate-gas ratio (CGR), and oil-gas ratio (OGR) Proration factors, ECF 6 5 Test taps ust be installed at all proration gas wells. The required test tap locations are illustrated in Figure 7.8 for Petrinex subtypes 362, 363 and 364. See Section 8 for sapling and analysis of gas, condensate, and water Group Measureent Where delivery point easureent is required, the cobined (group) production of all wells in the proration battery ust have three-phase separation and be easured as singlephase coponents. Where delivery point easureent is not required, the group production ay be easured using two phase separation with three phase easureent. This eans that a two phase separator with an online product analyzer on the liquid leg of the separator ay be used provided that: The easureent syste design eets the requireents of Section 14 The condensate and water is recobined and delivered to a gas gathering syste or gas plant for further processing If liquid condensate is trucked out of the group separation and easureent point to a gas plant for further processing: SK AB BC The condensate ust be reported as a liquid condensate volue fro the battery. The condensate ust be reported as a gas equivalent volue fro the battery. See Measureent Guideline for Upstrea Oil and Gas Operations Gas wells in any one of the three types of proration batteries ust not be coingled with easured gas sources or gas fro another proration battery prior to group easureent, or with gas wells in a different type of gas proration battery, upstrea of their respective group easureent points. Variances fro this requireent ay be allowed if the Exeption criteria in Sections 5.5 and are et or if site-specific approval has been obtained fro the Regulator prior to ipleentation Stabilized Flow and Representative Flow Wells that use artifical lift systes are characteristically never in stabilized flow and thus ust be tested for a iniu duration that runs over ultiple flow cycles to accurately deterine a representative volue of gas, condensate, or water. These representative August 1, 2017 Page 7-2

182 production volues are then extrapolated to accurately reflect the wells production over an extended period of tie. August 1, 2017 Page 7-3

183 7.2 Gas Multiwell Proration SW Saskatchewan and SE Alberta Batteries (Petrinex facility subtype: 363) Gas wells in this type of battery do not require dedicated continuous easureent for each well or special approvals fro the Regulator. Production rates deterined during a well test ust be used in the estiation/proration calculations within 30 days of the test until the next test is conducted. Total battery gas production ust be easured and prorated back to the individual wells, based on each well s estiated onthly gas production. Estiated well gas production is based on hourly production rates, deterined by periodic well tests and onthly producing hours. Gas wells that produce fro shallow gas stratigraphic units or zones in SW Saskatchewan or SE Alberta ay be included in these types of batteries. SK AB BC The stratigraphic units or zones include coals and shales fro the base of the Glacial Drift to the base of the Upper Cretaceous. The production fro two or ore of these stratigraphic units or zones without segregation in the wellbore requires prior approval fro the Regulator for coingled production. The stratigraphic units or zones include coals and shales fro the top of the Edonton Group to the base of the Colorado Group. The production fro two or ore of these stratigraphic units or zones without segregation in the wellbore requires prior approval fro the Regulator for coingled production, which has been granted in a portion of SE Alberta in Order No. MU 7490, or adherence to the self-declared coingled production requireents described in Directive 065: Resources Applications for Oil and Gas Reservoirs. Not Applicable Group Measureent Group easured production is generally deterined through individually easured product streas. A iniu of two-phase group easureent is required because the battery water production ust be reported at the battery level. This group easureent point is located generally at the battery site where a copressor is present (see Figure 7.1). August 1, 2017 Page 7-4

184 Separator Figure 7.1. Typical Gas Multiwell Proration SW Saskatchewan or SE Alberta Battery Test Taps Test Taps Sweet Gas Well Test Taps Test Taps Sweet Gas Well Group Gas Copressor To Gathering Syste or Sales Sweet Gas Well Test Taps Sweet Gas Well Sweet Gas Well = easureent point Produced Water Size of a Gas Multiwell Proration SW Saskatchewan or SE Alberta Battery There is no liit on the nuber of flowlined wells that ay be in a Gas Multiwell Proration SW Saskatchewan or SE Alberta Battery. However, licensees are encouraged to consider the logistics of the battery s operation in deterining the size of these batteries, with the key factors being: 1. The ability to conduct representative well tests at the iniu frequency specified in Table 7.2; and 2. The configuration and operating pressures of the battery and flow lines such that all wells can readily flow. This approach will generally result in the ain pipeline syste laterals being used to establish a group easureent point Testing Requireents Gas production rate tests ust be conducted for each well in the battery in accordance with the following requireents: 1. The test ust be of sufficient duration to clearly establish a stabilized flow rate. Stabilized flow indicates a point at which flowing paraeters of gas, condensate, or water are producing under noral operating conditions and represent production levels equal to the well s noral average flow rate. Stabilized flow can only be achieved when all testing equipent associated in deterining an actual volue has reached equilibriu, i.e., liquid levels in test separator, pressure and teperature stabilization to noral operating conditions. 2. The test ust be representative of the well s capability under noral operating conditions. Representative flow can be used when stabilized flow is not achievable, such as for wells with artificial lift systes and wells with slugging characteristics. The test volues of gas, condensate, or water ust be representative of the well s production capability under noral operating conditions. Wells that use artificial lift systes or characteristically display slug flow ust be tested for a iniu duration that copletes ultiple flow cycles to accurately deterine a representative volue of gas, condensate, or water. These August 1, 2017 Page 7-5

185 representative production volues are then extrapolated to accurately reflect the wells production over an extended period of tie. 3. Testing progras and procedures ust ensure that all wells are treated equitably within their respective batteries. These types of wells are typically tested by directing flow fro the well through a test eter. However, a test separator syste ay also be used. 4. New wells ust be tested within the first 30 days of production, then again within 12 onths, and thereafter according to Table 7.2. If these requireents cannot be satisfied, the operator ust either reconfigure the syste, e.g., redirect soe wells to another battery/group easureent point, or test each of the individual wells within the battery once per onth. Table 7.2. Testing frequency for SW Saskatchewan and SE Alberta shallow gas wells Miniu rate Maxiu rate Nuber of tests Frequency* /d 1 Triennial > /d /d 1 Biennial > /d 1 Annual *See Appendix 2 for frequency definition Production Accounting and Reporting Procedures Water Reporting Requireents The reporting of water production for the qualified wells in Gas Multiwell Proration SW Saskatchewan and SE Alberta Batteries is not required. However, all water receipts and disposition ust be reported at the battery level. An ABMC receipt code for Alberta and an SKMC receipt code for Saskatchewan ust be used to balance the disposition at the battery level on Petrinex. If the water is trucked to non-petrinex reporting facilities without a reporting code or evaporated on site, it ust be reported using an ABMC or SKMC disposition code respectively. Gas Production Volue Calculations Monthly gas production volues are to be calculated as follows: 1. Calculate well gas test rate: Well gas test rate ( /hour) = Well test gas volue ( ) Well test duration (hours) 2. Calculate estiated onthly well gas volue: Estiated onthly well gas volue = Well gas test rate x Monthly total hours of well production 3. Calculate total estiated gas production for the battery: Total battery estiated onthly gas volue = Su of all estiated onthly well gas volues 4. Calculate proration factor for gas: Gas proration factor =Total battery easured onthly gas volue Total battery estiated onthly gas volue 5. Calculate actual onthly (prorated) well gas production: August 1, 2017 Page 7-6

186 Separator Actual onthly well gas production = Gas proration factor x Estiated onthly well gas volue 7.3 Gas Multiwell Proration Outside SW Saskatchewan and SE Alberta Batteries (Petrinex facility subtype 364) Gas wells in this type of battery do not require dedicated continuous easureent for each well. Production rates, WGRs, and/or CGRs deterined during a well test ust be used within 30 days in the estiation/proration calculations until the next test is conducted. Total battery gas production ust be easured and prorated back to the individual wells based on each well s estiated onthly gas production. Estiated well gas production is based on hourly production rates, deterined by periodic well tests and onthly producing hours. Total battery condensate production ust be easured if present. If it is delivered for sale fro the battery, it ust be prorated back to the individual wells based on each well s CGR fro the production tests. The sales condensate ust be reported as a liquid disposition on Petrinex. Then the estiated gas production volue at each well will not include the GEV of the condensate. If the condensate is recobined with the gas for further processing at a gas plant, the condensate ust be reported as a GEV and added to the easured gas production volue and reported on Petrinex. Total battery water production ust be easured and prorated back to the individual wells based on each well s estiated onthly water production. Estiated well water production is based on a WGR, deterined by well tests ultiplied by the estiated onthly well gas production (see Figure 7.2). Figure 7.2. Typical Gas Multiwell Proration Outside SW Saskatchewan and SE Alberta Battery Test Taps Gas Well Test Taps Test Taps Test Taps Gas Well Battery / Group Measureent Point Gas Copressor To Gathering Syste or Sales Gas Well Test Taps Gas Well Condensate To Gathering Syste or Sales Gas Well = easureent point Produced Water If total water production at each well in the battery is less than or equal to /d based on the onthly average flow rates recorded during the six onths prior to conversion, water production ay be prorated to all wells in the battery based on the estiated gas production at each well. If a group of new wells not previously on production is to be configured as a proration battery, the qualifying flow rates ust be based on production tests conducted under the noral operating conditions of the proration battery. There is no geographical or zonal liitation for this type of proration battery. The Exeption criteria in Section 5.4 ust be et or Regulator site-specific approval ust be August 1, 2017 Page 7-7

187 Test Separator obtained prior to the proration battery ipleentation either at the initial design and installation stage or at a later stage of production when the production rate decreases to a point that continuous easureent is not econoical. Gas wells producing oil rather than condensate ust not be tied into a Gas Multiwell Proration Outside SW Saskatchewan or SE Alberta battery unless the well oil and gas production volues are separated and easured prior to coingling with the other wells in the battery and either the Exeption criteria in Sections 5.5 and are et or sitespecific approval has been obtained fro the Regulator prior to ipleentation. However, if a gas well classified as producing condensate in a gas ultiwell proration outside SW Saskatchewan or SE Alberta battery is reclassified by the Regulator as producing oil, the well ay reain in the battery provided that the well is equipped with a separator and there is continuous easureent of the gas, oil, and water or, alternatively, the easureent, accounting, reporting procedures specified in Section are followed Well Testing Requireents Well testing is typically perfored by directing well production through a three-phase portable test separator configured with dedicated eters for gas, condensate, and water. Test equipent using two-phase separation is acceptable if hydrocarbon liquids are too sall to be easured during typical well test durations. Other options that provide equivalent liquid volue deterination accuracy ay also be considered. For exaple, if a three-phase separator is not available, alternative equipent, such as a two-phase separator with a total liquid eter and continuous water cut analyzer, ay be acceptable (see Figures 7.3 and 7.4). Figure 7.3. Typical testing unit for Gas Multiwell Proration Outside SW Saskatchewan and SE Alberta Battery Testing Unit Gas (A) Metered and Recobined Condensate (B) Produced Water (C) Gas Well X X X Test Taps To Gas Battery (Group easureent) = easureent point August 1, 2017 Page 7-8

188 Separator Figure 7.4. Typical Gas Multiwell Proration Outside SW Saskatchewan and SE Alberta battery Test Taps Test Taps Battery / Group Measureent Point Gas Well Test Taps Test Taps Gas Well Gas (D) To Gathering Syste or Sales Gas Well Test Taps Gas Well Condensate (E) To Gathering Syste or Sales Gas Well = easureent point Produced Water Volue (F) Test frequency ay be extended with Regulator approval. Unless alternative test procedures have been specified in a Regulator approval, the test ust be conducted with easureent of all phases as follows: 1. The test ust begin only after a liquid level stabilization period. 2. The test duration ust be a iniu of 12 hours. 3. After the coenceent of production at the proration battery, all wells ust be tested within the first onth, and thereafter annually. New wells added to the battery at soe future date ust be tested within the first onth of production, then again within six onths, and thereafter annually. 4. Consistent testing procedures ust be used for consecutive tests to identify if a change in a well s flow characteristics has occurred. 5. These wells are typically tested by directing flow fro the well through a test separator. If the initial testing with a separator shows a liquid-gas ratio (LGR) of less than liquid/ gas, other testing ethodology, such as a saller separator or a single test eter without separation, could be used for the next test. If the total liquid volues at group easureent point exceed a ratio of liquid/ gas in any onth, a test separator ust be used to test all the wells within the battery for the next round of testing to deterine where the liquid originated. 6. The gas, condensate, and water volues ust be easured. 7. The condensate ust be sapled during every test and subjected to a copositional analysis, which is to be used to deterine the gas equivalent factor (GEF). The saple ay be taken fro the condensate leg of a three-phase separator or the liquid leg of a two-phase separator. The water ust be reoved fro the condensate before conducting the analysis. 8. The GEF ust be used to convert the liquid condensate volue deterined during the test to a GEV, which will be added to the easured test gas volue to deterine the total test gas volue if: August 1, 2017 Page 7-9

189 SK AB BC the condensate is not delivered for sale at the group easureent point or trucked for further processing, see Section the condensate is not delivered for sale at the group easureent point, see Section See Measureent Guideline Upstrea Oil and Gas Operations 9. The WGR, CGR, and OGR (if applicable) ust be deterined by dividing the test water, condensate, and oil volue respectively by the total test gas volue. 10. For orifice eters, the test gas eter ust use 24-hour charts for a test period of 72 hours or less, unless electronic flow easureent is used; for testing periods longer than 72 hours, seven-day charts ay be used, provided that good, readable pen traces are aintained, see Section Exeption fro Gas Multiwell Proration Outside SW and SE Alberta Batteries 1. New and existing wells producing fro shallow gas zones/stratigraphic units in SW Saskatchewan ay be tested in accordance with the testing requireents set out in Section SK 2. Existing shallow gas wells in batteries located outside the SW Saskatchewan shallow gas zones/stratigraphic unit with a LGR liquid / gas ay be tested in accordance with the testing requireents set out in Section The stratigraphic units or zones include coals and shales fro the base of the Glacial Drift to the base of the Upper Cretaceous. The production fro two or ore of these stratigraphic units or zones without segregation in the wellbore requires prior approval fro the Regulator for coingled production. 1. New and existing wells producing fro shallow gas zones in SE Alberta ay be tested in accordance with the testing requireents set out in Section Existing wells in batteries located outside the SE Alberta shallow gas zones with a LGR liquid / gas ay be tested in accordance with the testing requireents set out in Section AB BC The stratigraphic units or zones include coals and shales fro the top of the Edonton Group to the base of the Colorado Group. The production fro two or ore of these stratigraphic units or zones without segregation in the wellbore requires prior approval fro the Regulator for coingled production, which has been granted in a portion of SE Alberta in Order No. MU 7490, or adherence to the self-declared coingled production requireents described in Directive 065: Resources Applications for Oil and Gas Reservoirs. See Measureent Guideline for Upstrea Oil and Gas Operations August 1, 2017 Page 7-10

190 7.3.2 Production Volue Calculations Monthly production volues are to be calculated as follows: Units: All gas volues and GEV are to be in and liquid volues in Calculate well gas test rate, see Figure 7.3: Well gas test rate ( /hour) = (Well test gas volue [A] + GEV of well test condensate [B]) Well test hours Note: Do not include GEV of [B] if condensate is: SK AB delivered for sale at the group easureent point or trucked for further processing. delivered for sale at the group easureent point. BC See Measureent Guideline for Upstrea Oil and Gas Operations 2. Calculate estiated onthly well gas volue: Estiated onthly well gas volue = Well gas test rate x Monthly total hours of well production 3. Calculate total estiated gas production for the battery: Total battery estiated onthly gas volue = Su of all estiated onthly well gas volues 4. Calculate the well WGR, see Figure 7.3: WGR = Well test water volue (C) (Well test gas volue [A] + GEV of well test condensate [B]) Note: Do not include GEV of [B] if condensate is: SK AB delivered for sale at the group easureent point or trucked for further processing. delivered for sale at the group easureent point. BC See Measureent Guideline for Upstrea Oil and Gas Operations 5. Calculate estiated water production for each well: Estiated onthly well water volue = Estiated onthly well gas volue x WGR 6. Calculate total estiated water production for the battery: Total battery estiated onthly water volue = Su of all estiated onthly well water volues If the condensate is: SK AB delivered for sale at the group easureent point or trucked for further processing, delivered for sale at the group easureent point, BC See Measureent Guideline for Upstrea Oil and Gas Operations August 1, 2017 Page 7-11

191 calculate the next two ites; otherwise go directly to ite Calculate the well CGR, see Figure 7.3: CGR = Well test condensate volue (B) Well test gas volue (A) 8. Calculate estiated condensate production for each well: Estiated onthly well condensate volue = Estiated onthly well gas volue x CGR 9. Calculate total estiated condensate production for the battery: Total battery estiated onthly condensate volue = Su of all estiated onthly well condensate volues 10. Calculate proration factors for gas, condensate SK AB If delivered for sale at the group easureent point or trucked for further processing, If delivered for sale at the group easureent point, BC See Measureent Guideline for Upstrea Oil and Gas Operations and water, see Figure 7.4: Gas Proration Factor (GPF) = (Total battery easured onthly gas volue [D] + GEV of total battery condensate [E]) Total battery estiated onthly gas volue Note: Do not include GEV of [E] if condensate is: SK AB delivered for sale at the group easureent point or trucked for further processing. delivered for sale at the group easureent point. BC See Measureent Guideline for Upstrea Oil and Gas Operations Water Proration Factor (WPF) = Total battery actual onthly water volue (F) Total battery estiated onthly water volue Condensate Proration Factor (CPF) = Total battery easured onthly condensate volue [E] Total battery estiated onthly condensate volue 11. Calculate actual onthly (prorated) well production: Actual onthly well gas production = Estiated onthly well gas volue x Gas Proration Factor Actual onthly well water production = Estiated onthly well water volue x Water Proration Factor Actual onthly well condensate production = Estiated onthly well condensate volue x Condensate Proration Factor Exeption for Gas Wells Producing Oil SK If the hydrocarbon liquid that a gas well produces changes fro condensate to oil, based on its density, the well ay reain in a Gas Multiwell Proration Outside SW Saskatchewan Battery, provided that the well is equipped with a separator and there is continuous easureent of the gas and liquid coponents or, alternatively, the easureent, accounting, and reporting procedures specified August 1, 2017 Page 7-12

192 AB BC below are followed, (see Figure 7.5). If a gas well classified as producing condensate in a gas ultiwell proration outside SE Alberta battery is reclassified by the Regulator as a gas well producing oil, the well ay reain in the battery provided that the well is equipped with a separator and there is continuous easureent of the gas and liquid coponents or, alternatively, the easureent, accounting, and reporting procedures specified below are followed, (see Figure 7.5). See Measureent Guideline for Upstrea Oil and Gas Operations Annual Gas Rate WGR tests ust be conducted on the well. An oil-gas ratio (OGR) ust also be deterined during this test. The WGR, estiated water production, water proration factor, and actual water production are deterined in the sae anner, see Section Units: All gas volues and GEV are to be in and liquid volues in Calculate well gas test rate, see Figure 7.6: Well gas test rate = Well test gas volue (A) Well test hours 2. Calculate estiated onthly well gas volue: Estiated onthly well gas volue = Well gas test rate x Monthly total hours of well production 3. Calculate the OGR, see Figure 7.6: OGR = Well test oil volue (B) Well test gas volue (A) 4. Calculate actual well oil production: Actual onthly well oil production = Estiated onthly well gas volue x OGR 5. Calculate actual total oil production: Actual onthly total battery oil production = Su of all actual onthly well oil volues 6. At the group easureent point, subtract the oil production volue (ite 5) fro the total liquid hydrocarbon volue to deterine the total battery condensate production. SK AB BC The GEV of the total battery condensate volue, if not delivered for sale or trucked for further processing, ust be added to the easured group gas volue to deterine the total battery gas volue, see Figure 7.5: The GEV of the total battery condensate volue, if not delivered for sale, ust be added to the easured group gas volue to deterine the total battery gas volue, see Figure 7.5: See Measureent Guideline for Upstrea Oil and Gas Operations Total battery condensate volue = Battery total liquid hydrocarbon volue (E) Actual onthly total battery oil production 7. Calculate total estiated gas production for the battery: Total battery estiated onthly gas volue = Su of all estiated onthly well gas volues 8. Calculate proration factor for gas, see Figure 7.5: August 1, 2017 Page 7-13

193 Test Separator Separator Gas Proration Factor (GPF) = (Total battery easured onthly gas volue [D] + GEV of total battery condensate volue [ite 6]) Total battery estiated onthly gas volue 9. Calculate actual onthly (prorated) well gas production: Actual onthly well gas production = Estiated onthly well gas volue x Gas Proration Factor Figure 7.5. Typical Gas Multiwell Proration Outside SW Saskatchewan or SE Alberta battery Test Taps Test Taps Battery / Group Measureent Point Gas Well Test Taps Test Taps Gas Well Gas (D) To Gathering Syste or Sales Gas Well Test Taps Gas Well Liquid Hydrocarbon (E) To Gathering Syste or Sales Gas Well = easureent point Produced Water Volue (F) Figure 7.6. Typical Testing Setup Testing Unit Gas (A) Metered and Recobined Oil (B) Produced Water (C) Gas Well X X X Test Taps To Gas Battery (Group easureent) = easureent point August 1, 2017 Page 7-14

