Bulletin 2011-12

Bulletin 2011-12: Revised Edition of Directive 017: Measurement Requirements for Oil and Gas Operations Issued

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Revised Edition of Directive 017: Measurement Requirements for Oil and Gas Operations Issued

Apr 18, 2011

This bulletin announces the release of the revised edition of Energy Resources Conservation Board (ERCB) Directive 017: Measurement Requirements for Oil and Gas Operations, which replaces the edition issued on October 22, 2009. The word “upstream” is removed from the directive title in the April 2011 edition. Additionally, the new Sections 12.4, 14, and 15, described below, and clarifications to the pre-existing 13 sections of Directive 017 are incorporated into this revised edition and are effective April 18, 2011. Due to the complexity of consolidating and clarifying existing requirements and updating them to meet the current technological advancement and operating environment, this directive is being developed in stages, with new sections added as they become available.

The revised edition of Directive 017, as well as a new document addressing frequently asked questions (FAQs), is available on the ERCB Web site www.ercb.ca under Industry Zone : Rules, Regulations, and Requirements : Directives. Printed copies of the directive may be purchased from ERCB Information Services, Suite 1000, 250 – 5 Street SW; telephone: 403-297-8311; fax: 403-297-7040; e-mail: infoservices@ercb.ca.

In the version available on the ERCB website, all changes made in editions published from 2007 to October 2009 appear in red type and all changes made since the previous edition (October 2009) appear in blue type.

Clarifications, Updates, and New Requirements in Sections 1 to 13

  • Purpose: Clarified that the requirements apply to measurement points used for accounting and reporting purposes, as well as those points required under existing regulations.
  • Sections 1.7.1, 1.7.2: Added where delivery point measurement applies.
  • Section 1.7.2(vi): Clarified gas flare measurement and estimation limits for cold heavy oil and thermal in situ operations.
  • Section 1.7.2(vii): Clarified acid gas measurement after compression single point uncertainty requirement.
  • Section 1.7.3(ii): Clarified that each injection well requires measurement.
  • Section 1.7.3(iv): Added in steam measurement uncertainty requirements from Section 12.4. Clarified that each injection well requires measurement.
  • Section 1.8.3: Updated all uncertainty limits in the summary.
  • Section 2.1: Moved definitions of primary measurement element, meter element, and end device from 2.5.1.
  • Section 2.4: Clarified that the uncertainty of the proving or calibration device must be equal to or better than device being proved or calibrated.
  • Section 2.5.1: Clarified what part of the measurement system requires calibration or inspection.
  • Section 2.5.2: Added that gas meter proving may be an alternative method to internal inspection.
  • Section 2.6: Replaced Table 2.1 with a new table containing more detailed information and changed “hydrocarbons or hydrocarbons/water emulsion” to “the normally metered fluid” and added that LACT meters may use API procedures for proving.
  • Section 2.6.1: Clarified that continuous does not include intermittent flows.
  • Sections 3.1.4: Updated proration factor limits and Petroleum Registry of Alberta subtype codes.
  • Sections 3.2.1: Clarified that measured or proration batteries should not have metering differences.
  • Section 4.3.1(1): Removed single oil wells from daily chart requirement.
  • Section 4.3.1(3): Added in constant pressure measurement exceptions.
  • Section 4.3.1(12): Added in mass meter density variation limitation on gas measurement applications.
  • Section 4.3.3.1(9): Added that at least one on/off cycle must be completed within a reporting period.
  • Section 4.3.6: Originally Section 4.3.3.2. Renumbered and moved.
  • Section 4.3.6.1: Changed gas electronic flow measurement (EFM) hardware and equipment requirements to match what is in Section 14 for liquid EFM. Formerly Section 4.3.3.2(a).
  • Section 5.5.1: Added continuous or 31-day test provision.
  • Sections 6.3 to 6.8: Relevant subsections have been moved to the new Section 14.
  • Section 6.9: Added reporting cases on Alberta Energy royalty regimes for oil producing wells.
  • Section 7.1.3: Deleted; information moved to Table 7.1 under Section 7.1.
  • Section 7.4.1: Added re-testing requirements.
  • Section 8.2: Added exception to allow C6+ composition for sales or delivery points.
  • Section 8.4.5: Exceptions item (1), “or” has been changed to “and” to be consistent with other subsections.
  • Section 10.1.2: Clarified publication applicable as Technical Publication TP-27.
  • Section 10.2.1: Clarified terminal requirements for an oil battery and delivery points.
  • Sections 10.3 to 10.5: Relevant subsections have been moved to the new Section 14.
  • Section 10.5.2: Added exception for split weighing for cold heavy oil measurement.
  • Section 11.2: Clarified that acid gas meters must have continuous temperature correction.
  • Section 11.4.4.3: Clarified that acid gas must also be measured before injection into a well at the injection well site.
  • Section 12.3.1.2: Clarified that licensed multiwell batteries or multiple single-well batteries on the same lease cannot be a part of a paper battery.
  • Section 12.3.1.3: Clarified that inventory is required if Disposition = Production method is not used.
  • Section 12.3.2.2: Clarified gas requirements at a multiwell proration battery.
  • Section 12.4: New subsection added for thermal in situ oil sands operations.
  • Section 13.3: Added the reporting cases’ equivalence to Alberta Energy’s royalty regimes.
  • Appendix 1: Added new development items.
  • Appendix 2: Directive 004: Determination of Water Production at Gas Well rescinded with this revised version.

New Sections

Section 12.4: Thermal In Situ Oil Sands Operations—This subsection presents the requirements and exceptions for thermal in situ oil sands facilities, but does not cover crude bitumen production through mining.

Section 14: Liquid Measurement—This section presents the requirements for liquid hydrocarbon measurement (i.e., crude oil, bitumen, condensate), liquefied petroleum gases (i.e., propane, butane), dense phase hydrocarbons (i.e., ethane, natural gas liquids), and water. It represents a consolidation of the liquid measurement requirements contained in other sections.

Section 15: Water Measurement—This section presents the requirements for measurement and reporting of water with respect to oil and gas production, water sources, injection and disposal, waste processing and disposal, storage and disposal caverns, and thermal in situ oil sands schemes.

Some of the highlights of the new sections are presented below:

Section 12.4 Section 14 Section 15
  • Bitumen, diluent, dilbit measurement
  • Gas, steam, solvent, and water measurement
  • Single point measurement uncertainties for various applications not covered in Section 1
  • Water/steam primary and secondary measurement
  • Monthly water balance
  • Production well testing
  • Application of API measurement standards
  • System design and installation
  • Meter selection
  • Shrinkage determination requirements
  • Pressure and temperature measurement
  • Density determination
  • Tank measurement
  • Sampling and analysis
  • Liquid volume calculations
  • Record keeping
  • Water measurement and accounting requirements for various battery/facility types
  • Water-gas-ratio testing methodology and calculation

Further Information

Please forward comments and questions to Bill Cheung, of the Field Surveillance and Operations Branch, directly at 403-297-8798 or by e-mail at bill.cheung@ercb.ca.

 

<original signed by>

Robin King
Executive Manager
Field Surveillance and Operations Branch