H₂S Release Rate Assessments

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Overview

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An H₂S release rate assessment estimates the maximum potential hydrogen sulphide release rate from a well. The result is used to support well licensing, emergency planning, well classification, emergency planning zone calculation, facility level designation, and sour well design considerations.

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In Alberta, H₂S release rates are required before a well licence application can be submitted. The CAPP H₂S Release Rate Assessment Guideline states that H₂S release rates are prepared for drilling, completion, servicing, and producing operations, and are used to determine the EPZ, the classification of the well, and the facility level designation for setback requirements.

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The basic H₂S release rate calculation is:

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H₂S Release Rate = AOF × H₂S% × 0.01 / 86,400

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Where:

H₂S Release Rate = surface H₂S release rate, m³/s
AOF = surface absolute open flow potential, m³/d
H₂S% = maximum H₂S concentration as a percentage of the total gas stream
86,400 = seconds per day

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The CAPP guideline states that the H₂S release rate for each potentially sour zone is determined by multiplying the maximum H₂S content and AOF rate, and that the sum of the release rates from each zone becomes the cumulative release rate for the applicable drilling, completion/servicing, or suspended/producing case.

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Approval Types

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H₂S release rate assessments may be required for several types of well and project applications, including:

• New well licence applications

• Well licence amendments

• Emergency response planning updates

• Facility level designation reviews

 

The release rate case depends on the operation being assessed.  Common cases include:

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• Drilling case

• Completion / servicing case

• Producing case

• Suspended / producing case

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While a H2S release rate assessment report is not required to be submitted to the AER before applying for a well license, it must be on hand if the AER requests for audit purposes.  The AER does allow each report to be submitted prior to well licensing by operators to ensure they are in agreement with the applicant's analysis. 

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Application Process

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 A practical H₂S release rate assessment generally follows this process:

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1. Identify the proposed well location and target formation.

2. Identify all formations that may contain H₂S.

3. Determine which formations are open to the wellbore for each operating case.

4. Define whether the assessment is for drilling, completion/servicing, producing, or multiple cases.

5. Search for representative H₂S concentration data.

6. Search for representative AOF or flow capability data.

7. Review geological analogues.

8. Review wellbore configuration.

9. Apply appropriate engineering adjustments.

10. Calculate the H₂S release rate for each potentially sour zone.

11. Sum the applicable zone release rates.

12. Determine the EPZ.

13. Determine the well classification using Directive 056 section 7.7.4 and Table 4.

14. Determine whether emergency planning, sour well, facility level, or setback implications apply.

15. Prepare and retain the calculation package and supporting data.

 

For Alberta wells, the EPZ is commonly calculated using ERCBH2S plume dispersion modelling software, although the analyst should confirm the applicable jurisdiction-specific requirements.

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Data Requirements

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A complete H₂S release rate assessment should include:

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• Proposed well UWI

• Surface location

• Bottomhole location

• Well type

• Proposed wellbore path

• Drilling program

• Intermediate casing depth, if applicable

• Target formation

• Deepest formation to be penetrated

• Formations open to the wellbore during each operating case

• H₂S concentration data

• AOF or flow capability data

• Offset well list

• Representative analogue wells

• Gas analyses

• Well test data

• Pool information

• Formation tops

• Reservoir pressure data

• Net pay

• Stimulation information

• Gas/oil ratio information for oil wells

• Completion configuration

• Tubing/casing configuration

• Packer information, where applicable

• ERCBH2S inputs

• Audit forms and supporting calculations

 

The CAPP guideline recommends beginning with a three-by-three township study area to review well penetrations and establish geological analogues, while noting that smaller or larger areas may be appropriate depending on data quality and geological representativeness.

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For wells drilled outside an existing pool, the guideline generally recommends a minimum search radius of five kilometres and a minimum of five representative H₂S samples and five AOF samples, unless geological circumstances support a different approach.

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Geological Requirements

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The geological review is critical because the H₂S release rate should represent the highest credible release rate from the proposed well.