194 SK AB BC Report the calculated onthly oil production volue as oil produced fro the well. Prorate onthly condensate production, if delivered for sale or trucked for further processing, and water production as in the noral proration battery in Section Report the calculated onthly oil production volue as oil produced fro the well. Prorate onthly condensate production, if delivered for sale, and water production as in the noral proration battery in Section See Measureent Guideline for Upstrea Oil and Gas Operations 7.4 Gas Multiwell Effluent Measureent Batteries (Petrinex subtype 362) Gas wells in this type of proration battery have dedicated effluent easureent, whereby total ultiphase well fluid passes through a single eter, see Figure 7.7. This type of easureent ust be subjected to testing regardless of the type of effluent eter used. For a new copletion or recopletion of another stratigraphic unit or zone in an existing well, effluent easureent is not allowed at a certain LGR level, see Section for details. Figure 7.7. Typical Gas Multiwell Effluent Measureent Battery configuration Test Taps Effluent Group Measureent Point Effluent Test Taps Gas Produced Water Metered and Recobined Condensate To Gas Gathering Syste Effluent Test Taps = easureent point Production rates, WGR, CGR, and ECF deterined during a well test ust be used in the estiation/proration calculations within 60 days of the test until the next test is conducted. Total battery gas production ust be easured and prorated back to the individual wells, based on each well s estiated onthly gas production. Estiated well gas production is based on the total volue easured by the effluent eter ultiplied by an ECF, see Figure August 1, 2017 Page 7-15

195 7.8. The uncertainty of easureent will increase with higher liquid rates, especially under liquid slugging conditions. Figure 7.8 illustrates a typical gas well effluent easureent configuration. Production fro the gas well passes through a line heater (optional), where it is heated. This is typically done to vaporize soe of the hydrocarbon liquids and heat up the water and the gas in the strea before etering to prevent hydrate foration. For well testing purposes, test taps ust be located downstrea of this eter within the sae pipe run. The line heater, fuel gas tap, and other equipent, if present, ust be upstrea of the eter or downstrea of the test taps to ensure that the test eter is subjected to the sae condition as the effluent eter. After easureent, production fro the well is coingled with other flowlined effluent gas wells in the battery and sent to a group (battery) location, where single-phase (group) easureents of hydrocarbon liquids, gas, and water ust be conducted downstrea of separation. Figure 7.8. Typical gas well effluent etering configuration Fuel Test Taps Gas Well Line Heater (Optional) Effluent X X X To Gas Battery (Group Measureent) = easureent point For ost wells, the required iniu well testing frequency is annual unless the criteria in Section are et. Total battery water production ust be easured and prorated back to the individual wells, based on each well s estiated onthly water production. Estiated well water production is based on a WGR, deterined by periodic well tests ultiplied by the estiated onthly well gas production. SK Gas wells that produce oil, rather than condensate, ust not be tied into a Gas Multiwell Effluent Measureent Battery, unless the well oil and gas production volues are separated and easured prior to coingling with the effluent wells and either the Exeption criteria in Sections 5.5 and are et or site-specific approval has been obtained fro the Regulator prior to ipleentation. If the hydrocarbon liquid that a gas well produces changes fro condensate to oil, based on its density, see Section AB Gas wells that are classified as producing oil, rather than condensate, ust not be tied into a Gas Multiwell Effluent Measureent Battery, unless the well oil and gas production volues are separated and easured prior to coingling with the effluent wells and either the Exeption criteria in Sections 5.5 and are et or site-specific approval has been obtained fro the Regulator prior to ipleentation. If a gas well classified as producing condensate in a ultiwell effluent easureent battery is reclassified by the Regulator as producing oil, see Section August 1, 2017 Page 7-16

196 BC See Measureent Guideline for Upstrea Oil and Gas Operations Well Testing Well testing is typically perfored by directing well production downstrea of the effluent eter and within the sae pipe run through a three-phase portable test separator configured with dedicated eters for gas, condensate, and water, see Figure 7.9. Test equipent using two-phase separation is acceptable if hydrocarbon liquids are too sall to be easured during typical well test durations. Other options that provide equivalent liquid volue deterination accuracy ay also be considered. For exaple, if a three-phase separator is not available, alternative equipent, such as a two-phase separator with a total liquid eter and continuous water cut analyzer, ay be acceptable. The test ust be conducted as follows: 1. The test ust begin only after a liquid level stabilization period within the test separator. 2. The test duration ust be a iniu of 12 hours. 3. All new wells ust be tested within the first 30 days of initial production. 4. Consistent testing procedures ust be used for consecutive tests to identify if a change in a well s flow characteristics has occurred. 5. The gas, condensate, and water volues ust be easured. 6. The condensate ust be sapled during every test and subjected to a copositional analysis, which is to be used to deterine the GEF. The saple ay be taken fro the condensate leg of a three-phase separator or the liquid leg of a two-phase separator. The water ust be reoved fro the condensate before conducting the analysis. 7. The GEF ust be used to convert the liquid condensate volue deterined during the test to a GEV, which will be added to the easured test gas volue to deterine the total test gas volue if the condensate is not delivered for sale at the group easureent point. The ECF can then be deterined based on whether the condensate is recobined with the gas, see Section The WGR ust be deterined by dividing the test water volue by the su of the easured test gas volue and the gas equivalent of the easured test condensate volue if the condensate is not delivered for sale at the group easureent point, see Section For orifice eters, the effluent eter and the test gas eter ust use 24-hour charts for a test period of 24 hours or less, unless electronic flow easureent (EFM) is used; for testing periods longer than 24 hours, seven-day charts ay be used, provided that good, readable pen traces are aintained, see Section August 1, 2017 Page 7-17

197 Test Separator Figure 7.9. Typical effluent well easureent configuration with test unit Testing Unit Gas SP Metered and Recobined Condensate SP Fuel Produced Water Gas Well Effluent X X Test Taps Line Heater (Optional) X To Gas Battery (Group easureent) = easureent point Effluent Well Measureent and Testing Decision Tree The type of easureent and testing frequency for effluent easured wells ust follow the decision tree process in Figure Note that the starting point for initial well copletion or recopletion is different than for existing effluent easured stratigraphic units or zones or wells. August 1, 2017 Page 7-18

198 Figure Effluent well easureent and testing decision tree. (Text boxes are nubered fro left to right.) 1. Initial well copletion or recopletion Star t Here 2. Existing effluent easured wells/ zones Star t Here No 3. Ar e there unrecovered load fluids? Yes 4. Is the total LGR produced through the eter (liq) / (gas) based on initial or recopletion well test? 10. Yes 5. Install effluent eter & conduct onthly LG R test See Note 5 No a) Is the total weighted average onthly LGR at the reporting facility (liq)/ (gas) (excluding fluid volues fr o each well or r eporting facility with dedicated separation), and b) Is the hydr ocarbon liquid condensate (liq)/ (gas) (excluding any r ecovered hydrocarbon load fluids) for the well test evaluation per iod, and c) Have all working interest participants and Fr eehold royalty holder s (if present) been notified in writing and have no objections? Yes 6. Install 2-phase or 3-phase separation 8. Is the LGR rate / (gas) No Yes 7. Is the test LGR rate / (gas) after coplete load fluid recovery or a axiu of 12 onths? No 9. Effluent eter installation acceptable See Note 4. No 12. No effluent well testing required - re-evaluate in 12 onths Yes 11. Maintain 2-phase or 3- phase separation 14. No Effluent well testing required No 14. Is the operating pressure 350 kpag at the wellhead? Yes 15. Effluent well testing required No 16. Is the well flowing above critical lift rate at the last day of the well test evaluation period? See Note 3 Yes 17. Is this well par t of an approved zonal exeption? See Note 2 No 18. Was there an LG R test in the well test period (calendar quarter) prior to the current well test period (calendar quarter)? See Section No Yes See Note 1 Yes No 22. Was the test gas rate / day? Yes Yes 19. Does the well have electronic flow easureent for secondary & tertiary easureent? No 20. No effluent well testing required - re-evaluate in 12 onths No 23. Was this the 2 nd consecutive test wher e the LGR liq / gas and was the test gas rate / day? Yes 21. Was the LGR (liq) / (gas)? No Yes August 1, 2017 Page 7-19

199 Note 1: Where all wells in a facility are above critical lift and in a deeed exept stratigraphic unit or zone, if the LGR is greater than (liq) / (gas) at the respective facility inlet to which the wells flow, the stratigraphic unit or zone is not exept and the Note 1 path is to be followed. Note 2: Regulator stratigraphic unit or zonal easureent exeptions are by special approvals only. Note 3: The Turner Correlation 2 is used to approxiate critical lift. The calculation below produces a value in illion standard cubic feet (scf) per day. Use a factor of /scf to convert to etric units. Although there have been further refineents to the Turner Correlation calculation, the forulas below will be applied to deterine critical lift as it relates to the well easureent and testing decision tree. These siplified forulas assue a fixed-gas gravity (G) of 0.6 and fixed-gas teperature (T) of 120ºF. G = gas gravity P = Pressure (absolute) - lb force / square inch T = Teperature (absolute) degrees Rankine v g = Miniu gas velocity required to lift liquids ft / second Z = Copressibility factor A = Cross sectional area of flow square feet q g = Flow rate scf / day The following represents a saple Turner Correlation calculation: Evaluation period: Noveber October SCADA daily average tubing pressure, October: kpa Turner Correlation forula: assues G = 0.6 T = 48.9ºC (120ºF) Z = 0.9 Variable Value Units Calculation G 0.6 Z 0.9 T 580 Rankin [(48.9 x 1.8) + 32] k (2.693 x 0.6) (0.9 x 580) P 114 PSIA (684.6 kpa ) + ( kpa ) A Ft 2 [ x (1.995 inches 12) 2 ] 4 (tubing size = 2 3/8 inches) qg scf/d qg /d scf x /scf If both condensate and water are present, use the Turner Correlation for water to evaluate syste behavior. The Turner Correlation uses the cross-sectional area of the flow path when calculating liquid lift rates. For exaple, if the flow path is through the tubing, the 2 Turner, R. G., Hubbard, M. G., and Dukler, A. E., 1969, Analysis and Prediction of Miniu Flow Rate for the Continuous Reoval of Liquids fro Gas Wells, JPT 21(11): August 1, 2017 Page 7-20

200 iniu gas rate to lift water and condensate is calculated using the inside diaeter (ID) of the tubing. When the tubing depth is higher in the wellbore than the idpoint of perforations, the idpoint elevation between the highest and lowest perforations in the casing in a vertical well, the Turner Correlation does not consider the rate required to lift liquids between the idpoint of perforations and the end of the tubing. Ultiately, the liquid lift rate calculations are based on the tubing s ID or the area of the annulus and not on the casing s ID unless flow is up the casing only. Midpoint of perforations is the idpoint elevation between the highest and lowest perforations in the casing. The Midpoint of Perforations elevation is used in the Turner Correlation that plays a role in the well testing decision tree found in Section Note 4: Average Monthly LGR/CGR Calculation Follow Figure 7.10 to deterine if a facility exeption is appropriate for specific wells that flow to the reporting facility based on the total liquid/condensate volues versus the total gas volue easured at the group easureent point for the reporting onth. Production volues include not only volues easured at a group easureent point, but all fluid production volues used for reporting purposes. This requires accounting for all fluid volues that are received into or delivered out of the reporting facility for that reporting onth. LGR = [Total group easured liquids (condensate + water) + (Disposition + Inventory change before group easureent) Liquid received] [Total group easured gas + (fuel + flare + vent before group easureent) + Disposition before group gas easureent Gas received] CGR = [Total group easured condensate + (Disposition + Inventory change before group easureent) Condensate received] [Total group easured gas + (fuel + flare + vent before group easureent) + Disposition before group gas easureent Gas received] Note 5: An initial well test ust be conducted within 30 days of production and onthly thereafter. The WGR, CGR, and ECF factors fro the last test ust be used to calculate estiated production until the next test is conducted. Once full fluid recovery is achieved or the 12 onth period is passed, whichever coes first, the well ust be evaluated according to the decision tree process based on the last well test. Note 6: Wells that require biennial testing ust use the ECF, CGR, WGR, and saple analysis fro the ost current ECF test until the next ECF test results and saple analysis are available Well Test Evaluation The well testing evaluation period is based on a cycle of 12 consecutive onths that all of the wells in a reporting facility will identically follow. The well test evaluation period ust end two onths before the planned calendar quarter in which the required well testing will be conducted for a reporting facility. Once the evaluation period is chosen, it will reain fixed for a reporting facility. Well testing, when required according to Figure 7.10, ust occur once in the fixed calendar quarter. Figure 7.11 provides an illustrated exaple. Well and reporting facility data are gathered for the 12-onth period identified. The wells and/or the reporting facility would be analyzed within the context of the well easureent and testing decision tree. Initializing the design will establish the cycle that is repeated year over year. The operator is free to choose the well testing calendar quarter based on operations. The illustrated exaple shown in Figure 7.11 typically fits a well testing syste in which winter road access is available. August 1, 2017 Page 7-21

201 Figure Well test evaluation exaple Calendar Quarters Well Test Period Well testing occurs in January, February and / or March O N D J F M A M J J A S O N D J F M A 12 onths Noveber Well Testing Evaluation Period Noveber 2 onth period prior to January For the purposes of evaluating text box 10 of the well easureent and testing decision tree in Figure 7.10, the reporting facility and the affected wells such as wells without well separation will be on the sae well testing evaluation period. However, a reporting facility has operating characteristics such that a reporting facility well testing exeption in text box 10 is not possible, the well testing evaluation period can becoe unique to a well. This eans that for a well that requires testing according to the well easureent and testing decision tree, the well aintains a fixed well testing evaluation period, but the well testing evaluation period ay not be the sae for all of the wells in a reporting facility. If a facility is of such a size that it would take ore than one calendar quarter to test all of the wells, an operator can choose the calendar quarter in which a well test is to occur which in turn deterines the Well Testing Evaluation Period. Once the well testing period of a calendar quarter is chosen, the operator ust test once in the fixed calendar quarter period. The pressure data, as recorded by the well easureent equipent, will be the onthly average for the last onth of the well test evaluation period. If no tubing or casing pressure records are continuously recorded, then the upstrea static pressure data fro the well s flow eter ay be used to approxiate the tubing or casing pressure provided that the well s flow eter is located on the sae lease site as the wellhead Record Keeping The following lists the iniu records required related to well testing and/or the well easureent and testing decision tree where it is applicable: General Inforation: Producer Reporting facility nae and surface location Petrinex reporting code Well nae Well unique well identifier (UWI) Production foration nae and/or stratigraphic unit or zone code August 1, 2017 Page 7-22

202 Well Test Inforation: 7. Current well testing date 8. Last well test date 9. Effluent well eter run internal diaeter () 10. Meter run orifice size () (if applicable) 11. Test tap location (relative to effluent eter) 12. Test tap connection diaeter () 13. Last gas saple date 14. Last condensate saple date 15. Test gas average rate ( /day) 16. Test condensate average rate ( 3 /day) 17. Test water average rate ( 3 /day) 18. Current WGR ( 3 / ) 19. Current CGR ( 3 / ) 20. Current LGR ( 3 / ) 21. Last WGR ( 3 / ) 22. Last CGR ( 3 / ) 23. Last LGR ( 3 / ) 24. ECF last value calculated 25. ECF current value calculated Decision Tree Inforation 26. Wellhead tubing internal diaeter () 27. Wellhead casing internal diaeter () 28. Wellhead tubing pressure (KPa) 29. Wellhead casing pressure (KPa) 30. Effluent eter onthly average D/P for evaluation period (kpa) listed by onth (optional) 31. Effluent eter onthly average static pressure for evaluation period (KPa) listed by onth 32. Effluent eter onthly average teperature for evaluation period (ºC) listed by onth (optional) 33. Evaluation period average reporting facility LGR 34. Evaluation period average reporting facility CGR 35. Artificial lift ethod, i.e., cycling, plunger control 36. Well chart or EFM odel and ake August 1, 2017 Page 7-23

203 37. Well test evaluation period starting onth 38. Well test evaluation period ending onth 39. Date well dropped below critical velocity 40. Critical lift calculation for evaluation period 41. Well load fluid volues for evaluation period 42. Meters used in facility LGR calculations a. Meter tag b. Meter location c. Meter volue d. Meter units (10 3 3, etc.) 43. Well flow volue prior to recopletion (optional) 44. Well recopletion flow volue (optional) Revocation of Exeption Allowed by Decision Tree A testing exeption for an effluent gas well ay be revoked if certain criteria are not et. Baseline well testing ust be conducted if a testing exeption is revoked for any of the following reasons: 1. Noncopliance Potential areas of noncopliance include: a. Incorrect exeption calculations, b. Inadequate record keeping, c. Source data for exeption calculations cannot be validated, and d. Incorrect application/ipleentation of the well easureent and testing decision tree. 2. A working interest participant or Freehold ineral owner for any flowing well to the reporting facility objects to the exeption. Additionally, if the Regulator has a concern with the activities, operations, production data, or reporting associated with well testing, on notice in writing, the Regulator can partially or fully revoke well testing exeptions and ipose, odify, or substitute well testing conditions for any period of tie. The Regulator will advise the operator in writing as to the reason for the revocation, provide a reasonable tie period for the operator to eet the conditions set by the Regulator, and provide an opportunity for the operator to coent. Production Volue Calculations Monthly production volues are to be calculated as follows (see Figure 7.12). Units: All gas volues and GEV are to be in and liquid volues in 3. August 1, 2017 Page 7-24

204 Testing-Exept Battery For a battery that is exept fro testing, the voluetric calculation is to be based on the following: ECF = WGR = Battery-based water-gas ratio LGR = Battery-based liquid-gas ratio CGR = Battery-based condensate-gas ratio If battery condensate volues are recobined back into the gas strea, the gas equivalent of the recobined liquids will be calculated and added to the easured group gas volue to obtain the total battery gas volue. Condensate liquid volues will not be prorated to the wells. SK AB BC If battery condensate volues are tanked and trucked out for sale or for further processing, the condensate liquid volues will be prorated back to the wells in the battery based on the calculated battery CGR. If battery condensate volues are tanked and trucked out for sale (AB), the condensate liquid volues will be prorated back to the wells in the battery based on the calculated battery CGR. See Measureent Guideline for Upstrea Oil and Gas Operations Well water production ay be deterined by either: Calculating the battery water proration factor and then ultiplying the well s estiated water production by the battery s water proration factor or Multiplying the wells percentage of the total estiated gas production by the onthly easured battery water volue. In this case report a battery water proration factor of Exception: The operator ay, providing there is no objection fro the working interest owners of any well producing into the battery, use the WGR, CGR and ECF fro each well s ost recent ECF test instead of using the battery-calculated WGR, CGR and ECF of This option ay be used as long as the battery qualifies as a test-exept battery Testing - Exept Wells For a battering with both exept and nonexept wells, the voluetric calculation ust be based on the following: ECF = for exept wells For the wells that require testing, water production will be prorated to each well based on the well s individual WGR derived fro the well tests ultiplied by its estiated gas production. For those wells that are test exept, a battery WGR will be established and applied to all the test-exept wells after netting off the estiated water production of the tested wells. August 1, 2017 Page 7-25

205 If battery condensate volues are recobined back into the gas strea, the gas equivalent of the recobined liquids will be calculated and added to the easured group gas volue recobined volue and recobined analysis. Condensate liquid volues will not be prorated to the wells. Exception: For test-exept wells, the operator ay, at its discretion, use the WGR, CGR, and ECF fro each well s ost recent ECF test instead of using the battery-calculated WGR, CGR, and ECF of SK AB BC If battery condensate volues are tanked and trucked out for sale or for further processing, the tested wells estiated condensate production will be calculated based on each well s CGR derived fro the well tests ultiplied by the well s estiated gas production. For those wells that are test exept, a battery CGR will be established and applied to all the test-exept wells after netting off the estiated condensate production of the tested wells. If battery condensate volues are tanked and trucked out for sale, the tested wells estiated condensate production will be calculated based on each well s CGR derived fro the well tests ultiplied by the well s estiated gas production. For those wells that are test exept, a battery CGR will be established and applied to all the test-exept wells after netting off the estiated condensate production of the tested wells. See Measureent Guideline for Upstrea Oil and Gas Operations Nonexept Wells If there are no exept wells in the battery and condensate is delivered for sale at the group easureent point, go directly to ite 8. Otherwise, follow ites 1 to Calculate the ECF: ECF = (Well test gas volue [B] + GEV of well test condensate [C]) Effluent gas volue easured during test (A) Calculate estiated gas production for each well: Estiated onthly well gas volue = Monthly well effluent volue x ECF Calculate the WGR: WGR = Well test water volue (D) (Well test gas volue [B] + GEV of well test condensate [C]) Calculate estiated water production for each well: Estiated onthly well water volue = Estiated onthly well gas volue x WGR Calculate total battery estiated volues (gas and water): Total battery estiated onthly gas volue = Su of all estiated onthly well gas volues Total battery estiated onthly water volue = Su of all estiated onthly well water volues August 1, 2017 Page 7-26

