Bulletin 2016-07

Bulletin 2016-07: Updates to Directive 017: Measurement Requirements for Oil and Gas Operations

VIEW PDF (103.22 KB)

Updates to Directive 017: Measurement Requirements for Oil and Gas Operations

Mar 31, 2016

The Alberta Energy Regulator (AER) has released a revised edition of Directive 017: Measurement Requirements for Oil and Gas Operations (Directive 017) , which replaces the edition released on May 28, 2015. The updated directive revises specific measurement requirements based on feedback from industry and on observations the AER has made while monitoring operations.

Directive 017 consolidates, clarifies, and updates AER requirements for measurement points used for AER accounting and reporting purposes, as well as those measurement points required for upstream petroleum facilities and some downstream pipeline operations under existing regulations.

The purpose of the revised edition of Directive 017 is to update requirements, primarily related to aspects of measurement systems for production operations in the Duvernay and Montney formations, pad-level measurement at thermal operations, smart transmitter calibration, and proving and sampling frequencies. These changes provide greater flexibility in measurement equipment and reduce operating costs without compromising accurate measurement and reporting.

The new edition of Directive 017 includes the following changes:

Change

Location in revised directive

Updated the enforcement section by removing the reference to Directive 019 and adding guidance to refer to the AER website for more information on compliance and enforcement.

Introduction

Moved the produced gas meter downstream of the fuel and flare meter to clarify that all gas is used for fuel, flared, or sent to a gas gathering system.

Figure 1.2

Clarified that up to 0.50 103 cubic metres per day (m3/d) of fuel gas may be estimated at upstream oil and gas facilities that require metering of fuel gas.
Clarified that up to 0.50 103 m3/d of flared and vented gas may be estimated at upstream oil and gas facilities that require metering of flared and vented gas.

Section 1.7.2

Revised electronic flow measurement (EFM) requirements to allow a five-year calibration frequency for digital (smart) transmitters at gas and oil/condensate meters for nondelivery measurement points.
Revised the procedure for verifying temperature probes connected to EFM to verify without decoupling the temperature probe from the transmitter.

Section 2.5.4

Revised meter proving frequency from annual to biennial for live oil/condensate and water meters where volumes are ≤ 2.0 m3/d.

Section 2, table 2.1

For delivery point meters that measure trucked-in oil, oil emulsion, and condensate and that have no moving internal parts, the proving frequency has been extended from quarterly to semiannually if the meter factor has been found to be within 0.5 per cent of the average of the previous three monthly meter factors.

Section 2.6, Exceptions 4

Clarified that fuel use up to 0.50 103 m3/d may be estimated at upstream oil and gas facilities, and where fuel metering is required and a single site has multiple Petrinex reporting facilities, fuel gas may be metered at the site level and then allocated and reported at each individual reporting facility.

Section 4.2.2 and 4.3.3.1, 9

Clarified that up to 0.50 103 m3/d of flared and vented gas may be estimated at upstream oil and gas facilities that require metering of flared and vented gas.

Section 4.2.2 and 4.3.3.1, 10

Revised reporting requirements for single- and multiwell group gas batteries to allow the disposition equals production reporting methodology for condensate and water for wells that produce ≤ 2.0 m3/d of total liquid (i.e., condensate and water).

Sections 4.2.2.1 and 4.2.2.2

Clarified that when gas is injected into the wellbore to assist in lifting the liquids to the surface, the well status should be “GAS LIFT” for oil wells and “GAS PUMP” for gas wells.

Section 4.3.3.2

New section that consolidates existing operational scenarios and reporting errors that require correction and amendments to be made in Petrinex for magnitude of gas and condensate volumetric data.

Section 4.3.3.3

Revised battery-level gas-oil ratio (GOR) qualifying criteria for proration oil batteries to include only wells producing ≤ 0.5 103 m3/d of gas. The previous qualifying criteria was average well gas production of ≤ 0.5 103 m3/d and maximum oil production from each well of ≤ 2.0 m3/d.

Section 4.3.5.2

Exempted gas wells that produce ≤ 3.0 103 m3/d of gas from two qualifying criteria for extended gas chart cycle by exception.

Sections 5.3.1 and 5.3.3.1

Added a measurement-by-difference (MbD) scenario (schematic diagram and measurement and reporting requirements) where a measured gas source delivers measured oil or oil emulsion to a proration gas battery, gathering system, or gas plant.

Sections 5.5.2 and 5.5.3.1(a), 8

Added three acceptable fuel gas MbD scenarios.

Section 5.5.6

New section that describes the operational scenarios and reporting errors that require correction and amendments to be made in Petrinex for magnitude of oil production volumetric data. Thresholds were previously in Directive 046: Production Audit Handbook.

