Step Rate Testing and Maximum Wellhead Injection Pressure (MWHIP)

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Overview

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A step rate test is used to evaluate injectivity and help determine the maximum wellhead injection pressure, or MWHIP, for an injection or disposal well.

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MWHIP is the maximum pressure that may be applied at the wellhead during injection operations. It is an important operating limit because it helps ensure that injection can occur without unintentionally fracturing the formation, compromising containment, or creating a migration pathway outside the approved injection or disposal interval.

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In Alberta, AER Directive 065, Appendix O identifies step rate testing as a common method for determining MWHIP. Where valid step rate test data or reliable analogous data are not available, Directive 065 provides default depth-based MWHIP values.

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Approval Types

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Step rate testing and MWHIP analysis may be required or used to support several types of injection and disposal approvals, including:

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• Enhanced oil recovery schemes

• Waterflood injection schemes

• Pressure maintenance schemes

• Disposal wells

• Acid gas disposal wells

• CO₂ injection or sequestration wells

• Injection or disposal scheme amendments

• Applications requesting MWHIP above default values

 

There is an important difference between Alberta EOR schemes and Alberta disposal schemes.

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For Alberta EOR schemes, wellhead pressure data does not need to be converted to sandface conditions to determine MWHIP. The requested MWHIP may be based on Directive 065 Appendix O default values, a conclusive step rate or in-situ stress test, reliable analogous data, or an 8 × TVD basis where accepted by the regulator. The Directive 065 enhanced recovery form specifically includes an 8 × TVD option for requested MWHIP.

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For Alberta disposal schemes, wellhead pressure data should be converted to sandface or bottomhole conditions before determining fracture or parting pressure. The allowable sandface pressure is then converted back to the corresponding MWHIP.

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Application Process

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A practical MWHIP review generally follows this process:

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1. Confirm the jurisdiction.

2. Confirm whether the project is EOR, disposal, waterflood, acid gas, CO₂, or another injection type.

3. Confirm the top of the injection or disposal interval in m TVD.

4. Confirm the fluid type and fluid gradient.

5. Confirm tubing, packer, casing, and perforation configuration.

6. Determine whether valid step rate, in-situ stress, DFIT, mini-frac, or offset data are available.

7. For Alberta EOR, determine whether the MWHIP basis is Appendix O, test-supported, analogous, or 8 × TVD.

8. For Alberta disposal, convert wellhead pressure to sandface pressure before interpreting fracture or parting pressure.

9. For BC, calculate bottomhole fracture pressure, apply the 0.9 safety factor, subtract hydrostatic pressure, and add friction.

10. For Saskatchewan, apply the PNG008 formula using either measured fracture pressure or the default 18.1 kPa/m basis.

11. Compare the result against applicable default or jurisdiction-specific values.

12. Document assumptions, inputs, plots, pressure conversions, and final recommendation.

 

A typical step rate test includes:

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1. Stabilize the well before testing.

2. Establish an initial injection rate.

3. Use a first step long enough to overcome wellbore storage.

4. Increase injection rate in successive steps.

5. Record pressure, rate, and elapsed time for each step.

6. Plot pressure versus injection rate.

7. Identify the point where the pressure-rate trend changes.

8. Use that point to estimate fracture or parting pressure.

 

Directive 065 Appendix O indicates that at least five rate steps should be used and that at least two pressure-rate points above fracture pressure are needed to confirm that fracture pressure has been exceeded.

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Data Requirements

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A complete MWHIP or step rate test review should include:

• Well name and UWI

• Approval or application type

• Injection or disposal zone

• Top and base of the injection or disposal interval

• Perforation interval

• TVD reference used for calculations

• Tubing size and configuration

• Packer depth

• Casing details

• Fluid type

• Fluid density or gradient

• Initial reservoir pressure, where available

• Initial shut-in pressure

• Injection rate for each step

• Wellhead pressure for each step

• Downhole pressure, if measured

• Continuous pressure data, if available

• Continuous injection rate data, if available

• Step duration

• Friction loss assumptions

• Hydrostatic pressure correction

• Sandface pressure calculation, where applicable

• Pressure-rate plot

• Interpreted fracture or parting pressure

• Safety factor

• Recommended MWHIP

 

For Alberta disposal applications, if wellhead pressure data are used, the analysis should clearly show the conversion to sandface pressure before determining fracture or parting pressure.