206 Test Separator Figure Effluent well eter testing configuration with condensate production Testing Unit (B) Gas (C) Condensate Metered and Recobined Condensate and Water Fuel (D) Water Gas Well (A) Effluent X X Test Taps Line Heater (Optional) X To Gas Battery (Group easureent) = easureent point Calculate proration factors for gas and water: Gas Proration Factor = (Total battery easured onthly gas volue + GEV of total battery condensate) Total battery estiated onthly gas volue Water Proration Factor = Total battery actual onthly water volue Total battery estiated onthly water volue Calculate actual onthly (prorated) well production: Actual onthly well gas production = Estiated onthly well gas volue x Gas Proration Factor Actual onthly well water production = Estiated onthly well water volue x Water Proration Factor For the battery with condensate delivered for sale at the group easureent point: Calculate the ECF: ECF = Well test gas volue (B) Effluent gas volue easured during test (A) Calculate the well CGR: CGR = Well test condensate volue (C) Well test gas volue (B) 10. Calculate the WGR: WGR = Well test water volue (D) Well test gas volue (B) 11. Calculate estiated gas, condensate, and water production for each well: Estiated onthly well gas volue = Monthly well effluent volue x ECF Estiated onthly well condensate volue = Estiated onthly well gas volue x Condensate Gas Ratio Estiated onthly well water volue = Estiated onthly well gas volue x Water Gas Ratio 12. Calculate total estiated gas, condensate, and water production for the battery: August 1, 2017 Page 7-27

207 Total battery estiated onthly gas volue = Su of all estiated onthly well gas volues Total battery estiated onthly condensate volue = Su of all estiated onthly well condensate volues Total battery estiated onthly water volue = Su of all estiated onthly well water volues 13. Calculate total battery onthly gas, condensate, and water production: Total battery onthly gas volue = Total gas disposition + Flare + Vent + Fuel (take off before sales eter) Total battery onthly condensate volue = Total condensate disposition + inventory change Total battery onthly water volue = Total water disposition + inventory change 14. Calculate proration factors for gas, condensate, and water: Gas Proration Factor (GPF) = Total battery onthly gas volue Total battery estiated onthly gas volue Condensate Proration Factor (CPF) = Total battery onthly condensate volue Total battery estiated onthly condensate volue Water Proration Factor (WPF) = Total battery onthly water volue Total battery estiated onthly water volue 15. Calculate actual onthly (prorated) well production: Actual onthly well gas production = Estiated onthly well gas volue x Gas Proration Factor Actual onthly well condensate production = Estiated onthly well condensate volue x Condensate Proration Factor Actual onthly well water production = Estiated onthly well water volue x Water Proration Factor Sapling and Analysis Requireents Testing Exepted Batteries For testing exepted batteries, the well saple and analysis used ay be either: The saple and analysis obtained fro the ost recent ECF test or The annual saple and analysis obtained fro the group separator, provided that a. There is coon ownership in all wells in the battery; b. If there is no coon ownership, written notification has been given to all working interest participants, with no resulting objection received; and c. If there is no coon Crown or Freehold royalty and only Freehold royalties are involved, written notification has been given to all Freehold royalty owners, with no resulting objection received. If there is a ix of Freehold and Crown royalty involved, the licensee ust apply to the Regulator for approval. Regardless of which of the above approaches is used, the operator ay, at its discretion, test and saple any well and use the well saple and analysis to calculate well volue. August 1, 2017 Page 7-28

208 Testing Exepted Wells For test-exept wells in batteries that have tested and test-exept wells, the well saple and analysis used ay be either The saple and analysis obtained fro the ost recent ECF test or The annual saple and analysis obtained fro the group separator, provided that a. There is coon ownership in all wells in the battery; b. If there is no coon ownership, written notification has been given to all working interest participants, with no resulting objection received; and c. If there is no coon Crown or Freehold royalty and only Freehold royalties are involved, written notification has been given to all Freehold royalty owners, with no resulting objection received. Regardless of which of the above approaches is used, the operator ay, at its discretion, test and saple any test-exept well and use the well saple and analysis to calculate well volue Exeption for Gas Wells Producing Oil in Effluent Measureent Battery SK AB BC If the hydrocarbon liquid that a gas well produces changes fro condensate to oil, based on its density, the well ay reain in a Gas Multiwell Effluent Measureent Battery, provided that the well is equipped with a separator and there is continuous easureent of the gas and liquid coponents or, alternatively, the effluent eter is left in place and the easureent, accounting, and reporting procedures specified below are followed, (see Figure 7.13). If an existing gas well classified as producing condensate in a ultiwell effluent easureent battery is reclassified by the Regulator as a gas well producing oil, the well ay reain in the ultiwell effluent easureent battery provided that the well is equipped with a separator and there is continuous easureent of the gas and liquid coponents or, alternatively, the effluent eter is left in place and the easureent, accounting, and reporting procedures specified are followed, see Figure See Measureent Guideline for Upstrea Oil and Gas Operations Annual ECF-WGR tests ust be conducted on the well. These types of wells do not qualify for the test frequency exeptions or reductions described in Section 7.4. An OGR, to be used for the well oil production calculation, ust also be deterined during this test. The WGR, estiated water production, water proration factor, and actual water production are deterined in the sae anner as indicated in Section August 1, 2017 Page 7-29

209 Test Separator Figure Effluent well eter testing configuration with oil production Testing Unit (B) Gas (C) Oil Metered and Recobined Oil and Water Fuel (D) Water Gas Well (A) Effluent X X Test Taps Line Heater (Optional) X To Gas Battery (Group easureent) = easureent point Calculate the ECF: ECF = Well test gas volue (B) Effluent gas volue easured during test (A) Calculate estiated gas production for the well: Estiated onthly well gas volue = Monthly well effluent volue x ECF Calculate the OGR: OGR = Well test oil volue (C) Well test gas volue (B) Calculate actual well oil production: Actual onthly well oil volue = Estiated onthly well gas production x OGR Calculate the total onthly battery condensate volue: Total battery condensate volue = Total battery liquid hydrocarbon volue Total onthly oil volue Report the calculated onthly oil production volue as oil produced fro the well. Prorate onthly gas and water production as in Section Well Effluent Measureent in the Duvernay and Montney Stratigraphic Units Section 7.5 only applies to Alberta since Saskatchewan does not have Duvery and Montney Stratigraphic units. Unconventional resource developent plays such as the Duvernay and Montney forations in the northwestern part of Alberta present unique operational and easureent challenges, including the following: 1. Hydrocarbon liquid densities of oil wells (oil) and gas wells (condensate/oil) are very siilar, which can result in a ix of oil well and gas well classifications on a coon developent pad. This akes it difficult for operators to design production and easureent systes until the wells are drilled, tested, and classified. August 1, 2017 Page 7-30

210 2. 3. Initial well operating pressures and production rates are high and decline rapidly, e.g., initial pressures up to 60 MPa (8700 psi) and initial production rates of /d of gas. This adds significant costs to separator construction and akes it difficult to properly size separation equipent for the entire life cycle of the wells. Gas well LGRs are very high (up to approxiately liquid / gas [200 bbl/mmcf]) The equipent design, project developent delay, and cost challenges presented by highpressure, high-lgr unconventional oil and gas plays present an opportunity to ipleent a easureent, production accounting, and voluetric reporting syste that is applicable to both oil wells and gas wells drilled into a coon foration (either the Duvernay or Montney) and that delivers acceptable easureent perforance. The following discussion describes the qualifying criteria and the easureent syste and reporting requireents for two operational scenarios where it is acceptable to include effluent-easured, surface-coingled production fro oil and gas wells in a coon easureent and production accounting syste for gathering and deterining volues. After oil and gas well production volues are deterined, those volues ust be reported into Petrinex according to existing reporting requireents. Gas wells report production to an gas ultiwell effluent easureent battery (subtype 362), and oil wells report production to an crude oil battery (subtype 311 or 321). Oil wells report gas and oil volues and gas wells report gas and condensate/oil volues, depending on the well s voluetric gas well liquid (VGWL) classification Qualifying Criteria for Well Effluent Measureent in the Duvernay and Montney Stratigraphic Units Oil and gas wells eeting the following criteria ay be included in the ixed oil well / gas well effluent easureent syste: All wells are drilled and copleted in only the Duvernay foration, or all wells are drilled and copleted in only the Montney foration. Surface coingling of Duvernay and Montney wells within the sae easureent syste is not allowed. Gas well LGRs ay exceed liquid / gas with no upper LGR restriction, and the effluent easureent syste ay consist of only gas wells. Specifically, gas wells with LGRs > liquid / gas ay be effluent easured. All wells have coon ownership and either coon Crown or Freehold royalty. a. If there is no coon ownership, written notification has been given to all working interest participants, with no resulting objection received. b. If there are no coon Crown or Freehold royalties and only Freehold royalties are involved, written notification has been given to all Freehold royalty owners, with no resulting objection received. If there is a ix of Freehold and Crown royalty involved, the licensee ust apply to the Regulator for approval. August 1, 2017 Page 7-31

211 7.5.2 Measureent Systes requireents for Well Effluent Measureent in the Duvernay and Montney Stratigraphic Units The two effluent easureent operational scenarios described in Sections and ust adhere to the following coon requireents: Well and facility developents ust include test separation (peranent or portable) and test easureent systes to eet Section 7 effluent well testing requireents. Saple point installation ust coply with Section 8 sapling requireents. All wells ust calculate onthly estiated condensate/oil volues using the ost recent CGR/OGR, as deterined through ECF testing. The well ECF testing procedure and volue deterination ethodology (production accounting) ust be consistent fro one well to another, whether testing oil wells or gas wells. Well ECF tests ust be conducted onthly, at iniu, until stabilized flow fro the well is realized. Stabilized flow eans that the individual ECFs obtained fro the three ost recent ECF tests do not vary by ore than ±5.0 per cent of the average of the three ost recent ECFs. After stabilized flow is realized, ECF tests ust be conducted seiannually, at iniu. Battery gas and condensate/oil proration factors ust fall within the range of to If the proration factors fall outside this range, ECF tests ust be conducted ore frequently in order to bring the proration factors back within the required range. This requireent is in addition to the ECF test frequency described above i.e. ECF tests ay have to be conducted ore frequently than described above. Each well ust be sapled during each ECF test, and the group separator ust be sapled onthly to analyze gas and hydrocarbon liquids. The hydrocarbon liquid saple obtained fro each well during each ECF test ust undergo a ultistage flash liberation analysis (FLIB) or coputer flash siulation to obtain the shrinkage factor and gas-in-solution factor. a. The derived shrinkage factor will be applied to the hydrocarbon liquid test volues. b. The gas in solution factor will, when ultiplied by the test oil/condensate volue, yield the aount of gas that will flash out of oil/condensate as it is processed through the battery (ultistage flash). c. The derived flash gas volue will be added to the etered test gas volue to deterine the total test gas used in the proration. 10. The surface-coingled production fro all of the effluent-easured wells ust be connected by pipeline to a battery group separator where each phase (gas, hydrocarbon liquid, and water) can be individually etered or tanked. 11. Gas well production/disposition ust be reported as a facility subtype 362: Gas Multiwell Effluent Measureent battery. August 1, 2017 Page 7-32

212 12. Oil well production/disposition to the 362: Gas Multiwell Effluent Measureent battery ust be reported as subtype 311: Crude Oil Single-Well Battery or facility subtype 321: Crude Oil Multiwell Group Battery. 13. Through the Enhanced Production Audit Progra on Petrinex, operators ust notify the Regulator of the facility reporting codes of the batteries using the ixed oil well / gas well effluent easureent syste. 14. Annually, operators ust prepare and subit to the Regulator a easureent perforance report for each ixed oil well / gas well effluent easureent syste that has been ipleented. Additionally, operators ust eet with the Regulator easureent specialist annually to review the perforance reports. The reports ust contain the following data and discussion ites: a. A list of the wells and facilities included in the easureent syste. b. For each well, a chronological listing of ECF test and saple dates and the test results (test duration, test gas volue, test hydrocarbon liquid volue, test water volue, effluent etered volue, ECF, CGR, WGR, per cent change of ECF fro last test). The operator ust provide detailed individual ECF test data (source test easureent data) to the Regulator upon request. c. For each easureent syste, a chronological listing of onthly production volues for each reporting facility and the gas, hydrocarbon liquid, and water proration factors d. A general discussion of the perforance of the easureent syste, highlighting operational and easureent challenges, itigate easures taken if proration factors trended outside the required tolerances, best practices ipleented, lessons learned, etc. e. Additional developent plans for the upcoing year 15. All other requireents in this Directive reain in effect August 1, 2017 Page 7-33

213 7.5.3 Operational Scenario 1 Hydrocarbon Liquids are Recobined into the Gathering Syste Figure 7.14 Gas Multiwell Effluent Battery Effluent Meter Gas Well #1 Effluent Meter Test Header Separator Gas Group Meter (E) HC Liq. Meter (F) To Gas Gathering Syste or other facilities Gas Well #2 Effluent Meter (A) Test Gas Meter (B) Test Separator Test HC Liq. Meter (C) SP SP Produced Water Metered (G) and Recobined or Disposal Produced Water Disposal (Optional) Oil Well = easureent point SP Test Water Meter (D) Scenario 1 (see Figure 7.14) production easureent and well volue are deterined as follows: Production fro the gas wells and oil well is effluent easured, surface coingled, and sent to the battery group separator where it is separated into three phases, each separately easured. The hydrocarbon liquids and water are then recobined with the gas and sent to a gas gathering syste or to another facility such as a gas plant. Using standard ECF proration accounting procedures, individual well volues of gas and condensate/oil (gas wells), gas and oil (oil wells), and water are deterined. The oil well and gas well hydrocarbon liquid volues are calculated for each coponent using the saple analysis obtained during ECF testing. The oil well s oil and gas volues are then subtracted fro the group easured gas and hydrocarbon liquid volues to derive the effluent battery condensate/oil volue. The oil well s water production volue is also subtracted fro the battery s easured water volue. The oil well production is reported to an oil battery facility subtype 311 or 321 (stock tank liquid volue). The gas battery s liquid condensate is converted to a gas equivalent and added to the group separator gas volue. This is reported as a gas disposition fro gas ultiwell effluent easureent battery facility subtype 362. August 1, 2017 Page 7-34

214 Additional Measureent Syste Requireents Hydrocarbon Liquids are Recobined into the Gathering Syste In addition to the requireents set out in Section 7.5.2, Operational Scenario 1 ust also adhere to the following requireents: 1. The battery group separator and the well test separator ust be three-phase separators and use EFM for the condensate/oil and gas. 2. The battery group separator and well test separator condensate/oil leg ust use a Coriolis ass eter and a water-cut analyzer. 3. Gas and hydrocarbon liquid saple analysis for individual wells ust be used to calculate the well gas and hydrocarbon liquid GEV. 4. The group gas and hydrocarbon liquid saple analysis ust be used to calculate the group gas and hydrocarbon liquid GEV. 5. The hydrocarbon liquid eters at the test and group separators ust be proved to separator operating conditions. Production Accounting and Reporting Procedures Hydrocarbon Liquids are Recobined into the Gathering Syste Do the following after testing each well: Calculate the ECF: ECF = Well test gas volue / Effluent gas volue easured during test Calculate estiated onthly well gas volue: Estiated onthly well gas volue = Monthly well effluent volue ECF Obtain shrinkage factor (SF) and flash factor (GIS) for oil wells and gas equivalent factor (GEF) for gas wells fro the hydrocarbon liquid saple taken during the test Calculate the WGR WGR = Well test water volue / (Well test gas volue) Calculate estiated water production for each well: Estiated onthly well water volue = Estiated onthly well gas volue WGR Do the following after testing gas wells: Calculate the CGR or OGR: CGR or OGR = Well test condensate or oil volue / Well test gas volue Calculate estiated well condensate or oil production: Estiated onthly well condensate or oil volue = Estiated onthly well gas production CGR or OGR Do the following after testing oil wells: 1. Calculate the OGR: OGR = Well test oil volue / Well test gas volue 2. Calculate estiated well oil production: Estiated onthly well oil volue = Estiated onthly well gas production OGR August 1, 2017 Page 7-35

215 Do the following for all wells: 1. Calculate battery estiated volues Total battery estiated onthly gas volue = Su of all estiated onthly well gas volues Total battery estiated onthly hydrocarbon liquid volue = Su of all estiated onthly well hydrocarbon liquid volues Total battery estiated onthly water volue = Su of all estiated onthly well water volues 2. Calculate proration factors for gas, hydrocarbon liquids, and water: Gas proration factor = Total battery actual onthly gas volue / Total battery estiated onthly gas volue Hydrocarbon liquid proration factor = Total battery actual onthly hydrocarbon liquid volue / Total battery estiated onthly HC liquid volue Water proration factor = Total battery actual onthly water volue / Total battery estiated onthly water volue 3. Calculate onthly well production: Prorated onthly well gas production = Estiated onthly well gas volue gas proration factor Prorated onthly well hydrocarbon liquid production = Estiated onthly well hydrocarbon liquid volue hydrocarbon liquid proration factor Actual prorated onthly well water production = Estiated onthly well water volue water proration factor Do the following for oil wells: 1. Calculate the well actual oil and gas production volues after applying shrinkage and flash factors (see 3 above): Actual onthly oil production = Prorated onthly well oil production (1 SF) Flash gas volue = Actual onthly well oil production GIS Actual onthly gas production = Prorated onthly oil well gas production + Flash gas volue Do the following for gas wells: 1. Calculate GEV of prorated onthly well condensate2 production: GEV of condensate = Prorated onthly well condensate production GEF 2. Calculate actual onthly gas well volue: Actual onthly gas well volue = Prorated onthly gas production + GEV of condensate August 1, 2017 Page 7-36

216 7.5.4 Operational Scenario 2 Hydrocarbon Liquids are Delivered to Sales at the Battery Figure 7.15 Gas Well #1 Effluent Meter Gas Multiwell Effluent Battery Test Header Gas Group Meter (E) VRU SP To Gas Gathering Syste or other facilities Gas Well #2 Effluent Meter Test Gas Meter (B) SP Separator HC Liq. Tank Produced HC Liquid Trucked or Pipelined to Sales Effluent Meter (A) Test Separator Test HC Liq. Meter (C) SP Water Storage Produced Water Disposal Oil Well = easureent point SP Test Water Meter (D) Scenario 2 (see Figure 7.15) production easureent and well volue are deterined as follows: Production fro the gas wells and oil well is effluent etered, surface coingled, and sent to the battery group separator where it is separated into three phases, each separately easured (note that hydrocarbon liquids and water are easured at the receiving facility). The hydrocarbon liquids and water are individually tanked and disposed to sales (hydrocarbon liquids) or disposal/injection (water). The gas is delivered to a gas gathering syste or another facility such as a gas plant. Standard ECF proration accounting procedures are used to deterine individual well volues of gas and condensate/oil (gas wells), gas and oil (oil wells), and water. Oil, gas, and water volues fro oil wells are then subtracted fro the group easured gas, hydrocarbon liquid, and water volues. Oil production is reported to an oil battery facility subtype 311 or 321 for oil wells. For gas wells, the condensate/oil is reported as a liquid volue disposition fro a gas effluent easureent battery facility subtype 362. August 1, 2017 Page 7-37