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Typical geological requirements include:

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• Identification of all potentially sour formations

• Formation tops

• Pool boundaries

• Structural interpretation

• Stratigraphic interpretation

• Gas cap versus oil leg interpretation

• Hydrocarbon/water contacts

• Porosity distribution

• Subcrop or depositional edge review

• Isolated reef or separate geological trend review

• Offset well data quality review

• Review of whether each formation is expected to be present, absent, wet, non-porous, eroded, or sweet

• Geological support for excluding any formation

• Identification of the most representative analogues

 

The CAPP guideline states that a well’s geological setting must be clearly defined to estimate potential H₂S release rates, and that all prospective formations and corresponding H₂S concentrations must be assessed individually. A potentially sour formation should not be excluded simply because there is no data proving it is sour; it should only be excluded if there is data proving that it is sweet.

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Where the position of the gas/oil contact is uncertain, the guideline states that both gas cap and oil leg release rates should be assessed, and the greater release rate should be used.

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Engineering Requirements

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The engineering review focuses on converting available analogue data into a reasonable estimate of maximum wellhead flow potential for the proposed well. Typical engineering requirements include:

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• AOF review

• Surface AOF calculation

• Sandface AOF calculation, where applicable

• Adjustment to proposed reservoir pressure

• Adjustment for net pay

• Adjustment for contacted reservoir length

• Adjustment for wellbore type

• Adjustment for slant or horizontal well geometry

• Adjustment for stimulation

• Adjustment to zero skin, where applicable

• Conversion from sandface AOF to wellhead AOF

• Tubing and casing flow assumptions

• Wellhead-on and wellhead-off scenarios, where applicable

• Multi-zone or commingled flow assumptions

• Completion configuration

• Producing configuration

• Acid gas or high-H₂S gas property review, where applicable

 

The CAPP guideline states that analogue AOF data may need to be adjusted for reservoir pressure, net pay, skin, well type, contacted reservoir length, and finally from sandface AOF to wellhead AOF. The wellhead AOF adjustment should be the final adjustment.

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For producing cases, if the wellhead is installed and a packer is in place, the guideline indicates that flow may be based on the tubing configuration. If no packer is in place, tubing and annulus flow rates should be combined to determine maximum expected flow.

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For acid gas or high-H₂S cases, gas properties may require special attention. The guideline recommends using pseudo-pressure for acid gas calculations and for sweet gas calculations above 14 MPa.

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For sour water injection or disposal wells, the H₂S release rate assessment should be based on the H₂S concentration in the vapour phase, not simply the dissolved H₂S concentration reported in the water analysis.

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Where the H₂S is dissolved in the injected water, the vapour-phase H₂S concentration is typically estimated from the water analysis using Henry’s Law, along with the applicable pressure and temperature conditions. If the H₂S concentration in the vapour phase is equal to or greater than 0.01 mole percent (100 ppm in the vapour phase), an EPZ determination is required.

 

For sour water injection wells, the H₂S release rate should be calculated using the maximum expected vapour-phase H₂S concentration, the maximum gas-to-liquid ratio, and the maximum expected liquid injection rate multiplied by three.

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Regulatory Requirements

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AER Directive 056 section 7.7.4 and Table 4 should be used to classify wells based on the calculated H₂S release rate and applicable operating case.

 

The H₂S release rate assessment supports:

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• Well classification

• Critical or non-critical sour well determination

• Emergency planning zone

• ERP requirements

• Drilling program requirements

• Producing well level designation

• Facility level designation

• Setback requirements

• Emergency response planning

• Sour well design considerations​

 

The CAPP guideline states that H₂S release rates are used to determine the EPZ, the classification of the well as critical or non-critical, and the facility level designation for land-use setback requirements.

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The calculated release rate should be compared against Directive 056 section 7.7.4 and Table 4 for the applicable drilling, completion/servicing, producing, or suspended/producing case. If the result changes the well category, EPZ, ERP obligations, drilling requirements, or facility level designation, the application package should be updated accordingly.

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Operators should also consider both “wellhead on” and “wellhead off” release rates where applicable. The CAPP guideline notes that if the “wellhead on” release rate results in a non-critical classification but the “wellhead off” release rate would result in a critical sour well, the wellhead design and casing/tubing material selection should correspond to recommended practices for a critical sour well.