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Geological Requirements

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The geological review should confirm that the proposed injection or disposal interval is suitable for the requested pressure.Typical geological considerations include:

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• Formation name

• Top and base of the injection or disposal zone

• Depth to top perforation

• Reservoir continuity

• Confinement above and below the injection interval

• Offset well review

• Faults or fractures, where applicable

• Existing production or injection history

• Available fracture pressure, DFIT, mini-frac, or step rate data

• Reliable analogous offset data, where used

 

For disposal schemes, the geological review is especially important because the MWHIP must support containment of the injected fluid within the approved disposal interval.

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Engineering Requirements

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Engineering requirements focus on converting test data into a defensible pressure limit.

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• Alberta EOR MWHIP Calculation

 

For Alberta EOR schemes, the regulator may accept an 8 × TVD basis.

MWHIP = 8 × TVD of the injection perforations

 

Example:

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Injection perforation TVD = 1,500 m

MWHIP = 8 × 1,500

MWHIP = 12,000 kPag

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• Alberta Disposal Sandface Calculation

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For Alberta disposal schemes, the pressure acting on the formation should be calculated at sandface conditions.

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Sandface pressure = wellhead pressure + hydrostatic pressure − friction loss

Hydrostatic pressure = fluid gradient × TVD to injection interval

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Once the formation fracture or parting pressure is determined at sandface conditions:

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Allowable sandface pressure = fracture pressure × safety factor

If a 10% safety factor is used:

Allowable sandface pressure = fracture pressure × 0.90

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The corresponding MWHIP is:

MWHIP = allowable sandface pressure − hydrostatic pressure + friction loss

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Expanded:

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MWHIP = (fracture pressure × 0.90) − (fluid gradient × TVD) + friction loss

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• Alberta Appendix O Default MWHIP

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In the absence of step rate test data or analogous test data, Directive 065 Appendix O provides default MWHIP values based on depth.

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For intervals shallower than 400 m TVD:

MWHIP = 7.5 × TVD

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For intervals deeper than 2,500 m TVD:

MWHIP = 4.0 × TVD

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The Appendix O table assumes an injected or disposed fluid gradient of 10.52 kPag/m and does not account for friction. If the actual fluid gradient is different, the MWHIP can be adjusted as follows:

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MWHIP revised = MWHIP table + [(10.52 − actual fluid gradient) × TVD]

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Example:

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Appendix O table MWHIP = 4,400 kPag
Actual fluid gradient = 11.00 kPa/m
Top of disposal interval = 1,475 m TVD

MWHIP revised = 4,400 + [(10.52 − 11.00) × 1,475]

MWHIP revised = 4,400 − 708

MWHIP revised = 3,692 kPag

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• British Columbia MWHIP Calculation

 

BCER uses the following formula:

PWellhead = [PISIP × 0.9] − PHyd + PFriction

Where:

PWellhead = maximum wellhead injection pressure
PISIP = bottomhole formation fracture pressure
0.9 = 90% of fracture pressure
PHyd = hydrostatic pressure of the disposal fluid column
PFriction = frictional pressure loss

If fracture pressure is based on a fracture gradient:

PISIP = fracture gradient × TVD to top perforation

Hydrostatic pressure is:

PHyd = disposal fluid gradient × TVD to top perforation

Expanded formula:

PWellhead = [(fracture gradient × TVD) × 0.9] − (fluid gradient × TVD) + friction loss

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Or:

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PWellhead = TVD × [(fracture gradient × 0.9) − fluid gradient] + friction loss

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BCER commonly uses a conservative friction loss value of 200 kPa unless a project-specific friction calculation is provided.

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Example:

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TVD to top perforation = 1,137 m
Fracture gradient = 25 kPa/m
Fluid gradient = 10.5 kPa/m
Friction loss = 200 kPa

PWellhead = [(25 × 1,137) × 0.9] − (10.5 × 1,137) + 200

PWellhead = 25,582.5 − 11,938.5 + 200

PWellhead = 13,844 kPa

Rounded MWHIP = 13,840 kPa

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• Saskatchewan MWHIP Calculation

 

Saskatchewan uses:

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MWHIP = (fracture pressure × 0.9) − fluid hydrostatic pressure

Fluid hydrostatic pressure = TVD × fluid gradient

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Expanded:

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MWHIP = (fracture pressure × 0.9) − (TVD × fluid gradient)

In the absence of local fracture pressure data, Saskatchewan provides:

MWHIP = TVD × (18.1 − fluid gradient)

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Example using produced salt water:

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TVD = 1,500 m
Fluid gradient = 10.5 kPa/m

MWHIP = 1,500 × (18.1 − 10.5)

MWHIP = 1,500 × 7.6

MWHIP = 11,400 kPa

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Regulatory Requirements

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• Alberta

AER Directive 065 Appendix O provides the step rate test procedure and default MWHIP table. Directive 065 indicates that a step rate test should:

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• Start from a stabilized well condition

• Use a first injection period long enough to overcome wellbore storage

• Achieve radial flow conditions

• Use at least five rate steps

• Include at least two pressure-rate points above fracture pressure

• Include continuous pressure and injection data, if recorded

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Directive 065 also notes that step rate test data collected after hydraulic fracture stimulation may be inconclusive and may not be acceptable for determining fracture pressure.