217 Additional Measureent Syste Requireents Hydrocarbon Liquids are Delivered to Sales at the Battery In addition to the requireents set out in Section 7.5.2, Operational Scenario 2 ust also adhere to the following requireents: The battery group separator ust have three-phase separation and use EFM to deterine gas volues. The well test separator ust be a three-phase separator and use EFM for condensate/oil and gas, and the condensate/oil leg of the separator ust use a Coriolis ass eter and a water-cut analyzer. Gas and hydrocarbon liquid saple analyses fro individual wells ust be used to calculate the well gas and hydrocarbon liquid GEV. The group gas saple analysis ust be used to calculate the group GEV. The hydrocarbon liquid eter at the test separator ust be proved to stock tank conditions. Condensate/oil at the battery ust be handled in one of the following ways: a. b. c. Condensate/oil tanks ust incorporate a vapour recovery syste to capture and conserve hydrocarbon vapours that would flash fro the hydrocarbon liquids; Condensate/oil ust be stored in pressure vessels of a pressure rating sufficient to ensure that no vapours are vented; or Condensate/oil ust be processed to ensure vapour anageent coplies with Directive 060, Section 8.1(4) for atospheric storage tanks vented to atosphere or flared. Production Accounting and Reporting Procedures Hydrocarbon Liquids are delivered to Sales at the Battery Do the following after testing each well: 1. Calculate the ECF: ECF = Well test gas volue / Effluent gas volue easured during test Calculate estiated gas production: Estiated onthly well gas volue = Monthly well effluent volue ECF Obtain GIS for wells fro the hydrocarbon liquid saple taken during test Calculate the WGR WGR = Well test water volue / (Well test gas volue) Calculate estiated water production for each well: Estiated onthly well water volue = Estiated onthly well gas volue WGR Do the following after testing gas wells: 1. Calculate the CGR or OGR: August 1, 2017 Page 7-38

218 CGR or OGR = Well test condensate or oil volue / Well test gas volue 2. Calculate estiated well condensate or oil and gas production: Estiated onthly well condensate or oil volue = Estiated onthly well gas production CGR or OGR Estiated onthly well flashed gas volue = Estiated onthly well condensate or oil volue GIS Total estiated onthly well gas volue = Estiated onthly well gas volue + Estiated onthly well flashed gas volue Do the following after testing oil wells: 1. Calculate the OGR: OGR = Well test oil volue / Well test gas volue 2. Calculate estiated well oil and gas production: Estiated onthly well oil volue = Estiated onthly well gas production OGR Estiated onthly well flashed gas volue = Estiated onthly well oil volue GIS Total estiated onthly well gas volue = Estiated onthly well gas volue + Estiated onthly flashed gas volue Do the following for all wells: 1. Calculate total battery estiated volues Total battery estiated onthly gas volue = Su of all estiated onthly well gas volues Total battery estiated onthly hydrocarbon liquid volue = Su of all estiated onthly well hydrocarbon liquid (oil and condensate) volues Total battery estiated onthly water volue = Su of all estiated onthly well water volues 2. Calculate proration factors for gas and hydrocarbon liquid: Gas proration factor = Total battery actual onthly gas volue / Total battery estiated onthly gas volue Hydrocarbon liquid proration factor = Total battery actual onthly hydrocarbon liquid volue / Total battery estiated onthly hydrocarbon liquid volue Water proration factor = Total battery actual onthly water volue / Total battery estiated onthly water volue 3. Calculate onthly well production: Actual prorated onthly well gas production = Estiated onthly well gas volue gas proration factor Actual prorated onthly well hydrocarbon liquid production = Estiated onthly well hydrocarbon liquid volue hydrocarbon liquid proration factor August 1, 2017 Page 7-39

219 Actual prorated onthly well water production = Estiated onthly well water volue water proration factor The volues and proration factors above will be reported on Petrinex under the gas battery for gas wells and the oil battery for oil wells. August 1, 2017 Page 7-40

220 8 Gas and Liquid Sapling and Analysis This section outlines the gas and related liquid sapling and analysis requireents for the various categories of production easureent. These requireents add to the requireents in: SK AB BC Section 83 of the Oil and Conservation Regulation, 2012, which continue to apply. Sections and of the OGCR, which continue to apply. Oil and Gas Activities Act The requireents vary, depending on a nuber of factors, such as production rate, potential for the coposition to change over tie, and the end use of the fluid. Where appropriate, conditions have been identified under which the sapling and analysis requireents ay be altered or eliinated altogether. The Regulator ay also consider applications for further requireent alterations or eliinations if the licensee can deonstrate that easureent accuracy would either not be reduced or not ipact royalty, equity, environent, public safety or reservoir engineering concerns. SK AB BC In Saskatchewan, all sapling and analysis reports ust be uploaded within 30 days of the analysis being copleted as per Minister s specifications which are laid out in Directive PNG013: Well Data Subission Requireents Upon Regulator Request Upon Regulator Request 8.1 General Gas and liquid analyses are required for the deterination of gas volues, conversion of liquid volues to gas equivalent, and product allocation. The sapling and analysis requireents identified in Section 8 pertain only to those areas that affect the calculations and reporting required by the Regulator. These requireents apply solely to the easureent of hydrocarbon fluids and are not intended to supersede the business requireents that licensees are required to eet regarding product allocations. If oil is produced fro gas wells, as defined by the Regulator, oil ust be reported as liquid oil production and not as a gas equivalent volue (GEV). Therefore copositional analysis of the oil is not required for that purpose. The oil produced ay be cobined with the gas and delivered to a gas plant or other facilities for further processing, or the oil could be separated fro the gas at the well equipent and directed to tankage, and then on to sales or further treatent. Gas density and coposition are integral coponents of gas volue calculations and plant product allocation calculations. For differential producing eters, such as orifice eters, April 1, 2017 Page 8-1

221 venturi eters, and flow nozzles, the accuracy of a coputed volue and coponent allocations are very sensitive to the accuracy of the copositional analysis, which is the basis for copressibility factors and density deterination. For linear eters, such as ultrasonic and vortex, the copositional analysis is priarily used to deterine the copressibility factors. SK AB BC If liquid condensate produced fro gas wells is recobined with the gas well production, the copositional analysis fro a condensate saple ust be used to deterine the GEV of the condensate, which ust be added to the well gas volue for reporting purposes. A siilar procedure applies to gas gathering systes where liquid condensate is delivered to other facilities. For this reason, the condensate sapling requireents ust irror the gas sapling requireents. If liquid condensate is separated at a well, battery, or gas gathering syste and delivered fro that point for sale or other disposition or trucked for further processing, the condensate ust be reported as a liquid volue. Therefore, a copositional analysis of the condensate is not required for gas equivalent volue deterination purposes but ay be required for the purposes of the sale. If liquid condensate produced fro gas wells is recobined with the gas well production or trucked to the inlet of a gas plant for further processing, the copositional analysis fro a condensate saple ust be used to deterine the GEV of the condensate, which ust be added to the well gas volue for reporting purposes. A siilar procedure applies to gas gathering systes where liquid condensate is delivered to other facilities. For this reason, the condensate sapling requireents ust irror the gas sapling requireents. If liquid condensate is separated at a well, battery, or gas gathering syste and delivered fro that point for sale or other disposition without further processing, the condensate ust be reported as a liquid volue. Therefore, a copositional analysis of the condensate is not required for gas equivalent volue deterination purposes but ay be required for the purposes of the sale. See Measureent Guideline for Upstrea Oil and Gas Operations Sapling and analysis frequencies and updating requireents for the various production types are suarized in Section 8.4. Further details are provided in the sections that follow. These sapling frequencies are the base requireents for gas and related liquid easureent. Sapling and analysis of oil/eulsion streas at oil and gas wells and batteries are perfored to deterine the relative oil and water content of the streas. Oil/eulsion sapling and analysis are discussed in Section Sapling and Analysis Requireents Except where noted in this Directive, the gas sapling equipent and ethodology ust follow the requireents set out in API MPMS 14.1 of June 2001, Gas Processors Association (GPA) , or other equivalent industry standards. August 1, 2017 Page 8-2

222 Except where noted in this Directive, the condensate sapling equipent and ethodology ust follow the requireents set out in GPA , the evacuated cylinder ethod cited in GPA , or in other equivalent industry standards. Saples and analysis ay be obtained by any of the following ethods: 1. On-site gas chroatograph (GC) 2. Proportional sapling 3. Spot or grab sapling Spot or grab saples are acceptable for obtaining gas and liquid analyses once per test or per deterination, provided that uncertainty requireents in Section 1, Standards of Accuracy are fulfilled. When the uncertainty requireents cannot be et, licensees ust consider ore frequent sapling, calculated analyses in Section 8.3.2, proportional saplers, or chroatographs. For exaple, if the analysis fro one tie period to the next is such that the density and/or copressibility changes cause the volue to change by ore than the allowable uncertainty, a ore frequent analysis is required or an alternative ethod of obtaining the saple ust be used. The gas and liquid analyses ust be updated when operating conditions are significantly altered through addition/reoval of copression or line-heating, addition/reoval of production sources in a coon strea, wellbore recopletion. If the gas volues for all eters in the coon strea such as sales, fuel, flare, and injection gases eet the uncertainty guidelines in Section 1, Standards of Accuracy, the licensee ay use a single gas analysis for all eters on the coon strea Sapling Procedures 1. Saple points ust be located to provide representative saples. 2. Saple probes ust not be located within the iniu upstrea straight lengths of the eter. 3. Access fro grade or platfor ust be provided for the saple point. 4. If saple transfer tubing is to be used, its length ust be iniized. 5. The saple transfer tubing ust be oriented to iniize the potential to trap liquids in gas saples and water in condensate saples. 6. A eans ust be provided to safely purge saple transfer tubing between the saple point and the connection point of the saple cylinder. 7. Saple containers ust be clean and eet the pressure, teperature, and aterials requireents of the intended service and have the required Regulatory approvals as necessary. 8. The procedures used for sapling, transportation, handling, storage, and analysis ust ensure that atospheric containation does not occur. All saples ust be analyzed using a gas chroatograph or equivalent to deterine the coponents to a iniu of C 7+ coposition except for sales or delivery points where C 6+ coposition is acceptable if agreed upon by affected parties. The gas coposition analysis August 1, 2017 Page 8-3

223 ust be deterined to a iniu of four decial points as a fraction of or two decial points as a percentage of 100, and the relative density ust be deterined to a iniu of three decial points Saple Point and Probes The saple point location and probe installation requireents that follow apply to all Regulator easureent points. SK AB BC With the exception of sales/delivery point easureent, current saple point locations and installations existing prior to when this Directive coes into force, do not have to be upgraded to eet the saple probe requireents but ust eet the saple point requireents. With the exception of sales/delivery (royalty trigger) point easureent, current saple point locations and installations existing prior to Deceber 5, 2007, do not have to be upgraded to eet the saple probe requireents but ust eet the saple point requireents. See Measureent Guideline for Upstrea Oil and Gas Operations A saple probe ust be installed according to the requireents in this section when an installation is relocated or reused for another well or facility Requireents for Gas Sapling 1. For sapling applications where the gas is at or near its hydrocarbon dew point, a saple probe ust be used. This requireent applies to any separator application where hydrocarbon liquids are present. 2. For gas applications where the gas is not near its hydrocarbon dew point, the licensee ay use a saple probe. 3. The preferred location for gas saple points is the top of horizontal lines. 4. An optional location for gas saple probes is the side of vertical lines with the probe tip sloping 45 downward. 5. Saple probes ust be located at least five pipe diaeters downstrea of any piping disturbances, such as bends, elbows, headers, and tees. 6. The location of the saple point ust be such that phase changes due to changes in pressure and/or teperature are iniized. Specifically, for gases at or near their hydrocarbon dew point, saple points ust not be located downstrea of pressure-reducing coponents, such as control valves, flow conditioners, and Regulators, or long lengths of un-insulated piping or within five pipe diaeters downstrea of an orifice plate. 7. Saple points ay be located downstrea of ultrasonic eters that experience iniu pressure drop through the eter unless a flow conditioner is used and the gas is at or near its hydrocarbon dew point, in which case the saple point ust be upstrea of the flow conditioner. 8. Insulation and heat tracing ust be used to eliinate any cold spots between the saple point and the entry point into the saple container or gas chroatograph August 1, 2017 Page 8-4

224 where the saple transfer tubing teperature falls below the hydrocarbon dew point, such as at all separator applications. 9. Saple points used to saple blends of two gas streas ust have provision for ixing, such as an upstrea static ixer, with due consideration to potential phase changes brought about by a pressure drop associated with the ixing device. 10. Orifice eter ipulse lines or transitter anifolds lines ust not be used for taking saples. 11. Level gauge connections ust not be used for taking saples Requireents for Condensate Sapling With the exception of two-phase separators, a saple probe is recoended. A saple probe ust be installed for saples to be used to deterine water cut when there is eulsion or a ix of water and hydrocarbon, such as two-phase separators. For such applications, the sapling syste design ust eet the requireents of API MPMS 8.2 with respect to the use of ixers, saple probe location, and design. The preferred location for condensate saple points is the side of horizontal lines. An optional location for liquid saple points is the side of vertical lines with the probe tip sloping 45 downward. The location of the saple point ust be such that phase changes due to changes in pressure and/or teperature are iniized. Specifically, saple points ust not be located where vapour breakout is likely such as downstrea of pressurereducing coponents, orifice plates, flow conditioners, turbine, PD or Coriolis ass eters, control valves, and Regulators or where the strea teperature has increased. For separator applications, the saple point ust be between the separator outlet and the flow/level control valve upstrea of the eter, unless a pressure booster pup is used, in which case the saple point ust be located between the pup discharge and the eter. Orifice eter ipulse lines or transitter anifolds lines ust not be used for taking saples. Level gauge connections ust not be used for taking saples. H 2 S Sapling and Analysis This section relates to obtaining high pressure saples. Special considerations, such as extra saple(s) or purging, should be taken when obtaining low pressure saples at a boot separator configuration, treater, stabilizer, or at an acid gas facility. Hydrogen sulphide (H 2 S) is a reactive olecule that presents challenges for sapling and analysis of gas ixtures containing it. H 2 S is easily lost during sapling and analysis, resulting in underreporting of H 2 S concentrations. Factors that affect representative sapling and analysis accuracy through H 2 S loss are: Presence of air, water, or other sulphur-containing olecules Presence of reactive or absorptive sapling container surfaces August 1, 2017 Page 8-5

225 Presence of a liquid phase, which can absorb H 2 S H 2 S concentration Saple pressure and teperature Analysis ethod Tie lapse between sapling and analysis The aount of H 2 S lost can be reduced by: Proper saple point selection, which iniizes the presence of containants such as air, water, and aines Using clean containers ade of aterials that iniize H 2 S reactions or absorption Miniizing the tie between sapling and analysis Typical construction aterials for cylinders are stainless steel and aluinu. Inert coated cylinders, glass containers, and non-absorptive elastoer bags can be considered to further iniize H 2 S degradation, especially for concentrations of H 2 S less than 5000 pp when oisture is present. The choice of analytical technique also affects the aount of H 2 S reported. Instruentoriented techniques, such as gas chroatography, are typically ore precise than cheistry-oriented techniques, such as Tutweiler titrations or stain tubes. However, such instruent-oriented techniques are often ipractical for individual well site applications. Therefore, consideration should be given to analysis technique liitations and saple degradation as they relate to the specific reporting requireents in deterining the best approach. See Table 8.1 for analysis technique coparison. With the exception of pp level concentrations of H 2 S in the presence of oisture, a field H 2 S deterination and a laboratory GC analysis are recoended. These analysis techniques provide a degree of redundancy and a check of the field analysis. Above 5% H 2 S, the GC value is typically ore reliable. Below 5% H 2 S, the higher of the two values ust be used. Unexpectedly large variances between lab and field H 2 S values ust be investigated. Table 8.1. H 2 S analysis technique coparison Analysis Lower detection Advantages technique liit Online GC 500 pp Real-tie, accuracy Laboratory GC Tutweiler GPA C-1 Stain Tubes GPA 2377 Minial elapsed tie Liitations Capital cost, ongoing aintenance 500 pp Precision, accuracy Potential degradation during transport that varies with H2S concentration 1500 pp On site Titration apparatus, reagent quality, variability in operator technique, including visual endpoint detection, coputations, ercaptan interference 1 pp On site Poor precision (±25%) Matrix effects as described in anufacturer s specifications August 1, 2017 Page 8-6

226 Analysis by gas chroatography is the preferred ethod at higher H 2 S concentrations. For H 2 S concentrations between 1500 and 5000 pp, it is recoended that both stain tube and Tutweiler values be obtained if online GC is not used. If high accuracy of low-level, below 1500 pp, H 2 S concentration is required, consideration should be given to using a low-level sulphur-specific detector, such as a GC sulphur cheiluinescence detector. Sulphur Cheiluine Scene Detectors is a category of sulphur selective detectors that achieve a low detection liit of H 2 S and other sulphur copounds, such as ercaptans, sulphides, and disulphides. These detectors are used in easureent of H 2 S in natural gas streas. The use of containers that iniize degradation and the tie elapsed between sapling and analysis is also recoended in these situations. Refer to Appendix 4 for ore detail on the analytical ethods used in the industry for deterining H 2 S concentrations in gas saples Copositional Analysis of Natural Gas The two recoended procedures for copositional analysis of natural gas are based on GPA Standard : Tentative Method of Extended Analysis for Natural Gas and Siilar Gaseous Mixtures by Teperature Prograed Gas Chroatography and GPA Standard : Analysis for Natural Gas and Siilar Gaseous Mixtures by Gas Chroatography. If a thorough olecular weight and density description of the C 7+ fraction is required, analytical ethods based on GPA Standard 2286 are ore accurate and preferred. Specifically, GPA Standard 2286 akes use of a high-resolution colun and flae ionization detector to separate and quantify the heavier C 7+ coponents, which is then used for calculation purposes. Extended analysis of natural gases is coon but has not been fully standardized; therefore soe inter-laboratory bias ay occur. If the C 7+ properties are well defined or have been agreed upon by all affected parties, analytical ethods based on GPA Standard 2261 are suitable. The principal advantage of the precut ethod specified in GPA Standard 2261 is that all of the C 7+ coponents can be grouped together into a single sharp chroatograph peak. Grouping of the nuerous heavy copounds results in ore precise easureent of the cobined peak area. The priary disadvantage of GPA Standard 2261 is the lack of inforation gained with respect to the coposition of the C 7+ fraction. Inherently, if the coposition of the C 7+ fraction is unknown, soe agreed-upon physical properties ust be applied for calculation purposes. The GC C 7+ calibration is also affected, which increases the uncertainty of the C 7+ easureent and heating value coputation. If detailed inforation on C 7+ physical properties is not available, default values can be applied, as in Table 8.2. Table 8.2. Recoended default values for C 7+ properties* Molecular ass Liquid density kg/ 3 at Coponent Naes gras per ole 15 o C Heating value MJ/ 3 C 7+, Heptanes plus * C 7+ is a pseudo-copound. The values in ost scenarios have been found to adequately represent the heavier fraction of natural gas saples. August 1, 2017 Page 8-7

227 8.3 Gas Equivalent Factor Deterination fro Condensate Gas Equivalent Factor (GEF) is the volue of gas, at base conditions that would result fro converting of liquid into a gas. GEF is used when there is a requireent to report the gas equivalent volue (GEV) of condensate and other hydrocarbon liquids to the Regulator. The GEF of a liquid ay be calculated by any one of three ethods described in Appendix 5, depending upon the type of coponent analysis conducted on the liquid such as volue, ole, or ass fractions and the known properties of the liquid Engineering Data Specific constants are used in calculating the GEF. Absolute density of liquids should be used instead of relative density. The exaples in Appendix 5 present the different ethodologies used to calculate the GEF. All physical properties are based on GPA Standard (2003 or later) published data. 1 kol = kpa and 15 º C Calculated Copositional Analyses In soe instances, representative sapling of a hydrocarbon strea is not possible or feasible because of econoics, and calculation of a fluid coposition is required, as described in this section: Calculated Well Strea Analysis: It is not possible to accurately saple ultiphase streas, so the coposition of a recobined well strea ust be deterined by calculation. Such an analysis is typically not used for easureent, as it represents a ultiphase fluid strea and ost gas is easured as single phase. However, soe copanies use this analysis for calculation of gas volues fro effluent easured wells. Calculated well strea analyses are ost coonly used in product allocation calculations. Calculated Group Analysis: It is often difficult to accurately deterine the average coposition of fluids at a coingled group easureent point, as wells/sources to the group syste flow at different rates and the coposition is constantly changing. The recoended options for sapling these streas are on-line gas chroatographs or proportional sapling systes. However, if the recoended options are not practical or econoical, a flow-weighted calculated analysis ay be a viable option. Calculated Single Analysis: Soeties a single analysis cannot represent the coposition for an entire easureent period. In such scenarios, ultiple analyses of a single point ust be cobined to deterine the coposition for the period. An exaple of this is a sales gas strea where a proportional saple is taken weekly but a single coposition for the onth is required. The principles to be followed for each of these calculated analyses follow Calculated Well Strea Copositional Analysis This type of analysis applies to wells only and is eant to represent the hydrocarbon fluid coposition produced fro a well and/or delivered to a gathering syste. In ost scenarios, it represents the coposition of hydrocarbons being produced fro the August 1, 2017 Page 8-8