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Stakeholder Engagement

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H₂S release rate assessments affect emergency planning and stakeholder engagement because the calculated release rate is used to determine the EPZ. Stakeholder implications may include:

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• Emergency response planning

• Public protection planning

• EPZ size

• Resident notification

• Landowner communication

• Public consultation requirements

• Urban density considerations

• High public usage areas

• Sour well classification

• Facility level and setback restrictions

 

The CAPP guideline identifies situations where a more rigorous analysis is expected, including where the EPZ includes residents or high public usage areas, where the well is within 5.0 km of an urban density development with 50 or more dwellings, or where the well is a critical or special sour well.

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Because H₂S release rate can affect the EPZ and emergency response obligations, operators should review release rate assumptions early in the project rather than waiting until the well licence is ready for submission.

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Common Deficiencies

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Common deficiencies in H₂S release rate assessments include:

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• Missing H₂S data

• Poor-quality gas analysis

• Failure to use the highest valid representative H₂S concentration

• No clear analogue selection rationale

• Insufficient AOF data

• Insufficient search area

• No explanation for excluded data

• Excluding potentially sour formations without proof they are sweet

• Failure to evaluate all formations open to the wellbore

• Failure to calculate separate drilling, completion/servicing, and producing cases

• Failure to consider wellhead-on and wellhead-off scenarios

• Incorrect use of gas cap versus oil leg data

• Inappropriate GOR assumptions for oil wells

• Failure to account for stimulation

• Failure to adjust for horizontal or slant well configuration

• Missing sandface-to-wellhead AOF adjustment

• Failure to update release rate after actual test data becomes available

• Failure to compare the final result to Directive 056 section 7.7.4 and Table 4

• Missing support for well classification

• Missing support for ERP or facility level designation

 

The CAPP guideline notes that if actual H₂S concentration or actual AOF creates a greater H₂S release rate than originally used in the well licence, the release rate must be adjusted. It also recommends updating the release rate where test data support a lower value that materially changes emergency response planning, well category, or facility level status.

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Frequently Asked Questions

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What is an H₂S release rate?

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An H₂S release rate is an estimate of the maximum potential surface release rate of hydrogen sulphide from a well. It is calculated using the maximum H₂S concentration and the maximum wellhead AOF.

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What is the basic H₂S release rate formula?

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H₂S Release Rate = AOF × H₂S% × 0.01 / 86,400

Where AOF is in m³/d and the result is in m³/s.

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What is AOF?

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AOF means absolute open flow potential. In the H₂S release rate context, AOF refers to the maximum flow capability used to estimate the potential release rate.

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Does the H₂S concentration and AOF need to come from the same well?

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No. The CAPP guideline states that the paired data points need not be from the same well. The maximum H₂S content and AOF rate are determined by geological and engineering review of available data.

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What operating cases need to be considered?

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The main cases are drilling, completion/servicing, and producing operations. Separate release rate estimates may be needed for each applicable case.

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How many H₂S samples are required?

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The guideline recommends a minimum of five representative H₂S samples for each potentially sour zone, where available. For wells outside an existing pool, the search area should generally extend a minimum of five kilometres from the proposed well location.

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Can a formation be excluded if there is no H₂S data?

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Not simply because there is no sour data. The guideline states that a potentially sour formation should be excluded only if there is data to prove that it is sweet.

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How does H₂S release rate affect well classification?

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After calculating the H₂S release rate, the result should be compared against AER Directive 056 section 7.7.4 and Table 4 to determine the applicable well classification and related emergency planning or drilling requirements.

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Why does wellhead-on versus wellhead-off matter?

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A wellhead-on scenario may produce a lower release rate because flow is restricted through tubing or other equipment. A wellhead-off scenario may produce a higher release rate because flow may occur through casing or open wellbore. If the wellhead-off case results in a more severe classification, design and ERP implications should be considered.

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When should an H₂S release rate be updated?

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The release rate should be updated when actual well test data, H₂S concentration, AOF, completion configuration, producing configuration, or reservoir conditions support a materially different release rate than the one used in the original well licence.

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Related Technical Tools

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Related technical tools may include:

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• H₂S Release Rate Calculator

 

Need Assistance?

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H₂S release rate assessments require both geological and engineering judgment. The final number affects well licensing, well classification, EPZ size, emergency response planning, facility level designation, and sour well design considerations. Benoit Regulatory can help operators prepare H₂S release rate assessments, review offset data, support Directive 056 well classifications, update release rates after testing, and respond to regulator questions.

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