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Directive 065 Appendix O references SPE 16798, “Systematic Design and Analysis of Step-Rate Tests to Determine Formation Parting Pressure.” The paper explains that step rate tests must be designed and interpreted carefully. A simple pressure-versus-rate plot can be misleading if the data are affected by wellbore storage, changing wellbore storage, skin effects, unstable starting conditions, or pre-existing fractures.

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• British Columbia

 

BC uses a bottomhole-to-wellhead pressure calculation. The BCER formula accounts for fracture pressure, a 10% safety factor, hydrostatic pressure, and friction loss. BCER’s example uses a 25 kPa/m fracture gradient, 10.5 kPa/m fluid gradient, and 200 kPa friction loss.

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• Saskatchewan

 

Saskatchewan uses a fracture-pressure-based calculation and provides a default formula where local fracture pressure data are unavailable.

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Stakeholder Engagement

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Step rate testing itself usually does not trigger separate stakeholder engagement. However, the MWHIP result may support an EOR, disposal, acid gas, CO₂, or injection amendment application that may have notification or consultation requirements.

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Stakeholder or offset operator issues may arise where:

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• A higher MWHIP is requested

• Injection may affect offset wells

• The scheme area is being amended

• The disposal or injection interval changes

• There are wellbore integrity concerns in offset wells

• The pressure increase may affect containment or offset operations

 

Where MWHIP is used to support a regulatory application, it should be integrated with the broader application’s notification and stakeholder requirements.

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Common Deficiencies

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Step rate test analysis may be questioned when:

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• The well was not stabilized before testing.

• The first step did not overcome wellbore storage.

• The test did not include enough rate steps.

• The test did not clearly exceed fracture pressure.

• The pressure-rate plot does not show a clear change in slope.

• Continuous pressure and rate data were not provided.

• The well was previously hydraulically fractured.

• Skin changes are mistaken for formation parting.

• Friction losses are ignored.

• Fluid density is incorrect.

• For Alberta disposal schemes, wellhead pressures are not converted to sandface conditions.

• The requested MWHIP does not match the interpreted test result.

• The proposed MWHIP does not include an appropriate safety factor.

 

Frequently Asked Questions

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Do Alberta EOR schemes require wellhead pressures to be converted to sandface pressure?

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No. For Alberta EOR schemes, wellhead pressures do not need to be converted to sandface conditions to determine MWHIP.

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Do Alberta disposal schemes require sandface conversion?

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Yes. For Alberta disposal schemes, if wellhead test data are used, the wellhead pressure should be converted to sandface or bottomhole pressure before determining formation fracture or parting pressure. The allowable sandface pressure is then converted back to MWHIP.

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Can Alberta EOR MWHIP be based on 8 × TVD?

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Yes. For Alberta EOR schemes, the regulator may consider an MWHIP based on 8 × TVD of the injection perforations.

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What happens if there is no step rate test?

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In Alberta, Appendix O Table 1 may be used in the absence of step rate test data or analogous test data. The default table is depth-based and assumes a 10.52 kPag/m fluid gradient.

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What is the BCER MWHIP formula?

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BCER’s formula is:

PWellhead = [PISIP × 0.9] − PHyd + PFriction

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What is the Saskatchewan MWHIP formula?

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Saskatchewan uses:

MWHIP = (fracture pressure × 0.9) − fluid hydrostatic pressure

In the absence of local fracture pressure data:

MWHIP = TVD × (18.1 − fluid gradient)

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Why does SPE 16798 matter?

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SPE 16798 explains why step rate test design and interpretation require more than a simple pressure-versus-rate plot. The paper demonstrates that wellbore storage, changing storage, skin effects, and fractures can distort test interpretation.

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Related Technical Tools

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Benoit Regulatory’s MWHIP tool can be used to:​

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• Adjust MWHIP for actual fluid gradient

• Calculate disposal MWHIP from sandface fracture pressure

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Need Assistance?

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Step rate test interpretation and MWHIP calculations can materially affect approval conditions, injection operations, and regulatory compliance. Benoit Regulatory can assist with step rate test analysis, MWHIP calculations, Alberta Directive 065 applications, BC and Saskatchewan pressure calculations, and regulator responses.