228 reservoir. The calculation is a flow-weighted recobination of the hydrocarbon gas and liquid streas. The accuracy of the flow rates used in this calculation is as iportant as the gas and liquid coposition. Subject to the exeption criteria described in the following paragraph, the gas and liquid flow rates used ust be fro the sae day that the gas and liquid saples were obtained. Flow rates fro the day of sapling ust be used in deterining recobined copositions, with the following exeptions: 1. When the daily liquid-to-gas ratio is constant, volues fro an extended period such as ultiday or up to onthly ay be used. 2. If soe of the liquid strea is not recobined in a onth such as scenarios where it is dropped to a tank, the coposition flow volue of the liquids not recobined ust be deducted fro the initial recobined coposition. This is typically perfored by recalculating the recobined coposition with new flow rates, typically the flow rates for the onth. See the exaple in Appendix Calculated Group Copositional Analysis This type of analysis is a flow-weighted representation of the hydrocarbon fluid coposition produced fro a group of wells or eter points. It is often used at coingled group points such as inlets, copressors and certain process points where it is difficult to obtain representative saples using spot sapling techniques. Ideally, proportional saplers should be eployed in such situations. However, when proportional sapling is not practical or possible, a calculated group analysis can be deterined based on the volue and coposition of the wells/eters that flow to the coingled point. The accuracy of the flow rates used in this calculation is as iportant as the gas and liquid coposition. The flow volues used for each well/eter should be actual easured volues for the period that the analysis is being calculated for, typically onthly. For exaple, five gas wells producing fro different pools with different coposition deliver gas to a copressor station where the gas is easured. Accurate spot sapling at the copressor station is difficult due to changing flow rates at the wells. Using spot saples taken at the wells and onthly flow rates, the producer calculates a group analysis for the copressor station eter. Care ust be taken when separator liquids are produced that all hydrocarbons are correctly accounted for, regardless of the phase. See the exaple in Appendix 6. Calculated Single Copositional Analysis This type of analysis is a flow-weighted representation of the hydrocarbon fluid coposition deterined at a single saple point. It is typically used at saple points that have variable copositions and are sapled frequently, such as weekly, using spot or proportional sapling. Ideally, proportional saplers or gas chroatographs should be eployed in such situations. However, when proportional sapling is not practical or possible, a calculated single analysis can be deterined based on the volue and coposition of a group of analyses at the saple point. The accuracy of the flow rates used in this calculation is as iportant as the gas and liquid coposition. The flow volues used for each saple ust be actual easured volues for the period that the analysis is representative of. For exaple, a producer takes spot saples of an inlet strea weekly August 1, 2017 Page 8-9

229 because proportional sapling or on-line sapling is not practical. Using weekly flow rates, the producer calculates a onthly flow-weighted coposition of the inlet strea. See the exaple in Appendix Sapling and Analysis Frequency Table 8.3 gives the analysis update frequency for gas and condensate streas. The sapling and analysis of condensate, if applicable, ust be perfored at the sae tie as the gas sapling. The configurations shown in Figures 8.1 through 8.17 are exaples. In each scenario, other siilar configurations ay also apply. SK AB BC New gas and condensate saples ust be taken for all new wells and easureent points within 30 days following the first onth of production. For the tie period prior to receipt of a new coposition, a substitute coposition ay be used for gas easureent and gas equivalent of liquid calculations. Gas and condensate saples ust be taken for all existing wells and easureent points by April 1, 2020 unless one has already been copleted or has an autoatic exeption as per Section 8. For the tie period prior to April 1, 2020, a substitute coposition ay be used for gas easureent and gas equivalent of liquid calculations. In Saskatchewan, all sapling and analysis reports ust be uploaded within 30 days of the analysis being copleted as per Minister s specifications listed in Directive PNG013: Well Data Subission Requireents. If an analysis has already been copleted it ust be uploaded before April 1, 2020 as per the Minister s specifications listed in Directive PNG013: Well Data Subission Requireents. New gas and liquid saples ust be taken for all new wells and easureent points by the end of the onth following the first onth of production. For the tie period prior to receipt of a new coposition, a substitute coposition ay be used for gas easureent and gas equivalent of liquid calculations. See Measureent Guideline for Upstrea Oil and Gas Operations For wells, substitute copositions ust be fro a well producing fro the sae pool with siilar separator operating conditions or fro saples taken during well testing. Copositions taken during well tests should be carefully reviewed prior to use, as saples are typically taken at different conditions fro those the well produces at and there are often containants such as nitrogen or frac fluid in test saples. For non-well eters, the substitute coposition should be as close to what is expected as reasonably possible. If the initial gas volue calculated by a substitute analysis is found to be in error by greater than 2% and the error volue is over /onth, retroactive voluetric adjustents ust be calculated using the initial gas coposition. See Section for inforation regarding voluetric data aendents in Petrinex resulting fro errors caused by using substitute gas and condensate analyses. August 1, 2017 Page 8-10

230 Table 8.3. Sapling and analysis frequencies for various types of facilities Gas wells/ batteries/ facilities Non-heavy oil wells/ batteries Type of production battery/facility SW Saskatchewan and SE Alberta shallow gas stratigraphic units or zones or areas or coalbed ethane (CBM) well with inial water See Section Gas proration outside SW Saskatchewan and SE Alberta shallow gas stratigraphic units or zones or areas or effluent easureent battery See Sections & Multiwell group battery or singlewell battery including CBM well/battery with no condensate or oil See Section Multiwell group battery or singlewell battery with condensate or oil See Section Gas storage schees, injection and withdrawal phase See Section Gas cycling schees See Section Gas sales/delivery See Section Gas plants See Section Injection Production Lift Gas using return gas fro gas plant (Scenario 3 of Section ) Gas gathering systes See Section Single-well/ ultiwell group battery See Section Gas rate /d Saple and analysis type Sapling point Frequency N/A Gas only Group eter Biennially N/A Gas/condensate Test eters At tie of testing Group eter Annually N/A Gas only All eters Annual first year, then Biennially > 16.9 Gas/condensate Per eter Annually 16.9 Gas/condensate Per eter Biennially Gas Per injection/ production eter Gas/condensate Per injection eter Per production eter First onth, then sei-annually Per approval or source requireent (if not in approval) Per approval or sei-annually (if not in approval) Gas only Per eter Annually Gas/condensate Per accounting eter Seiannually Gas only Per eter Seiannually > 16.9 Gas/condensate Per inlet eter 16.9 Gas/condensate Per inlet eter Annually Biennially Flared Gas only Per eter Initial Conserved > 16.9 Gas only Per eter Annually 16.9 Gas only Per eter Biennially August 1, 2017 Page 8-11

231 Heavy oil 1 batteries See Section Water source well/battery Type of production battery/facility Multiwell proration battery See Section Single-well/ ultiwell group battery Multiwell proration battery Single-well/ ultiwell battery Priary production and water flood See Section Miscible/i iscible flood See Section Heavy oil is crude oil with a density 920 kg/ 3 at 15 o C Gas rate /d Saple and analysis type Sapling point > 16.9 Gas only Per test/group eter per pool 16.9 Gas only Per test/group eter per pool Production Gas only Per test/group eter Frequency Annually Biennially Per approval or quarterly (if not in approval) Injection Per eter Per approval or onthly (if not in approval) 2.0 Gas only Per well Initial > 2.0 Gas only Per eter Biennially 2.0 Gas only Per eter/ Per pool > 2.0 Gas only Per test/group eter Gas only (if present) Per well Initial Biennially Licensees ust ensure that analysis data are used to update voluetric calculations by the end of the onth following the receipt of the analysis report. The only exception is for effluent wells, for which the analysis ust be updated by the end of the second onth following receipt of the analysis report. If sapling and analysis are conducted for other purposes, such as joint venture and allocation agreeents, ore frequently than required by this Directive, the licensee ust use those data to update voluetric calculations. Initial Gas Multiwell Proration SW Saskatchewan and SE Alberta Batteries with Minial Water (Petrinex facility subtypes: 363 in SK and 363 and 366 in AB including CBM) SK AB Shallow gas wells are those that produce fro shallow gas stratigraphic units or zones, including coals and shales fro the botto of the Glacial Drift to the botto of the Upper Cretaceous. The production fro two or ore of these stratigraphic units or zones without segregation in the wellbore requires either prior approval fro the Regulator for coingled production. Shallow gas wells are those that produce fro shallow gas stratigraphic units or zones, including coals and shales fro the top of the Edonton Group to the base of the Colorado Group. The production fro two or ore of these zones without segregation in the wellbore requires either prior approval fro the Regulator for coingled production, which has been granted in a portion of SE Alberta in Order No. MU 7490 or adherence to the self-declared coingled production August 1, 2017 Page 8-12

232 requireents described in Directive 065. BC See Measureent Guideline for Upstrea Oil and Gas Operations In the configuration of Figure 8.1 of shallow gas wells or CBM wells with water production not ore than / gas, analyses ust be updated biennially at group gas eter A. No sapling and analysis are required at the test eter or well. Density and coponent analysis data fro the group eter saple point ay be used for test eter calculations. Figure 8.1. Typical shallow gas wells or CBM well configuration Test Taps Gas Well Test Taps Gas Well Gas Well Test Taps Test Taps Test Taps Gas Well Gas Well Separator Group Gas Meter A Produced Water Copressor To Gathering Syste or Sales Group Gas & SP (alternate location) = easureent point For shallow gas wells and CBM wells that have been fractured or stiulated using a gaseous ediu (e.g., N 2 or CO 2 ), gas sapling and analysis frequency ust be in accordance with the following: 1. An initial saple and analysis ust be obtained within the first onth the well is put on production to establish the initial N 2 or CO 2 concentration and other coponent coposition. 2. Where there is adequate analog saple and analysis data that is representative of how concentrations of N 2 or CO 2 will decline fro onth to onth in the produced gas, the onthly analog saple and analysis data ay be used to calculate well volues in the second to fifth onths. a. The analog data set ust contain onthly saple and analysis data showing how N 2 or CO 2 concentrations decline onth over onth for up to 12 onths and fro at least six wells within an eight k radius of the subject well. The analog data set ust be a volue-weighted average coposition. 3. After being on production for six onths, a second saple and analysis ust be obtained to confir that the well gas N 2 or CO 2 concentration is declining as predicted by the analog data set. The saple and analysis ust be used to reestablish the well gas coposition with the analog data set. The onthly analog August 1, 2017 Page 8-13

233 saple and analysis data ay be used to calculate well volues fro the seventh to twelfth onths. 4. After being on production for one year, the saple and analysis fro the group separator ay be used to deterine the well gas volues. 5. If analog saple and analysis data does not exist as described above, then the well ust be sapled bionthly until the well gas coposition has stabilized; the saple and analysis obtained at the group eter ay then be used to deterine well gas volues. Coposition stabilization eans that the ole fraction of N 2 or CO 2 in the total saple analysis is 0.05 or 0.02, respectively. For CBM wells that have been fractured or stiulated using a gaseous ediu, gas saples ust be taken onthly until the coposition stabilizes and then biennially or as otherwise required by the exeptions in this directive. If these stratigraphic units or zones are coingled with gas fro other outside stratigraphic units or zones, sapling ust be done on a per pool or stratigraphic unit or zone basis for CBM or per coingled pool(s) basis fro a representative well within the pool(s) biennially. For exeptions on sapling for these pools or stratigraphic units or zones, see Section Gas Multiwell Proration Outside SW Saskatchewan and SE Alberta Batteries (Petrinex facility subtypes: 364 in SK and 364 and 367 in AB) In the configuration in Figure 8.2, gas density and coposition ust be updated annually at group gas eter A and at each well during a test. If condensate at the group easureent point is recobined and delivered to a gas plant, the condensate GEF ust be updated annually. Figure 8.2. Typical proration gas configuration Test Taps Gas Well Test Taps Gas Well Gas Well Test Taps Test Taps Test Taps Gas Well Gas Well Separator Copressor Group Gas Meter A Produced Condensate Group Gas (alternate location) To Gathering Syste or Sales = easureent point Produced Water Exeptions for Sapling Frequency 1. A licensee is not required to update the analyses where three consecutive gas relative density (RD) deterinations conducted at the specified deterination August 1, 2017 Page 8-14

234 frequency or, alternatively, no ore frequently than once per year are all within ±1.0% of the average of the three RD s as shown in Exaple 8.1. In this situation, there is no need for an application to be subitted to the Regulator. Records and data in support of this exeption ust be retained by the licensee and ade available to the Regulator upon request. Notwithstanding this exeption, the licensee ust update the gas analyses when changes are ade to producing conditions that could affect the gas density by ore than ±1.0% of the average of the three qualifying RD s. 2. The gas and condensate analyses deterined at the group easureent points ay be used for the test eters, provided that all wells are fro the sae pool. 3. For wells producing fro ultiple pools into a group easureent point, average individual gas and (where applicable) condensate analyses ay be used in volue calculations for all the wells in each individual pool (or coingled pool) producing to a test eter provided the following qualifying criteria are et. a. All wells flowing to the group easureent point have coon ownership. If there is not coon ownership, written notification has been given to all working interest participants, with no resulting objection received. b. All wells flowing to the group easureent point have coon Crown or Freehold royalty. If there is no coon Crown or Freehold royalty and only Freehold royalties are involved, written notification has been given to all Freehold royalty owners, with no resulting objection received. If there is a ix of Freehold and Crown royalty involved, the licensee ust apply to the Regulator for approval if any Freehold royalty owners objects. i. In each subsequent year, gas and condensate analyses ust be obtained fro at least four wells in each pool (or coingled pool) or at least 25 per cent of the wells in each pool (or coingled pool), whichever is greater. This new data will be used to recalculate average gas and condensate relative densities and provided that the newly sapled well gas and condensate relative densities variance reains within the 2 per cent liit of the average, the exeption will reain in effect (see exaple 8.2). If the well gas and condensate relative densities variance exceeds the 2 per cent liit, this exeption is revoked. The revocation of the exeption reains in place until sapling and analysis of all wells in the pool re-establishes the required RD variance. ii. If the pool (or coingled pool) has four or fewer wells flowing to the group easureent point, then, in each subsequent year, gas and condensate analyses ust be obtained fro one well fro each pool (or coingled pool). If the newly sapled well gas and condensate relative densities variance reains within 2 per cent of the previous years relative densities, the exeption reains in effect. If the well gas and condensate relative densities variance exceeds the 2 per cent liit, this exeption is revoked. The revocation of the exeption reains in place until sapling and analysis of all wells in the pool re-establishes the required RD variance. August 1, 2017 Page 8-15

235 c. New wells that have been fractured or stiulated with a gaseous ediu are not eligible for this exeption until their gas and condensate RDs are within the 2 per cent variance of the calculated pool average gas and condensate RD. Exaple 8.1. Meter A RD Differences Saple date RD RD Difference fro average June 03, % June 09, % June 06, % Average In this exaple, eter A would be exept fro the requireent for future updates as the three consecutive RD s are within ±1.0% of the average of the three RD s Multiwell Effluent Measureent Battery (Petrinex facility subtype: 362) In the configuration in Figure 8.4, gas analyses, condensate coposition, and GEF ust be updated at the tie of testing each effluent well and annually at the group gas and condensate eters as shown in Figure 8.3. The gas analysis to be used for voluetric calculation at the effluent eter is as follows: Option 1: Option 2: Use the separated gas analysis fro the ECF-WGR test; or Use the recobination of the gas analysis and the condensate analysis fro the ECF-WGR test. Note: All wells within the effluent battery ust use the sae analysis option Exeptions for Analyses at Group Gas and Condensate Metering Points 1. A licensee is not required to update analyses at the group gas and condensate etering points if: a. Three consecutive gas RD deterinations conducted at the specified deterination frequency or no ore frequently than once per year are all within ±1.0% of the average of the three RD s as shown in Exaple 8.1; and b. The daily average liquid condensate volue is less than or equal to /d for all reporting onths for the previous three years and/or the GEV of the condensate is less than or equal to 2.0% of the recobined total onthly gas volue. In these situations, there is no need for an application to be subitted to the Regulator. Records and data in support of these exeptions ust be retained by the licensee and ade available to the Regulator upon request. Notwithstanding these exeptions, the licensee ust update the gas analyses when changes are ade to producing conditions that could affect the gas RD by ore than ±1.0% of the average of the three qualifying RD s, and the licensee ust update the condensate analyses if the liquid condensate volue or GEV percentage increases beyond the qualifying liits. August 1, 2017 Page 8-16

236 Separator 2. A licensee is not required to update the well gas and condensate analyses if three consecutive calculated recobined relative density (RD) deterinations conducted at the specified deterination frequency or, alternatively, no ore frequently than once per year are all within ±1.0% of the average of the three RDs (see Exaple 8.1). Specifically, the RDs would be those of the gas plus gas equivalent of the recobined liquid condensate. After the well has fallen below the critical lift velocity as deterined using the Turner Correlation calculation described in Section a new gas and condensate analysis ust be obtained. In this situation, there is no need for an application to be subitted to the Regulator. Records and data in support of this exeption ust be retained by the licensee and ade available to the Regulator upon request. Notwithstanding this exeption, the licensee ust update the gas analyses when changes are ade to producing conditions that could affect the gas density by ore than ±1.0% of the average of the three qualifying recobined RDs. Figure 8.3. Typical ultiwell effluent easureent battery Test Taps Effluent Gas Well Effluent Test Taps Group Measureent Point Gas Meter A Condensate Metered and Recobined To Gas Gathering Syste Gas Well Effluent Test Taps Produced Water Metered and Recobined or Disposal Gas Well = easureent point August 1, 2017 Page 8-17

237 Test Separator Figure 8.4. Typical effluent well testing configuration Testing Unit Gas Metered & Recobined Condensate Fuel Produced Water Gas Well X X Test Taps Line Heater (Optional) X To Gas Battery (Group easureent) = easureent point Gas Single Well Battery (Petrinex facility subtype: 351) or Gas Multiwell Group Battery (Petrinex facility subtype: 361) and Shallow Gas Well or CBM Well without Condensate or Oil For the configuration in Figure 8.5, the gas analysis ust be updated within the first year and then biennially at each well eter shown as gas eter A. SK AB BC Shallow gas well are those that produce fro the shallow gas stratigraphic units and include coals and shales fro the botto of the Glacial Drift and the botto of the Upper Cretaceous. The production fro two or ore of these stratigraphic units without segregation in the wellbore requires prior approval fro the Regulator. Shallow gas wells are those that produce fro shallow gas zones and include coals and shales fro the top of the Edonton Group to the base of the Colorado Group. The production fro two or ore of these zones without segregation in the wellbore requires either prior approval fro the AER for coingled production, which has been granted in a portion of SE Alberta in Order No. MU 7490, or adherence to the self-declared coingled production requireents described in Directive 065: Resources Applications for Oil and Gas Reservoirs. See Measureent Guideline for Upstrea Oil and Gas Operations For shallow gas wells and CBM wells that have been fractured or stiulated using a gaseous ediu (e.g., N2 or CO2), frequency of gas sapling and analysis ust be in accordance with the following: August 1, 2017 Page 8-18

238 1. An initial saple and analysis ust be obtained in the first onth the well is put on production to establish the initial N 2 or CO 2 concentration and other coponent coposition. 2. Where there is adequate analog saple and analysis data that is representative of how concentrations of N 2 or CO 2 will decline fro onth to onth in the produced gas, the onthly analog saple and analysis data ay be used to calculate well volues fro the second to fifth onths. a. The analog data set ust contain onthly saple and analysis data showing how N 2 or CO 2 concentrations decline onth over onth for up to 12 onths and fro at least six wells within an eight k radius of the subject well. The analog data set ust be a volue-weighted average coposition. 3. After being on production for six onths, a second saple and analysis ust be obtained to confir that the well gas N 2 or CO 2 concentration is declining as predicted by the analog data set. The saple and analysis ust be used to reestablish the well gas coposition with the analog data set. In the seventh onth and for the duration of the well life cycle, the analog saple and analysis data ay be used to deterine the well gas volues. 4. If analog saple and analysis data does not exist as described above, then the well ust be sapled bionthly until the well gas coposition has stabilized; after that, no further sapling of the well is required. Coposition stabilization eans that the ole fraction of N 2 or CO 2 in the total saple analysis is 0.05 or 0.02, respectively. For shallow gas wells and coalbed ethane wells that have not been fractured or stiulated using a gaseous ediu, only a single gas saple and analysis is required through the entire producing life cycle of the well. The operator ay deterine the tiing of the gas sapling, but it ust be obtained within the first year of the well being placed on production. A representative saple analysis fro an analog well or a calculated average gas coposition based on the saple analyses of several analog wells ay be used for gas volue deterination until the actual well gas saple and analysis are obtained. Figure 8.5. Typical CBM gas battery configuration Gas Meter A To Gas Gathering Syste / Gas Plant / Sales Gas Well Separator Produced Water = easureent point August 1, 2017 Page 8-19