Section 6.3.4

Added an exception to the testing requirements for wells in gas multiwell proration batteries outside SE Alberta to allow new and existing wells producing from the SE Alberta shallow gas zones to be tested in accordance with the testing requirements for wells in SE Alberta multiwell gas proration batteries.

Added an exception to allow existing wells with a liquid-gas ratio ≤ 0.01 m3 liquid / 103 m3 gas in batteries located outside the SE Alberta shallow gas zones to be tested in accordance with the testing requirements for wells in SE Alberta multiwell gas proration batteries.

Section 7.3.1

Clarified that effluent-measured gas wells requiring biennial effluent correction factor (ECF) testing must use the ECF, condensate-gas ratio (CGR), water-gas ratio (WGR), and sample analysis from the most current ECF test until the next ECF test results and sample analysis are available.

Section 7.4.1.1, note 6

Revised the methodology for calculating production volumes for test-exempt batteries and test-exempt wells in batteries that have a mix of tested and test-exempt wells. The revised methodology allows for the most recent ECF-test WGR and CGR to be used instead of a battery-calculated WGR and CGR.

Section 7.4.2

Added sampling and analysis requirements for wells in test-exempt batteries and for test-exempt wells in batteries that have both tested and test-exempt wells. Previously, sampling requirements were not defined.

Section 7.4.3

Added new section, “Well Effluent Measurement in the Duvernay and Montney Plays.”

Section 7.5

Revised sampling and analysis requirements for shallow gas and coalbed methane (CBM) batteries with wells that have been fractured or completed with nitrogen (N2) or carbon dioxide (CO2) to allow the use of analog data sets for well gas composition when calculating well gas volumes.

Section 8.4.1

Revised sampling and analysis requirements for shallow gas and CBM single and multiwell group batteries with wells fractured or completed with (N2) or (CO2) to allow the use of analog data sets for well gas composition when calculating well gas volumes.

Revised CBM well sampling and analysis requirements to allow for a single sample and analysis for wells not fractured or stimulated using a gaseous medium.

Section 8.4.4

Added a requirement that all gas measurement devices must be calibrated, proved, or verified annually or as otherwise stated in section 2.

Section 12.3.3

Added that operators may measure steam injected on a grouped basis for wells once the associated subsurface drainage area has coalesced. Steam injection must continue to be reported to Petrinex for each well using its unique well identifier (UWI).

Section 12.3.4

Added that operators may measure solvent injected on a grouped basis for wells once the associated subsurface drainage area has coalesced. Solvent injection must continue to be reported to Petrinex for each well using its UWI.

Clarified that all solvent injection measurement devices must be calibrated, proved, or verified annually or as otherwise stated in section 2.

Section 12.3.7

Revised section title to Well Production Measurement from Well Testing.

Added that operators may measure production on a grouped basis for wells once the associated subsurface drainage area has coalesced. Production of oil, gas, and water must continue to be reported to Petrinex for each well using its UWI.

Added that ±2 per cent applies only to individual wells for emulsion tests.

Added ±5 per cent for single point measurement uncertainty for group-metered emulsions, excluding the effects of steam and hydrocarbon vapours and the effects of determining sediments and water (S&W).

Section 12.3.9

Cleaned up wording by removing reference to previous, old proration factors and moved the summary table of proration factors from section 12.3.14.

Section 12.3.10

Added internal inspection exceptions for thermal in situ oil sands operations.

Section 12.3.11

Table 12.4: Relocated table 12.4 to section 12.3.10 and renumbered to table 12.3.

Table 12.3: Renumbered table 12.3 to table 12.4, changed single point measurement uncertainty criteria for grouped well metering to ±5 per cent, and clarified that individual emulsion testing single point measurement uncertainty is ±2 per cent.

Section 12.3.14

Added load water reporting section that allows operators to discontinue load water recovery reporting from a well after being on production for 12 months.

Section 15.2.10

Added definitions of condensate-gas ratio (CGR), oil-gas ratio (OGR), and water-gas ratio (WGR).

Appendix 2

Corrected battery gas production and gas gathering system calculated volumes and the associated measurement difference between the gas battery and gathering system. The previous calculation used an incorrect volume.

Appendix 9


Directive 017 is available on the AER website, www.aer.ca. Printed copies of the directive can be purchased from AER Order Fulfillment, Suite 1000, 250 – 5 Street SW, Calgary, Alberta T2P 0R4; telephone: 403-297-8311 or 1-855-297-8311 (toll free; option 2); fax: 403-297-7040; e-mail: InformationRequest@aer.ca.

Comments or questions should be directed to the AER Customer Contact Centre at 403-297-8311 or by e-mail at inquiries@aer.ca.

<original signed by>

Kirk Bailey
Executive Vice President
Operations