239 Exeptions for Analysis Frequency 1. A licensee is not required to update the analyses if three consecutive gas analyses conducted at the specified deterination frequency or, alternatively, no ore frequently than once per year are all within ±1.0% of the average RD of the three analyses as shown in Exaple 8.1. In this situation, there is no need for an application to be subitted to the Regulator. Records and data in support of this exeption ust be retained by the licensee and ade available to the Regulator upon request. Notwithstanding this exeption, the licensee ust update the gas analyses when changes are ade to producing conditions that could affect the gas analysis by ore than ±1.0% of the average RD of the three qualifying analysis. 2. A representative analysis for all wells producing to a coon gathering syste or facility fro a coon pool can be used if the RD of all coon-pool wells are within 2.0% of the average analysis of those wells. Gas analyses ust initially be obtained for all the coon-pool wells to arrive at the average analysis. Subsequent analyses can be ade on 25% or at least four wells fro the pool (whichever is greater) at the frequency stated in this Directive, provided that the RD variance reains within the 2.0% liit of these wells as shown in Exaple 8.2. Should the variance exceed this liit, this exeption is revoked and biennial analyses ust be deterined for each easureent point. Exaple 8.2. Pool RD Differences Consider an 8-well pool producing gas under this configuration: Well Id RD RD Difference fro average % % % % % % % % Average In this scenario, it is acceptable to use the analyses fro the well with the RD closest to the average, Well Id 11-30, for all well eters, as all RDs are within ±2.0% of the average of all well RDs. The analysis ust then be updated biennially for at least four wells fro the pool. This exeption will reain in place, provided that all four well RD s continue to be within ±2.0% of the average of all the updated RD s. When this criterion is not et, analyses ust revert to biennial updates for all wells. A peranent exeption on a pool basis would be available where the updated average RD eets the criterion of Exeption 1. Where practical, the Regulator expects the sae wells to be used to arrive at the average RD used in pursuit of this exeption. August 1, 2017 Page 8-20

240 S eparator Gas Single Well Battery (Petrinex facility subtype: 351) or Gas Multiwell Group Battery (Petrinex facility subtype: 361) with Condensate or Oil For gas wells producing condensate in Figure 8.6, the frequency of sapling and analysis for gas and condensate depends upon the gas flow rate through gas eter A plus the GEV of condensate. If the flow rate exceeds /d, the frequency is annual. If the flow rate is less than or equal to /d, the frequency is biennial. The flow rate value is a onthly average. Figure 8.6. Condensate production Gas Well Separator Gas Meter A Metered & Recobined Condensate Produced Water To Gas Gathering Syste / Gas Plant / Sales = easureent point For gas wells producing oil in Figure 8.7, the sapling and analysis of oil/eulsion streas to deterine relative oil and water content ust confor to the requireents in Sections and The gas sapling frequency is the sae as for a gas well producing condensate, except that the total gas flow rate does not include GEV of oil/eulsion. Figure 8.7. Oil production Gas Well Gas Meter A Metered & Recobined Oil/Eulsion To Gas Gathering Syste / Gas Plant / Sales Produced Water = easureent point August 1, 2017 Page 8-21

241 Exeptions for Gas Batteries with Condensate 1. For gas wells producing condensate, a licensee is not required to update the gas and condensate (if applicable) analyses at the etering points if: a. Three consecutive gas RD deterinations conducted at the specified deterination frequency or no ore frequently than once per year are all within ±1.0% of the average of the three RDs as shown in Exaple 8.1; and b. Daily average liquid condensate volue is less than or equal to /d for all reporting onths for the previous three years and/or the GEV of the condensate is less than or equal to 2.0% of the recobined total onthly gas volue. In these situations, there is no need for an application to be subitted to the Regulator. Records and data in support of these exeptions ust be retained by the licensee and ade available to the Regulator upon request. Notwithstanding these exeptions, the licensee ust update the gas analyses when changes are ade to producing conditions that could affect the gas RD by ore than ±1.0% of the average of the three qualifying RDs, and the licensee ust update the condensate analyses if the liquid condensate volue or GEV percentage increases beyond the qualifying liits. 2. A representative analysis for all wells producing to a coon gathering syste or facility fro a coon pool ay be used if the RD s of all coon-pool wells are within 2% of the average RD of those wells. Gas analyses ust initially be obtained for all the coon-pool wells to arrive at the average RD. Subsequent analyses ay be ade on 25% or at least four wells fro the pool, whichever is greater, at the frequency stated in this Directive, provided that the RD variance reains within the 2% liit of these wells as shown in Exaple 8.2. Should the variance exceed this liit, this exeption is revoked and biennial analyses ust be deterined for each easureent point. Underground Gas Storage (Petrinex facility subtype: 505) For the gas storage configuration shown in Figure 8.8, there are two phases to consider: 1. Storage Injection Phase If the injection gas only coes fro a single source, an annual coon strea saple analysis ay be used for all injection eters, and no individual well injection analyses are required. If there are ultiple injection gas sources, saple analysis is required at each source strea and at each well injection easureent point. In this scenario, the iniu analysis frequency for injection eters are seiannual, however, a continuous proportional sapler or a gas chroatograph should be installed to provide ore accurate copositions for gas volue calculations. 2. Storage Recovery Phase During each recovery phase, analyses ust be updated at each gas well s production eters within the first onth and seiannually thereafter if necessary. August 1, 2017 Page 8-22

242 Figure 8.8. Underground Gas Storage Prod. Gas Produced Gas Gas Well A Injection Gas Condensate Water Metered & Recobined Condensate Produced Water Gas Plant Gas Sales Gas Well B Injection Gas Measured & Condensate Recobined Condensate Produced Water Water Injection Gas Produced Gas Injection Gas fro Plant Gas Well C = easureent point Condensate Water Measured & Recobined Condensate Produced Water Injection Gas fro other Sources Gas Cycling Schee (Petrinex facility subtype: 502) In the gas cycling schee configuration shown in Figure 8.9, analyses ust be updated at each well eter, A, B, and C, and the injection well eter in accordance with the specific schee approval. If there are no frequencies specified in the approval, the well eters ust have analyses updated sei-annually and the gas injection eter(s) ust have analyses updated in accordance with the source requireents such as seiannually for gas plant gas. August 1, 2017 Page 8-23

243 Figure 8.9. Gas Cycling Schee Gas Gas Well A Condensate Water Metered & Recobined Condensate Produced Water Gas Well B Gas Condensate Water Gas Well C = easureent point Metered & Recobined Condensate Produced Water Gas Condensate Water Metered & Recobined Condensate Produced Water Gas Plant Gas Injection Well Gas Sales Gas Sales/Delivery In the gas sales/delivery configuration shown in Figure 8.10, gas sales/delivery in this context will typically be clean, processed sales gas that is delivered out of a gas plant or a facility into a transission pipeline. In soe scenarios, this type of gas ay be delivered to other plants for further processing or fuel or to injection facilities. Figure Gas Sales/Delivery Gas Inlet Battery, Gas Gathering Syste, Gas Plant Sales Gas Transission Pipelines, Other Gas Plants, Injection Systes, or Fuel for Other Facilities = easureent point If a eter is used to deterine the sales gas/delivery point volue fro a battery, gas gathering syste, or gas plant, the iniu gas analysis frequency is annual. However, a continuous proportional sapler or a gas chroatograph should be installed to provide ore accurate analyses for the gas volue calculation. August 1, 2017 Page 8-24

244 8.4.9 Gas Plants (Petrinex facility subtypes: 401 to 407) and Gas Gathering Systes (Petrinex facility subtypes: 621 in SK and 621 and 622 in AB) In the configuration shown in Figure 8.11, only one saple point is required for coon gas streas, such as sales gas, which ay also be used for fuel, injection, and sales gas flare. Inlet gas saple ay be used for inlet gas flare. The frequency for sapling and analysis is as follows unless a different frequency has been specified in site-specific approvals, such as gas cycling or iscible/iiscible flood schees, or for heavy oil gas production. For gas sales easureent point sapling frequency, see Section Gas Plant The iniu frequency for updating analyses at all accounting eters within a gas plant is seiannual. Inlet condensate is reported as a GEV, so analyses are required. High-vapour pressure liquids, such as C 5 -SP and other NGLs, are to be reported as liquid volues on Petrinex, which will then perfor the GEV calculation autoatically using standard factors for plant balancing. Gas Gathering Syste The iniu frequency for updating analyses at all accounting eters within a gas gathering syste is annual for all flow rates that exceed /d. If the flow rate is less than or equal to /d, the frequency is biennial. The flow rate is to be based on a onthly average. Condensate volues recobined with gas for delivery to other facilities ust be reported as GEV, so analyses are required for updating GEFs. Where condensate is delivered out of a gas gathering syste without further processing, it is reported as a liquid volue, but analyses for GEV calculation purposes are required for reporting on Petrinex. August 1, 2017 Page 8-25

245 Figure Gas Plants and Gas Gathering Systes saple point Gas Plant Raw Gas Flare Acid Gas Sales Gas Flare Gas Gathering Syste(s) Inlet Separator Inlet Gas Condensate Gas Plant Plant Fuel Sales Gas Water To Disposal Gas Injection C5+, NGL, etc. Gas Gathering Syste Flare Copressor Sales Gas or Gas Plant Gas fro Batteries Dehydration Fuel Water Produced Water Gas Injection = easureent point Crude Oil Single Well Battery (Petrinex facility subtypes: 311) and Crude Oil Multiwell Group Battery (Petrinex subtype: 321) In the configuration shown in Figure 8.12, if all associated gas, net of lease fuel, is flared, an initial representative gas analysis is required. If gas is conserved, gas analysis updates are required. If the average flow rate exceeds /d, the frequency is annual. If the average flow rate is less than or equal to /d, the frequency is biennial. Figure Single-well or ultiwell group oil battery Gas to Flare or Gathering syste Vented Tank Vapours (Estiate) Puping Oil Well = easureent point Separator 2-Phase Separator Eulsion Tank Eulsion Trucked to Processing Facility August 1, 2017 Page 8-26

246 Crude Oil Multiwell Proration Battery (Petrinex facility subtype: 322) In the configuration shown in Figure 8.13, the gas analyses ust be updated at the test eters A and B biennially for axiu test gas rates up to /d or annually if the axiu test gas rates exceed /d. Figure Priary production/water flood Mannville E Pool Test Meter A Oil Well Oil Well Test Group Meter C Flare Gas Gathering Systes Oil Well Test Test Meter B Group Treater Fuel Oil Vented Gas Oil Sales Oil Well Oil Well Elkton A Pool Water Disposal or injection = easureent point It is acceptable to use the gas analysis fro a single representative well for all wells within a single pool. If wells fro ore than one pool are directed through the sae test separator, an analysis ust be obtained for each pool. The gas analysis at eter C ust be updated annually for gas flow rates exceeding /d or biennially if the total rate through the eter is less than or equal to /d based on the onthly average flow rate. Exaple 8.3. Miniu Gas Analysis Frequency Consider a five-well proration battery with two wells producing fro the Mannville E Pool and three wells producing fro the Elkton A Pool. Battery gas production is gathered and conserved. Pool Well Satellite eter Test gas rate /d Mannville E Meter A 4.2 Mannville E Meter A 6.8 Elkton A Meter B 18.0 Elkton A 9-27 Meter B 12.0 Elkton A Meter B 6.5 Total rate for Meter C = 47.5 August 1, 2017 Page 8-27

247 A gas analysis ust be established for the Mannville E Pool, as a iniu using either the or well, and updated biennially at eter A, as the axiu rate through eter A for the Mannville E pool wells is less than /d. A gas analysis ust be deterined for the Elkton A Pool at eter B, as a iniu using any one of the three wells, and updated annually, as the axiu rate through eter B for the Elkton A pool wells is greater than /d. The gas analysis at eter C ust be updated annually, as the flow rate through the eter exceeds /d Exeption for Gas Analysis Frequency If the total battery gas, net of lease fuel, is flared, an initial pool gas analysis ust be deterined at eters A and B. Updates of the gas analysis at eter C, at the annual or biennial frequency as deterined by the gas flow rate through the eter, is only required if the gas directed through eter C originates fro ultiple pools. If the gas directed through eter C originates fro a single pool, no updates are required subsequent to the initial analysis. However, this exeption is revoked as soon as the gas is conserved, and gas analyses ust be perfored according to the frequencies specified in this section Miscible/Iiscible Flood In the configuration shown in Figure 8.14, analyses ust be updated at each test and group eter and the injection well eter in accordance with the specific schee approval. If there are no frequencies specified in the approval, the test and group eters ust have analyses updated quarterly and the injection eter(s) ust have analyses updated onthly. Figure Typical Miscible/Iiscible Flood Oil Well Oil Well Test Test Meter Group Meter Fuel Flare Gas Gathering Systes Hydrocarbon Gases, CO 2, Solvent, or other cheicals Oil Well Test Test Meter Group Treater Injection Well Vented Gas Oil Oil Sales Oil Well Water Disposal = easureent point August 1, 2017 Page 8-28

248 Crude Oil Batteries Producing Heavy Oil (Petrinex facility subtypes: 313, 325, 326, and 327 in SK and 311, 321, 322, 343, and 344 in AB) SK AB BC Heavy oil production at a single-well as shown in Figure 8.15 or ultiwell group battery as shown in Figure 8.16 typically involves directing all production to a tank without using a separator or gas eter. In such scenarios, gas production ay be estiated using a GOR. If a eter is used to easure gas for the purposes of conducting GOR tests or continuous gas production easureent, an initial gas analysis is required. An analysis fro a coparable well producing fro the sae pool ay be used if a eter will be used to easure gas to deterine GOR. Note: If no initial gas analysis was copleted than at least one gas analysis ust be copleted before April 1, An analysis fro a coparable well producing fro the sae pool ay be used if a eter will be used to easure gas to deterine GOR. In Saskatchewan, all sapling and analysis reports ust be uploaded within 30 days of the analysis being copleted as per Minister s specifications listed in Directive PNG013: Well Data Subission Requireents. If an analysis has already been copleted it ust be uploaded before April 1, 2020 as per the Minister s specifications listed in Directive PNG013: Well Data Subission Requireents. Heavy oil production at a single-well as shown in Figure 8.15 or ultiwell group battery as shown in Figure 8.16 typically involves directing all production to a tank without using a separator or gas eter. In such scenarios, gas production ay be estiated using a GOR. If a eter is used to easure gas for the purposes of conducting GOR tests or continuous gas production easureent, an initial gas analysis is required. An analysis fro a coparable well producing fro the sae pool ay be used if a eter will be used to easure gas to deterine GOR. See Measureent Guideline for Upstrea Oil and Gas Operations August 1, 2017 Page 8-29

249 Figure Single well battery producing heavy oil Casing Gas - Fuel and/or Vent Vented Tank Vapours (Estiated) Puping Oil Well Eulsion Tank Eulsion Trucked to Processing Facility = easureent point Figure Multiwell group battery producing heavy oil Heavy Oil Well Heavy Oil Well Heavy Oil Well Casing Gas Casing Gas Casing Gas Casing Gas (estiate) = easureent point Oil Tank Vent (estiate) Oil Oil Gas Sales or Gathering Syste Eulsion Trucked to Processing Facility Eulsion Trucked to Processing Facility Eulsion Trucked to Processing Facility If a GOR is deterined by ethods other than using gas easureent, an initial gas analysis is not required. If a eter is used to easure gas on a continuous basis, biennial analysis updates are required. Heavy oil production at ultiwell proration batteries as shown in Figure 8.17 ay involve directing all production to tanks without using separators or gas eters, but if cobined gas volues eet the econoic requireents in: SK AB BC Directive S-10 - Saskatchewan Upstrea Petroleu Industry Associated Gas Conservation Directive Upstrea Petroleu Industry Flaring, Incinerating, and Venting See Measureent Guideline for Upstrea Oil and Gas Operations then the gas ust be gathered and conserved. August 1, 2017 Page 8-30

250 Figure Multiwell proration battery producing heavy oil Heavy Oil Well Heavy Oil Well Heavy Oil Well Casing Gas Casing Gas Casing Gas Oil Test Tank Tank Vent (estiate) Group Meter Required if over /day Oil Storage Fuel Copressor Eulsion Trucked to Processing Facility Gas Sales or Gathering Syste Eulsion Trucked to Processing Facility = easureent point If a eter is used to easure gas for the purposes of conducting GOR tests, an initial gas analysis is required. If a GOR is deterined by ethods other than using gas easureent, an initial gas analysis is not required. If a eter is used to easure gas on a continuous basis, biennial analysis updates are required. 8.5 Oil Sapling and Analysis Requireents Sapling and analysis ust be in accordance with Sections 6, 8, 10, 14 or other equivalent ethod approved by an appropriate industry standards association Oil Analysis Requireents for New Wells SK AB BC All new oil wells in Saskatchewan ust subit an oil analysis within 30 days of the on production date. In Saskatchewan, all sapling and analysis reports ust be uploaded within 30 days of the analysis being copleted as per Minister s specifications listed in Directive PNG013: Well Data Subission Requireents. If an analysis has already been copleted it ust be uploaded before April 1, 2020 as per the Minister s specifications listed in Directive PNG013: Well Data Subission Requireents. Upon Regulator request Upon Regulator request Exeption for Oil Analysis Requireents SK AB New oil wells are not required to subit an oil analysis if the Ministry has an oil analysis (subitted on IRIS) not older than 10 years for the target stratigraphic unit fro another well where the licensed boss wellbore is located within 1.6 kiloeters of the new well s licensed boss wellbore. See Alberta Energy Regulator s Directives August 1, 2017 Page 8-31

251 BC See BC Oil and Gas Coission s Directives August 1, 2017 Page 8-32

252 9 Cross-Border Measureent This section presents the easureent requireents for all upstrea and idstrea oil and gas products crossing a provincial or territorial border. 9.1 General Requireents For those facilities receiving and/or delivering products and waste to another jurisdiction either by trucking, rail or pipeline, including pipelines under the National Energy Board (NEB) jurisdiction, each jurisdictional products and waste streas ust be isolated and easured prior to coingling. The delivery point easureent standards for each jurisdictional authority ust be followed, unless site-specific approval fro the Regulator and the other jurisdictional authority(ies) has been obtained. All streas ust be isolated and etered or estiated according to requireents in this Directive. This can include production, gathering systes, and all fuel, flare, and vent volues. If the easureent or other equipent requireent for delivery point easureent of hydrocarbon and related fluids fro any jurisdiction is different fro the Regulator requireents, the higher requireents, such as frequency and accuracy, between the jurisdictions ust be followed. Non-royalty exept fuel gas usage at cross-border oil and gas processing facility ust be separately deterined and easured if it is over /d for each jurisdiction. If the usage is for production fro both jurisdictions, no separate fuel gas etering is required if site-specific approval is obtained fro both jurisdictions involved. For exaple, a copressor used only for gas coing fro another jurisdiction into Alberta or Saskatchewan ust be etered separately at the cross-border facility and the fuel gas use for other equipent processing coingled production or the entire facility ust be easured with another eter. 9.2 Cross-Border Sapling Requireents Except where otherwise noted, the gas and liquid sapling equipent and ethodology ust follow the requireents set out in Section 8: Gas and Liquid Sapling and Analysis. Spot or grab saples are acceptable for obtaining gas and liquid analyses, provided the uncertainty requireents in Section 1 of this Directive are fulfilled. When the uncertainty requireents cannot be et, consider: 1. More frequent spot sapling for calculated analysis; 2. The use of proportional saplers; or 3. The use of gas chroatographs or other continuous analyzers. 9.3 Cross-Border Measureent Points Figures 9.1 through 9.9 are soe of the scenarios to deterine if a specific circustance is considered cross border. Each scenario applies as well if the flow is in the opposite direction. There ust be only one cross-border easureent point for each pipeline crossing the provincial boundary unless site-specific approval is obtained fro both jurisdictions involved. The cross-border easureent point can be on either side of the jurisdictional border before coingling with any fluids fro another jurisdiction. Measureent-by-difference August 1, 2017 Page 9-1

253 Provincial Boundary rules apply in all situations where there is easured production going into a proration battery. Figure 9.1. Effluent gas easured wells to an out-of-province location (non-coon pool) Outside Jurisdiction Sales Saskatchewan or Alberta Facility, battery, or gas plant G G Wet etered well site Cross-border easureent Group easureent Pipeline For cross-border coon pools producing fro one or ore jurisdictions, if the surface facility is located in one jurisdiction and the well production as defined by the bottohole location is in another jurisdiction, delivery point easureent of the production is required (see Figure 9.2). The production fro this well ust be reported as delivered to the other jurisdiction where the surface facility is located. August 1, 2017 Page 9-2

254 P rovincial Bounda r y Provincial Boundary Figure 9.2. Gas gathering syste of effluent gas easured well with easured well downhole location in another jurisdiction Outside Jurisdiction Sales Saskatchewan or Alberta Facility, battery, or gas plant Downhole location in another jurisdiction G G Wet etered well site 3 - phase separation well site Cross-border easureent Group easureent Pipeline Figure 9.3. Multiple jurisdictional crossing Outside Jurisdiction Saskatchewan or Alberta Fuel Sales Copressor Facility, battery, or gas plant G Wet etered well site 3 - phase separation well site Cross-border easureent Group easureent Pipeline August 1, 2017 Page 9-3

255 P rovincial Bounda r y Provincial Boundar y Figure 9.4. Measured gas source fro an out-of-province location Outside Jurisdiction, Saskatchewan or Alberta Sales G Wet etered well site 3 - phase separation well site Cross-border easureent Group easureent Pipeline Facility, battery, or gas plant G Figure 9.5. Sales gas source fro an out-of-province location Outside Jurisdiction Saskatchewan or Alberta Facility or battery Facility or battery Sales Sales Facility, battery, or gas plant Sales Wet etered well site Cross-border easureent Pipeline August 1, 2017 Page 9-4

256 P rovincial Bounda r y P rovincial Bounda r y Figure 9.6. Measured sources fro an out-of-province location Outside Jurisdiction Saskatchewan or Alberta G Facility, battery, or gas plant Sales G Wet etered well site 3 - phase separation well site Cross-border easureent Group easureent Pipeline For Figure 9.6, the three-phase separation wells can be designed to delivery point easureent requireents without another cross-border easureent point. Measureent-by-difference rules applies in Figures 9.1, 9.2, 9.4, 9.5, and 9.6 unless the effluent etered wells have a group easureent point prior to coingling with the easured gas source(s). Figure 9.7. Sales oil or gas source fro an out-of-province location Outside Jurisdiction Saskatchewan or Alberta Facility, battery, or gas plant Sales Sales Sales Battery, or gas plant Cross-border easureent Pipeline August 1, 2017 Page 9-5

257 P rovincial Bounda r y P rovincial Boundary Figure 9.8. Sales oil or gas source fro an out-of-province location Outside Jurisdiction Saskatchewan or Alberta Facility, battery, or gas plant Sales Sales Cross-border easureent Pipeline Figure 9.9. Sales oil or gas source fro an out-of-province location Outside Jurisdiction Saskatchewan or Alberta Facility, battery, or gas plant Sales Sales Facility, battery, or gas plant Cross-border easureent Pipeline August 1, 2017 Page 9-6

258 10 Trucked Liquid Measureent This section presents the requireents for trucked liquid easureent fro oil and gas production facilities to another facility or sales. Applicable liquids include crude oil, condensate, water and NGLs General Requireents Crude oil or condensate ay be found in association with water in an eulsion. In such scenarios, the total liquid volue of the trucked load ust be easured, and the relative volues of oil and water in the eulsion ust be deterined by obtaining and analyzing a representative saple of the eulsion or by using a product analyzer such as a water-cut onitor or a Coriolis eter s density easureent where applicable. A licensee ust accurately easure produced liquids/eulsion volues by using tank gauging, a weigh scale, or a eter, unless otherwise stated in this Directive. The delivery point easureent requireents ust be et for all trucked liquids unless the exeption conditions in this section are et or site-specific approval fro the Regulator has been obtained as per Section 5. The Regulator will consider a truck liquid easureent syste to be in copliance if the base requireents outlined in Sections , and are et. The Regulator ay stipulate additional or alternative requireents for any specific situation, based on a site-specific assessent. All delivery point eters ust be proved in accordance with Section 2. LACT eters ay use the proving procedure in API-MPMS, Chapter 4: Proving Systes, instead of the Section 2 procedure Reporting Requireents Monthly oil, condensate, and water volues for well and battery, for exaple, production, receipts, and dispositions, ust be reported as the nuber of cubic etres rounded to the nearest tenth of a cubic etre (0.1 3 ). Measured volues ust be corrected to 15 C and at the greater of 0 kpag or equilibriu vapour pressure at 15 C. See Section for production data verification and audit trail requireents. For delivery point easureent, hydrocarbon liquid volue ust be deterined to two decial places and rounded to one decial place for onthly reporting. If there is ore than one volue deterination within the onth at a reporting point, the volues deterined to two decial places ust be totaled prior to the total being rounded to one decial place for reporting purposes Teperature Correction Requireents All delivery point easureent of hydrocarbons and eulsions requires teperature correction to 15 o C, see Section See Section 14.4 for teperature deterination requireents. Coposite eter factors are not acceptable for delivery point easureents. The correction for the effect of teperature on liquids (CTL) factor ust be deterined in accordance with the API MPMS, Chapter LPG ust follow the applicable GPA Technical EUB Directive 017: Measureent Requireents for Upstrea Oil and Gas Operations (July 2007) 10-1

259 Publication TP-27 or an equivalent applicable procedure accepted by an appropriate industry technical standard association Pressure Correction Requireents The correction for the effect of pressure on liquids (CPL) factor ust be deterined in accordance with API MPMS, Chapter 11, and is required only for LACT applications General Trucked Liquid Measureent, Accounting, and Reporting Requireents for Various Facility Types Oil Batteries that Produce Non-Heavy Oil For trucked oil/eulsion production into an oil battery, delivery point easureent is required for the total liquid volue. If there is a ixture of trucked-in production and prorated production within the sae battery, the exeption criteria in Section ust be et or Regulator site-specific approval ust be obtained. For condensate trucked into an oil battery, delivery point easureent is required for the total liquid volue. The requireents in Section 6.6 ust be et. For any oil battery, the trucked-out liquid is easured at the delivery point located at the receiving facility, and the oil volue deterined at the receiving facility ust be used as the delivering battery s oil disposition. Proper easureent ust be set up at the receipt point only, except for load oil delivery fro a facility to well(s). In this scenario, delivery point easureent is required at the loading facility. If there are eergencies at the receipt point, the origin easureent ay be used, but only as a teporary solution. If clean oil fro a battery is delivered into an oil pipeline via a LACT unit and that sae BT also receives clean trucked oil, condensate, or diluent fro other sources with delivery point easureent, a terinal Petrinex code ust be obtained so that the clean trucked-in fluid is received at the terinal instead of at the battery. The battery oil ust also be easured with delivery point easureent before coingling with other fluids at the terinal. The terinal will then deliver the fluid to the pipeline via the LACT unit. If there is no delivery point easureent for the battery oil to the terinal, easureent by difference rules apply, see Sections 5.5 and Figure August 1, 2017 Page 10-2

260 Figure Oil battery and terinal scheatic Production Wells G R O U P / T E S T FWKO TREATER GGS, Gas plant, Sales Injection Facility Subtype 503 H E A D E R Vented Gas Clean oil, diluent receipt Oil Battery Subtype 322 Terinal Storage Produced Water Terinal Subtype 671 Terinal Storage Vented Gas LACT Injection Well Pipeline = easureent point Custo Treating, Oil Battery, and Terinal Delineation A terinal is required when there is ore than one source of clean oil going through a LACT eter into an oil pipeline. Any oil, water, and gas crossing a facility boundary ust be easured. If there is blending of hydrocarbon liquids of densities that differ by > 40 kg/ 3, such as butane blending with the oil before the LACT, the lighter hydrocarbon used for blending ust be received and stored at the terinal and the oil production easured before the blending point. Scenario 1: Dedicated tankage for clean crude and produced water for both the crude proration battery and the custo treating battery. Figure Custo treating, oil battery, and terinal scheatic scenario 1 Production Wells G R O U P / T E S T H E A D E R FWKO TREATER Produced Water Clean Oil Storage VRU Terinal Oil Storage GGS, Gas plant, Sales LACT Pipeline Oil Battery Subtype 322 Fuel Terinal Subtype 671 Vented Gas Eulsion Oil Storage TREATER Injection Facility Subtype 503 Custo Treating Facility Subtype 611 Clean Oil Storage Produced Water Injection Well = easureent point August 1, 2017 Page 10-3

261 Scenario 2: Dedicated etering on treaters for water/oil and a shared tank for clean crude and produced water. Figure Custo treating, oil battery, and terinal scheatic scenario 2 Production Wells VRU GGS, Gas plant, Sales FWKO TREATER Terinal Oil Storage LACT Pipeline Vented Gas Fuel Oil Battery Subtype 322 Custo Treating Facility Subtype 611 Terinal Subtype 671 Injection Facility Subtype 503 Eulsion Oil Storage TREATER Produced Water = easureent point Injection Well The ain difference between the two scenarios is that scenario 1 has dedicated tanks with etering off the tanks, whereas scenario 2 has shared tanks but etering off each treater. For both scenarios, the transfer of fuel fro the proration battery to the custo treating facility provides heat for the custo treater and pressure to help dup the treater to storage tanks. There is also a receipt eter for the gas coing back fro the custo treater and terinal to the proration battery Custo Treating Facilities SK AB BC The easureent requireents are the sae as for trucking into a non-heavy oil battery, Section The easureent requireents are the sae as for trucking into a non-heavy oil battery above, but the accounting and reporting ust follow the requireents in Appendix 6 of Manual 011: How to Subit Voluetric Data to the AER. See Measureent Guideline for Upstrea Oil and Gas Operations Pipeline Terinals or Railcar Terinals At the pipeline or railcar terinals that receive either pipelined and/or trucked clean oil, the receipt eter or weigh scale easureent is considered to be a custody transfer easureent. That is, there is no proration/allocation fro the disposition volues to the receipt (REC) volues that are reported to Petrinex. Any easureent beyond this point is considered as downstrea operations and not covered in this Directive. However, if the downstrea pipeline operator allocates to the shippers the ibalance generally less than 1% on its pipeline syste according to the contractual requireents and the allocated August 1, 2017 Page 10-4

262 volues are reported to Petrinex instead of the easured REC volues, then the delivery point easureent requireent also applies to the easureent point(s) at the other end of the pipeline. This scenario also applies to Section Clean Oil Terinals Clean oil terinals are those that receive trucked and/or pipelined clean oil only; the receipt eter is considered as a delivery point. That is, there will be proration/allocation fro the terinal LACT disposition volues to the receipt volues for that onth. Voluetric allocation of the onthly LACT volues to the onthly truck receipt volue is not required at a clean oil terinal without Regulator site-specific approvals if the eter factor for each delivery point eter or the weigh scale accuracy verification does not deviate fro the prior factor or verification by ±0.5%. Any deviation 0.5% ust be investigated and rectified, and allocation for the previous onth(s) disposition volues to the receipt volues is required. The licensee ust revert to allocating onthly pipeline LACT volues to the receipt volues if the deviation is not brought back with ±0.5% Gas Plants, Gas Batteries, and Gas Gathering Systes For gas systes receiving trucked liquid, the easureent requireents are the sae as for trucking liquid into a non-heavy oil battery Water Injection/Disposal Facilities For water trucked into an injection or disposal facility, delivery point easureent accuracy is not required. See Sections and for facility accuracy requireents Waste Processing Facilities A waste processing facility handles volues of waste generated in the upstrea petroleu industry. However, any Regulator-approved waste facilities have an integrated custo treating facility designated for processing oil/water eulsions extracted fro the solids during waste processing. In addition, oil/water eulsions fro other batteries are trucked in and easured independently fro the waste oil/water eulsions, and both streas are processed through the sae treating facilities. The total waste strea disposition to the custo treater (CT) ust have eulsion volue and S&W deterinations in order to properly allocate the clean oil and water volues back to the other received eulsions. Therefore, delivery point easureent is required at the receipt point of non-waste truck unloading and at the total waste oil/eulsion delivery point to the CT for further processing, such as in a treater, where it is coingled with other oil/eulsion fro other sources. There are also injection/disposal facilities that receive other liquids, such as waste streas going into subsurface caverns for disposal. Waste liquids for disposal require easureent accuracy siilar to disposal of produced water. SK AB See Directive R01: Voluetric, Valuation and Infrastructure Reporting for the requireents for waste strea easureent, accounting, and reporting. See Directive 058: Oilfield Waste Manageent Requireents for the Upstrea Petroleu Industry for the requireents for waste strea easureent, August 1, 2017 Page 10-5

263 BC accounting, and reporting. See Measureent Guideline for Upstrea Oil and Gas Operations Integrated Waste Processing Facilities Integrated waste processing facilities include: 1. Waste Plants (WP) 2. Custo Treating (CT) 3. Water Disposal (IF) 4. Terinal (TM) Integrated oil and water processing and waste facilities are ones with various distinct processing and reporting entities. They are referred to as oilfield waste anageent facilities (OWMFs), see Figure Any fluids transferred between the different reporting facilities within the integrated site ust be easured and reported. Report fuel gas receipt at the WP and fuel gas usage. No fuel gas transfer or fuel use reporting required at the CT in this scenario. SK AB BC See Directive R01: Voluetric, Valuation and Infrastructure Reporting for ore details. See Section 5 of Directive 047: Waste Reporting Requireents for Oilfield Waste Manageent Facilities for ore details. See British Colubia Oil and Gas Coission s Directives August 1, 2017 Page 10-6

264 Figure Integrated waste processing facility delineation Waste Plant Subtype 701 Fuel for WP and CT Sweet Fuel Source Inlet Hopper Saple Point s Waste Tank Vented Gas Waste Tank Vented Gas Ski Tank Ski Oil Water Terinal Oil Storage Vented Gas LACT Pipeline Vented Gas Solids Trucked to Landfill Custo Treating Facility Subtype 611 Solids Separation Terinal Subtype 671 Eulsion Storage Water Storage TREATER Water Ski Oil Clean Oil Storage Water Storage Vented Gas Injection Facility Subtype 503 Injection Well = easureent point Facilities that Produce Heavy Oil To eet heavy oil trucked production delivery point easureent requireents, the licensee ust use an appropriate ethod based on the fluid characteristics, such as viscosity, teperature, and sand content of the load. Generally, delivery point easureent is perfored by using weigh scales or tank gauging with sapling to deterine the S&W and/or density. Meters are used only when there are inial or no solids present in the oil/eulsion, siilar to trucking into an oil battery that produces nonheavy oil Design and Installation of Measureent Systes Delivery point easureent is required for ost trucked fluids delivery/receipt except as entioned in Section The gross volue ust be easured through a syste consisting of inlet tank gauging, inlet eter, or weigh scale. Gauge boards ust not be used for delivery point easureent. Truck ticket estiates such as volue estiates deterined using the truck tank load indicator copleted by the trucker or trucking copany for bill of lading/transportation of dangerous goods purposes are not considered as easureent for the purpose of well or facility volue easureent. Therefore, truck ticket estiates ust not be used for deterining volues unless the requireents in Section are et. See Section 14 for liquid easureent design and installation requireents. August 1, 2017 Page 10-7

265 Meters Turbine eters are typically not suitable for viscous fluids and therefore are not recoended for unloading crude oil. When etering devices for the purpose of easuring truck delivery/receipt volues are installed, the following ust also be installed: 1. Saple point 2. Air eliinator For soe types of eters and applications, a strainer and a back pressure control syste are required. Refer to Figure 14.1 for ore inforation. Additional requireents for clean oil and pipeline terinals: 1. For echanical autoatic teperature copensators without gravity selection (ATC) or with gravity selection (ATG): a. For new applications, echanical ATC and ATG ust not be used. SK AB BC No grandfathering in Saskatchewan. All existing ATC and ATG are grandfathered at their existing applications and ust not be relocated or reused for other applications. See Measureent Guideline for Upstrea Oil and Gas Operations b. The difference between actual density and copensation density ust be less than 40 kg/ 3. c. Product teperature ust be between 10 C and +40 C excluding LPGs. d. The copensation density echanically set density or user-entered density for electronic flow coputers ust be a volue weighted average of the expected receipt volues. When product teperatures exceed +40 C, it ay be necessary to reduce the allowable density difference to aintain a 0.5% uncertainty. e. Teperature copensation devices ust be designed for the actual range of operating teperatures observed. If product teperatures exceed +40 C, it ay be necessary to reduce the allowable density difference to aintain a 0.5% uncertainty Weigh Scales Weigh scales for the purpose of delivery point easureent ust be verified in accordance with Section For sapling points and ethods, see Sections 14.6 and 8.5. Systes eploying weigh scales ust also provide for deterination of density of oil and water in accordance with one of the following: 1. API MPMS, Chapter 9: Density Deterination Using Hydroeter 2. precision laboratory ethod ASTM ethod or 3. on-line densitoeter August 1, 2017 Page 10-8

266 To aintain an uncertainty of 0.5% or less, the net weight of the payload ust not be less than 40% of the gross vehicle weight and the net weight ust not be less than 6500 kg. An exeption fro this requireent is granted only during seasonal road ban periods when reduced truck loads are andated by weight restrictions Exeptions for Truck Measureent Systes Truck-Mounted Level Gauges and Truck-Mounted Meters Truck gauge level indicators and truck-ounted eters are considered to have et the requireent for low-accuracy easureent with an overall uncertainty of ±1% or less if the following criteria are et. These units can be used for trucked-in delivery point easureent to proration oil batteries if all of the following requireents are et: 1. The battery receives not ore than of trucked-in oil per day 2. The axiu percentage of trucked-in oil to any battery is 10% of the onthly total battery oil production volue 3. The gauges or eters are verified/proved annually and if not within ±1% accuracy they are repaired and recalibrated/reproved 4. The product teperature is deterined to within 1 C, see Section , ite 2 5. The truck gauge levels or eters are initially set by calibrating to a aster eter or provers with a deonstrated uncertainty of not ore than 0.2% Additional criteria for truck-ounted level gauges: 1. The stated depth of liquid is within 12.7 of a known gauge level arker if used 2. The depth of liquid is deterined while the tank trailer is level to within 150 over its length 3. The iniu load on the trailer is ore than 65% of full load Truck Tickets and Lease Tank Gauging Truck ticket volues uncorrected for teperature are not acceptable for delivery point easureent of trucked liquid. If the fluid transfers are between unitized facilities or facilities with no equity or royalty concerns, then the teperature correction estiates ay be used. The truck ticket ust be based on a low-accuracy easureent requireent with an overall uncertainty of ±1% or less of trucked liquid, such as lease tank gauging at the battery sending the liquid production or truck-ounted eter, for deterining inlet volues at a proration battery if certain situations exist. The S&W per cent and corrected opening and closing readings ust be on the ticket or available on a suary sheet for Regulator audit purposes. An individual truck load ust be recorded on its own ticket. The Regulator ay accept low-accuracy easureent with an overall uncertainty of ±1% or less for trucked liquid production at a proration battery if: 1. Trucked production is teporary, pending battery consolidation within one year or less. 2. Individual well oil volues being trucked are less than /day, see Section August 1, 2017 Page 10-9

267 3. The crude oil volue receipt net of water is 5% or less of the total receiving battery oil production. 4. Truck-ounted eters used for low-accuracy easureent with an overall uncertainty of ±1% or less are proved in accordance with the requireents in Section Load Fluids Load fluids, at a iniu, ust be easured using devices that eet the requireent for low-accuracy easureent with an overall uncertainty of ±1% either at the source loading location or at the delivery point. Reporting of load fluid on Petrinex is liited to oil-based and/or water-based fluid(s) injected during preproduction well stiulation or postproduction activities. Only the load fluid product codes OIL, COND, or WATER can be reported. Well drilling fluids ust not be reported on Petrinex as load fluids. Load fluids are to be reported at the well level except when in an SW Saskatchewan or SE Alberta shallow gas battery, since there is no requireent to easure and report water production at this type of well. The load fluid reporting then can be done at the battery level. SK AB BC See the Directive R01: Voluetric, Valuation and Infrastructure Reporting for ore reporting procedures. See the Manual 011: How to Subit Voluetric Data to the AER, Appendix 8 for ore reporting procedures. See British Colubia Oil and Gas Coission s Directives Split Loads A split load is defined as existing when a truck takes on partial loads fro ore than one well or battery in a single trip or when load oil is delivered to ore than one receipt point or wells. Requireents: If the densities of the split load coponents are different by ore than 40 kg/ 3, blending tables are required to calculate shrinkage. The shrinkage volue is to be prorated back to each battery on a voluetric basis. Measureent: Volue fro each well or facility ust be easured at the tie of loading onto the truck (or off loading fro the truck for load oil) by one of the ethods: 1. Gauging the battery lease tank. 2. Gauging the truck tank not allowed for density difference over 40 kg/ 3 for any oils or eulsions. 3. Truck-ounted eter/gauge that eets low-accuracy easureent and is proved at least annually. Calibrated gauge tables are required for ethods 1 and 2. August 1, 2017 Page 10-10

268 Sapling: Fluid fro each single-well oil battery ust be sapled to deterine the S&W and the oil/water volues. The truck driver is to collect the saples by taking at least three well-spaced grab saples during the loading period, see Section 14.6 and 8.5. For load oil, the S&W ust be deterined at the loading source. Records: The truck tickets ust show the individual load volues, as well as the total volue at delivery receipt point, supported by opening and closing gauge or eter readings. Accounting: For battery eulsions, the total load is to be easured and sapled at the receiving location and prorated to each of the wells based on the easured loading volues and S&W fro each of the wells. For load oil, the initial volue ust be easured at the loading source and prorated to each delivery point based on the easured volue delivered to each well. Allowed: 1. Single-well oil battery delivering to other facilities. 2. Gas wells with condensate-water tanks and production less than of total liquids per day. 3. Blending of heavy oil and condensate. 4. Load oil for well servicing only, specifically load oil fro a single source only. Not Allowed 1. Multiwell batteries delivering to other facilities other than load oil. 2. Gas wells with production greater than of total liquids per day Sapling and Analysis For trucked-in hydrocarbons and eulsions receipt/delivery, a truck sapler or a proportional sapler ay be used to obtain a saple fro the truck tank, see Section 14.6 and 8.5. In soe scenarios spot (grab) saples ay be used to obtain the saple fro the off-load/load line. Autoatic sapling ethods are preferred. However, anual or tank sapling systes ay also be allowed, as described in Sections and The frequency of sapling or readings ust be sufficient to ensure that a representative saple of the entire truck volue is obtained. Consideration ust be given to both conditioning the flow strea and locating a probe or sapler. Flow conditioning to ensure turbulent ixing can be achieved through velocity control, piping configurations, or introduction of a ixing eleent upstrea of the saple point. A saple probe is required for truck delivery point sapling unless there is an in-line product analyzer or the sapling August 1, 2017 Page 10-11

269 is incorporated as part of the easureent syste. A id-pipe probe location ust be used for accurate sapling, also see Sections and The licensee ust choose the sapling ethodology based on eulsion characteristics, stratification, and S&W consistency of each load to obtain a representative saple. API MPMS, Chapter 8.1, Section 8, provides further inforation on anual sapling procedures Autoatic Sapling Autoatic sapling is typically conducted through the use of proportional saplers. If autoatic sapling procedures are used, a anual procedure ust also be in place for use when the autoatic syste is out of service or for interittent verification of the autoatic syste reading. For ore inforation, API MPMS, Chapter 8.2, Sections 7 to 15, provide further details on flow conditioning, probe location, and sapling frequency. Other requireents for autoatic sapling: 1. Containers ade of suitable aterial for handling and storage of the saple ust be used. Container lids ust be vapour tight. 2. All saple containers ust be cleaned and dried prior to collection of the next saple. 3. Saple containers ust allow adequate roo for expansion and content ixing, taking into consideration the teperature of the liquid at the tie of filling. 4. The saple containers ust be housed in a secured enclosure to prevent any tapering with the saple. 5. Saple lines ust be as short as practical and sloped downward to reduce the possibility of plugging up the saple line Manual Spot (Grab) Sapling Manual spot (grab) sapling ay be acceptable in situations involving a tight eulsion with less than 0.5% S&W in the truck by taking three well-spaced grab saples during the unloading period, see Section 14.6 and 8.5. A single grab saple is not acceptable when there is stratification of S&W within the truck. The use of anual sapling techniques, either full height or interittent, ay also be acceptable. However, in the presence of stratification, one unit of height at the botto of the truck tank represents a significantly lesser volue than the sae unit of height at the idpoint of the truck tank because of the shape of the tank. The resulting S&W fro a fullheight core saple therefore ay not be representative of the entire load. In such cases ultiple grab saples are to be used. Lease tank anual sapling is subject to siilar stratification liitations excluding the nonunifority of the tank. These concerns can be reduced by locating any water-eulsion interface and obtaining botto, iddle, and top saples of the eulsion to deterine the average water cut of the eulsion. However, lease tank anual sapling requires dedicated tankage for each load received or delivered to avoid ixing of product between deliveries. August 1, 2017 Page 10-12

270 Visual estiates or estiates based on changing off-load pup speeds ust not be used for free water volue deterination S&W Deterination The licensee ust select the ost appropriate ethod for deterining the S&W, see Section 14.8 and Appendix Density Deterination Truck load saple density deterination at 15 o C ust be conducted at least annually or ore frequently if there are changes in the reservoir conditions. Density of the load ay be deterined by one of the following ethods: 1. Truck load saples ay be collected fro the receiving point and sent to an independent laboratory for analysis to deterine density of the liquid hydrocarbon phase and the liquid water phase (if required). The density found in this analysis ust be applied to all hydrocarbon liquids coing fro the specific facility; or 2. Truck load saples or saples fro autoatic saplers ay be tested for density as outlined in Section 14.6 and 8.5. In applications where the truck volues have an S&W greater than 1%, density deterination at 15 C of an eulsion saple is difficult, as there are two different theral corrections to be applied, one for the water and one for the oil. There are two options available: 1. The first is to deterine the saple density using a precision densitoeter that has its easuring cell at 15 C. No further corrections are required. 2. The second is to separately predeterine the density at 15 C of the water and the oil. When using this option, the eulsion density is calculated by applying the S&W cut to the density of each coponent. The calculation is Where: eulsion 100 % S & W % S & W oil water eulsion is the calculated density of the eulsion at 15 C oil is the density of the oil portion at 15 C water is the density of the water portion at 15 C 10.5 Volue Deterination Tank Gauging Tank gauging procedures are detailed in Section The starting and closing levels easured are then converted to volue through the use of gauge tables supplied by the tank anufacturer, which have been calculated using easureents of the tank. The difference between the closing and opening volues is the easured volue. If the tank is used for delivery point easureent, the teperature and density of the tank contents August 1, 2017 Page 10-13

271 ust be taken in order to correct the indicated volue to base conditions before deterining the volue difference Weigh Scales The procedure for deterining the volue of liquid on a truck using a scale is to weigh the truck before and after loading or unloading and deterine the difference to obtain the net weight. The entire load ust be weighed at a tie. Split weighing, whereby the truck is weighed after unloading a portion of its load to obtain the weight of the unloaded portion, is not peritted unless it is used in cold heavy oil easureent. To deterine the density of the load, an on-line densitoeter aybe used or a representative saple ust be obtained and the density and teperature easured with a hydroeter and theroeter respectively. The observed density ust be corrected to 15 C. The net weight deterined during the weighing process divided by the saple density at 15 C results in the net volue of the load prior to deductions for S&W Meters Metered volues ust be deterined in accordance with Section 14. August 1, 2017 Page 10-14

272 11 Acid Gas and Sulphur Measureent The sulphur easureent requireents in this section do not apply to operations and reporting in the Province of Saskatchewan. This section presents the base requireents and exeptions for acid gas and sulphur easureents at processing plants and injection facilities in the upstrea oil and gas industry that are used in deterining volues for reporting to the Regulator. SK AB BC Saskatchewan does not have specific sulphur easureent requireents. S-30 Monthly Gas Processing Plant Sulphur Balance Report requireents are also included, with instructions provided in Section See Measureent Guideline for Upstrea Oil and Gas Operations In a gas processing plant where sour gas is processed, ost of the acidic portion of the gas ust be reoved fro the gas strea (sweetening) in order to produce a saleable pipelinequality gas product. However, in the process of reoving the acidic portion of the sour gas, acid gas, which consists ainly of H 2 S and CO 2, is generated and ust be disposed of in an environentally and econoically acceptable way, such as by eleental sulphur production, acid gas injection, or acid gas flaring General Requireents SK AB The sour gas plant inlet and acid gas streas ust be easured and reported. The sour gas plant inlet and acid gas streas ust be easured and reported. The inlet sour gas strea volue including GEV of condensate, sour gas in solution in water, the sulphur disposition tonnage, and the sulphur balance ust be reported on a onthly basis on the S-30 report if the plant is approved with a sulphur inlet of ore than one tonne per day to the Regulator. See Table 11.1 for the onthly S- 30 sulphur balance requireent. For sour gas plants with less than one t/d of approved sulphur inlet, the S-30 report ust be subitted to Alberta Environent at its required tiing, with the exception of grandfathered plants that would still be required to subit S-30 reports to the Regulator until Deceber 31, For plants that are licensed as sweet but use a sweetening process to strip out excess CO 2, the reporting of the acid gas (CO 2 ) volue ust be the sae as sour plants under one tonne per day. Table Monthly S-30 Sulphur Balance Requireent Monthly average actual sulphur Maxiu Sulphur balance % inlet (tonne/day) error < 1 20% 1 5% In accordance with Interi Directive (ID) : Sulphur Recovery Guidelines for the Province of Alberta, other upstrea oil and gas facilities with sulphur eissions August 1, 2017 Page 11-1

273 BC greater than one tonne/day that are not required to subit S-30 reports ust aintain daily sulphur balance records and calendar quarter-year recovery calculations. These records ust be available for inspection or audit at the request of the Regulator. See Measureent Guideline for Upstrea Oil and Gas Operations The acid gas fro the sweetening process is generally saturated with water vapour. This water vapour portion ust be subtracted fro the saturated acid gas to obtain the dry volue without water vapourfor ore inforation refer to Section Acid Gas Measureent The quantity of acid gas going to sulphur plants, to copression and injection, or to flaring is generally easured at a low pressure of 50 to 110 kpag; therefore, the orifice eter, or any other eter, ust be appropriately sized and aintained to anufacturer s recoended specifications to achieve accurate easureent. Acid gas is saturated with water vapour, which represents a significant portion of the total gas easured. The aount of water vapour varies significantly with the teperature of the reflux dru. Therefore, the acid gas eter ust have continuous teperature correction (see Section 4.3) to calculate the correct acid gas volue as outlined in this section. The gas density ust also include the water content, and the eter coefficient ust include a factor to exclude the water vapour content of the gas in the final volue coputation for reporting purposes. The accuracy of the gas relative density factor and water content deterination ust be annually verified to ensure that acid gas easureent uncertainty is within tolerance Deterining Acid Gas on a Dry Basis For ideal gases, the total vapour pressure of a syste containing several coponents is the su of the vapour pressure of the individual coponents at the teperature of the syste. The coponent s vapour pressure percentage of the total pressure of a syste is equal to the volue percentage of that coponent in the syste. The reflux dru is the vessel in which the acid gas separates fro the sweetening solution. The aount of water vapour in the acid gas leaving the reflux dru is a function of the teperature and the absolute pressure in the reflux dru Calculating Acid Gas Flow Rate The calculation ethod for the acid gas flow rate is as follows: 3 Step 1: Deterine the percentage of water vapour in the acid gas on the basis of the ratio of vapour pressure of water to total pressure in the reflux dru at the reflux dru teperature. 3 Wichert, E., Water content affects low pressure, acid-gas etering, Oil & Gas Journal, January 2, 2006, pp August 1, 2017 Page 11-2

274 Step 2: Step 3: Step 4: Convert the acid gas coposition fro dry basis to wet basis at reflux dru pressure and teperature, and deterine the acid gas relative density and copressibility factor on a wet basis at eter pressure and teperature. Calculate the acid gas and water vapour flow rate corrected fro actual flowing pressure and teperature to base conditions of kpa(a) and 15 C. The volue calculated in step three contains water vapour in the percentage deterined in step one and ust be converted to dry basis volue for reporting purposes. An acid gas flow correction factor (CF) has to be applied to correct the acid gas flow fro a wet to a dry basis. CF = ( % H 2O in acid gas) 100 Dry acid gas flow rate = CF x flow rate calculated in Step 3 The H 2 S content of the acid gas is the dry basis acid gas flow ties the percentage of H 2 S divided by 100 in the acid gas on a dry basis Calculating Vapour Pressure of Water The forula for deterining the vapour pressure of water 4 is log P = (A B) (C + T RD) where: P = water vapour pressure in of ercury A = B = C = 235 T RD = teperature of acid gas in reflux dru ( C) The direct forula for deterining the vapour pressure of water in kpa(a) is thus ( /(235 + T)) P H2O = x 10 Where: P H2O = water vapour pressure in kpa(a) at T C % H 2O in the acid gas = (100 % * P H2O) (P RD + P at) Where: P RD = reflux dru pressure, kpag P at = atospheric pressure, kpa(a) Converting Acid Gas Calculation fro Dry to Wet Basis An exaple acid gas conversion calculation fro dry to wet basis with the eter installed upstrea of the back-pressure Regulator of the reflux dru is provided as follows: A. Reflux dru data Reflux dru teperature = 40 C Reflux dru pressure = 70 kpag Atospheric pressure = 95.0 kpa(a) 4 The vapour pressure of water at a certain teperature can also be obtained fro the GPSA Engineering Data Book, SI Units version, 12th edition, 2004 or subsequent versions, Figures August 1, 2017 Page 11-3

275 If the eter is installed upstrea of the back-pressure Regulator of the reflux dru, the upstrea pressure and the teperature of the eter run ay be used as the reflux dru pressure and teperature. B. Acid gas coponents on a dry basis fro acid gas analysis: H 2 S = 65% CO 2 = 33.5% C 1 = 1.2% C 2 = 0.3% C. Calculate the percentage of coponents, including water vapour, on a wet basis: Percentage of water vapour = (100% x Vapour pressure of water at 40 C) (Reflux dru gauge pressure + atospheric pressure) ( /( )) P H2O = x 10 = kpa(a) (Vapour pressure of water at 40 C is kpa(a), fro the Saturated Stea Table in the Therodynaics section of the GPSA SI Engineering Data Book, Figures ) Percentage of water vapour = ( ) x 100% = 4.47% Enter into colun 2 (see Table 11.2) and noralize. Table Calculation of relative density (RD) on wet basis Colun 1 Colun 2 Colun 3 Colun 4 Colun 5 Cop. Dry basis (%) Wet basis (%) Molar ass (Col. 1 * Col. 3) (kg/kol)* /100 (Col. 2 * Col. 3) /100 H2S CO C C H2O Total * Molar ass of air = kg/kol (GPSA Engineering Data Book, 2004 or later editions, Figure 23-2, or GPA-2145). Fro colun 4, ideal gas RD, dry basis = / = Fro colun 5, RD wet basis = = (this RD is to be used in the flow calculation for acid gas volues) Difference between the Acid Gas Volue on a Wet Basis and on a Dry Basis An exaple calculation is presented to show the difference in the results of the acid gas flow rate and the sulphur content of acid gas using dry versus wet basis etering. The exaple data for the eter run and assued conditions are as follows: 1. Orifice eter diaeter: Orifice plate diaeter: Meter upstrea pressure: kpag 4. Differential pressure: kpa 5. Meter teperature: 40 C 6. Atospheric pressure: 95.0 kpa 7. Acid gas coposition: as per Table 11.2 August 1, 2017 Page 11-4

276 Results with AGA # or later ethod: 1. Flow rate, dry basis without accounting for oisture content = /d 2. Sulphur content = ( x 65) (100 x ) = tonne/day 3. Flow rate, wet basis = /d, containing 4.47 percent H 2 O 4. Flow rate, wet basis converted to dry basis = ( x ( )) 100 = /d dry acid gas equivalent This volue, , is to be reported as Acid Gas on the onthly voluetric subission. An exaple for percentage difference in acid gas volue between dry and wet basis: 1. Percentage difference in flow rate = ( ) x 100 % = 3.51% 2. Sulphur content = ( x 65) (100 x ) = tonne/day 3. Difference in calculated sulphur balance between dry and wet basis etering = = 0.99 tonne/day 4. Percentage difference = (0.99 x 100) = 3.51% Thus, if the oisture content in the etering of the acid gas in this exaple were ignored, specifically if it was done on a dry basis taken as wet basis, the reported acid gas flow and sulphur content in the acid gas leaving the reflux dru would be 3.51% higher than the correct value. This ethod of estiating the water vapour content is valid when the gas is in contact with water in a low-pressure vessel, such as in the reflux dru. The ethod does not apply to low-pressure gas, such as in a flare line, when the flared gas originates fro a high-pressure vessel. The Table 11.3 suarizes the previous exaple and also provides the results that are obtained by the 1985 AGA # 3 Report ethod, using Wichert-Aziz (W-A) copressibility factors. Table 11.3 AGA #3, post-1992 AGA #3, 1985, W-A Z factors* Ite Dry basis Wet basis Dry basis Wet basis Z factor at St d P and T Z factor at Meter P,T Flow rate, /d Corrected to dry gas % difference Sulphur flow, tonnes/day % difference, tonnes/day *Z factors by Wichert-Aziz ethod, including water content in wet gas. August 1, 2017 Page 11-5

277 Calculation Method of Water Content if Meter Located Downstrea of Back-Pressure Valve of Reflux Dru The water content in the acid gas is a function of the pressure and teperature of the reflux dru. If the acid gas eter is located downstrea of the back-pressure Regulator of the reflux dru, both the pressure and the teperature of the eter will be soewhat lower than the pressure and teperature of the reflux dru. Under these conditions, it is still necessary to deterine the water vapour content of the acid gas strea at the reflux dru pressure and teperature, as shown in the previous exaple, to correctly calculate the acid gas flow rate. The reflux dru pressure ust be recorded for the correct calculation of the water vapour content of the acid gas. The reflux dru teperature ust be used to estiate the water content. However, since the flow data fro the eter includes the teperature at the eter run, the reflux dru teperature can be estiated on the basis of the eter teperature, as follows: T RD = (T * P 2) (P RD + P at) Where: T RD = reflux dru teperature, C P 2 = the downstrea eter tap pressure, kpa(a) P RD = reflux dru pressure, kpag P at = atospheric pressure, kpa(a) T = eperature downstrea of the orifice plate, Having estiated the teperature at the reflux dru fro the teperature downstrea of the orifice plate, the vapour pressure of the water can be calculations shown in Section The percentage of water vapour in the acid gas can then be deterined using the reflux dru pressure, and the sae procedure as outlined in the exaple shown in Section can be used to calculate the acid gas flow rate Effect of Copression and Cooling of Acid Gas In the situation of acid gas copression and injection, the acid gas flow rate ay in soe instances be etered after one or ore stages of copression and cooling, refer to Section This will reove a sufficient aount of water so that the reaining water vapour in the copressed and cooled acid gas will have little effect on the acid gas etering. In such a situation, it is not necessary to include the effect of water vapour in the etering of the acid gas Sulphur Measureent and Pit Volue Deterination Sulphur Pit Volue/Tonnage Deterination When pit gauging is used to deterine a liquid sulphur volue, the gauging procedures ust be conducted in accordance with the following: 1. The operator ust ensure that the gauge/strapping table used to convert the gauge level to a liquid volue is specific for the pit being gauged. 2. Pit gauging ust be used for inventory deterination only and ust not be used for delivery point easureent. August 1, 2017 Page 11-6

278 3. All dip sticks and electronic level devices ust have a iniu resolution of six. 4. It is acceptable to have one reading per deterination. 5. The sulphur density at pit teperature is obtained fro Figure The general forula for deterining the produced sulphur tonnage is as follows: Sulphur tonnage = Gauge reading x CF x Sulphur density where CF = Pit gauge/strapping table conversion factor Sulphur Measureent For sulphur sales/delivery point easureent using eters, see Section and These eters ust be kept at a teperature so that the olten sulphur will not solidify when there is no flow. For sulphur sales/delivery point easureent using a weigh scale, see Sections 2.12, and For daily sulphur production easureent using pit level gauging, two pits are required, one for production and the other for withdrawal using level easureent. The daily sulphur production tonnage ust be adjusted by the total onthly disposition at the end of the onth Exeption for Sulphur Tonnage Entering a Gas Plant For daily sulphur production volue deterination, if there is only one pit in place in an existing plant and sulphur is being withdrawn without easureent, the operator ay use the easured acid gas volue on a dry basis, provided that there is a continuous acid gas sapling device, such as a gas chroatograph, to calculate the sulphur tonnage entering the sulphur plant. The daily sulphur production can then be calculated using the following forula: Estiated daily sulphur production (t) = Daily acid gas inlet (t) Daily incineration (t) Daily flared (t) Others if applicable (t) The estiated daily sulphur production tonnage ust be adjusted by the total onthly disposition at the end of the onth by calculating a proration factor and applying that to all estiated daily production tonnage: Sulphur proration factor (S pf) = Total onthly sulphur disposition tonnage (including inventory changes) Total estiated daily sulphur production tonnage Actual daily sulphur production (t) = Estiated daily sulphur production (t) S pf SK AB BC Saskatchewan does not have a sulphur balancing report. The actual daily sulphur production is the daily production tonnage to be reported on the S-30 Monthly Gas Processing Plant Sulphur Balance Report. See Measureent Guideline for Upstrea Oil and Gas Operations 5 Tullen, W. N., The Sulphur Data Book, New York: McGraw-Hill Book Copany, Inc., 1954, p. 17. August 1, 2017 Page 11-7

279 Figure Liquid sulphur density vs. teperature 11.4 Sulphur Balance Calculation for Sour Gas Processing Plants When sour gas is produced to a sour gas treating plant, it always enters the plant through a plant inlet separator. A liquid water phase is usually present with the sour gas, and in any instances a liquid hydrocarbon phase can also be produced into the separator with the gas and water. In such situations, all three phases will contain soe H 2 S in different proportions. August 1, 2017 Page 11-8