How to practically implement RBI for oil and gas production, gathering, and midstream facilities in the United States.

On November 4, 2020, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued draft guidance on jurisdictional overlap with the Occupational Safety and Health Administration (OSHA) on “Midstream Processing Facilities”. The draft notification document was issued to help clear up where PHMSA’s jurisdiction ends and OHSA’s begins. Up until this announcement, the term “Midstream Processing Facility” has not been defined in any Pipeline Safety Laws or the PHMSA and/or OSHA regulations. While codification is slow, below is a field-ready Mechanical Integrity (MI) Plan based upon AOC’s experience tailored for an oil & gas well field development, covering the full lifecycle covering:

• Drilling & completions
• Facilities and gathering system construction
• Steady-state operations and maintenance

It is structured to align with API RP 75, API 510/570/653, API 580/581, PHMSA (49 CFR Part 192/195 where applicable), and OSHA PSM where triggered.

1. Purpose

Ensure pressure-containing equipment and safety-critical systems remain fit-for-service throughout the asset lifecycle by:

• Preventing loss of primary containment (LOPC)
• Detecting degradation before failure
• Managing risk through disciplined inspection and maintenance
• Providing auditable evidence of asset fitness

Success Criteria

 The MI program is considered effective when:

• No unexpected through-wall failures occur
• Inspection intervals are supported by measured degradation
• Safety-critical devices function on demand
• Deferrals are risk-justified and time-bound
• Field conditions match design assumptions

This plan is structured to align with API RP 75, API 510/570/653, API 580/581, PHMSA (49 CFR Part 192/195 where applicable), and OSHA PSM, where triggered.

Primary goals

The primary goals are threefold:

• Prevention of harm to people.
• Prevention of an environmental release
• Maintain reliable production through the equipment’s life cycle

2. Scope

This MI plan applies to: 

Wells

• Surface casing and production casing
• Tubing strings
• Wellheads and trees
• Annuli
• Artificial lift equipment
• Downhole safety valves (if installed) 

Surface Facilities

•  Two- and three-phase separators
• Heater treaters
• Free-water knockouts
• Compressors and scrubbers
• VRUs
• Flares and relief systems
• Produced water handling equipment
• LACT units

 Pipelines and Flowlines

•  Well laterals
• Infield flowlines
• Trunk lines
• Gas gathering
• Produced water disposal lines

The MI program begins at:

• Bottom of tubing (for well integrity monitoring)
• First block valve downstream of custody transfer to the pipeline

3. Lifecycle MI Strategy

This kind of environment requires front-loaded integrity control because early-life corrosion and erosion are common.

Phase 1 — Drilling and Completions

3.1 Required Engineering Reviews

Before drilling each well (or well type):

• Load case review for the tubing (burst, collapse, tension)
• Triaxial stress check for casing
• Connection rating verification
• Thermal effects review for high-rate wells
• Sand production risk assessment
• Corrosion risk screening

3.2 Materials Selection Requirements

 The minimum expectations are as follows:

Sweet service

• Carbon steel with defined corrosion allowance
• Internal coating where the water cut is expected early

Sour or CO₂ service

• NACE MR0175 compliance
• NACE Hardness limits verified
• Elastomer compatibility checked

 3.3 Design Margins

 Typical minimums (unless justified otherwise):

• Tubing corrosion allowance: ≥ 0.065 in
• Flowline corrosion allowance: ≥ 0.083 in
• PSV back pressure: per ASME/API
• Erosion velocity: ≤ API RP 14E limits (with sand adjustment)

3.4 Construction Quality Assurance

 Critical controls must be in place:

• Certified mill test reports (MTRs) matched to received materials
• Welding procedure qualification (WPS/PQR)
• NDE of critical welds for acceptability
• Proper torque and make-up verification of mechanical joints
• Pressure testing of:
• Casing strings
• Wellhead
• Surface lines

Hold points

• Before cementing
• Before wellhead installation
• Before the first production to the surface line

3.5 Baseline Integrity Verification

Before production into the gathering system, the following must be documented:

• Wellhead pressure test
• Tree function test
• Surface line hydrotest
• Initial annulus pressure survey
• Downhole safety valve test (if installed)

 Pressure Testing Requirements

All tests must include:

• Stabilization period
• Leak check
• Calibrated gauges
• Recorded charts

This documentation establishes the baseline MI record for each well.

Phase 2 — Facilities and Gathering Construction

4. Equipment Design Requirements and Fabrication Controls

 4.1 Pressure Vessel, Tanks,  Requirements

•  All pressure vessels will be designed and fabricated in accordance with ASME Section VIII, Division 1, 2, or 3. All vessels produced for sour service shall conform to NACE MR0175.
• All tanks will be designed and fabricated in accordance with API 650/620/12F and UL 142. All tanks produced for sour service shall conform to NACE MR0175. 
• All surface piping will be designed and fabricated in accordance with ASME B31.3, B31.4, and B31.8.
• All subsurface piping will be designed and fabricated in accordance with API 5L. Both produced for sour service shall conform to NACE MR0175.

4.1.1 Damage Mechanism Review (DMR) (Required Before Fabrication)

 For each equipment type, a DMR must be performed during conceptual design. It must document the damage rate and susceptibility to:

• CO₂ corrosion
• MIC
• Erosion
• Wet H₂S damage
• Amine damage (if applicable)
• Thermal fatigue

This drives:

• Corrosion allowance
• Inspection plan
• Internal coating decisions 

4.1.2 Shop And Field Fabrication QA

No equipment fabrication should be considered unless the process is operated under a documented Quality Management System (QMS). The QMS should document:

• The organizational structure
• The roles and responsibilities
• The document control system
• The fabrication controls

 A fabrication QA specification needs to be documented prior to PQR and should include:

• Fabrication inspection and Test Plan (FITP)
• Material Traceability
• Fit-up inspection
• Welding Procedure Specifications (WPS) and Procedure Qualification Records (PQR)
• Non-Destructive Examination (NDE)
• Hydrotest
• Nameplate verification

The required fabrication quality systems are as follows:

• Pressure Vessels - ASME fabrication program, “U” and “R” stamps
• Tanks - ISO 9001 or equivalent
• Piping - ISO 9001 or equivalent

5. Pre Safety Start Up Review (PSSR)

Before introducing hydrocarbons, a PSSR shall be conducted for the piece of equipment being placed in service. This will be performed by a team of the appropriate engineering, maintenance, operations, and inspection personnel. The three requirements below must be completed:

5.1 Walkdown Verification

 The team will confirm:

• The equipment is installed per design
• The relief devices are installed and set
• The process valves are correctly oriented
• The appropriate piping supports have been installed
• Process piping deadlegs have been minimized

5.2 Safety Critical Devices

The team will perform or observe the functional test of the following:

• PSVs
• ESD valves
• Level shutdowns
• High-pressure shutdowns
• Fire & gas (if present)

5.3 Documentation Completion

After 5.1 and 5.2 are completed, the team will assemble the required documentation and formally approve the installation. This should consist of:

• As-built drawings and installation specifications
• Functional test records
• MI baseline Inspections
• This equipment information is loaded into CMMS

 PSSR Gate: No startup without an approved MI release.

Phase 3 — Early Life Operations (Years 0–2)

This is the highest-risk period for these types of developments.

6. Initial First Time Inspection Strategy

 6.1 Wells

 Frequency

• Annulus pressure: monthly
• Wellhead visual: quarterly
• Tree valve function: annually
• Downhole safety valve: typically 6–12 months

6.2 Flowlines

 Baseline within the first 12 months

• Corrosion monitoring coupons
• UT thickness survey
• Pigging verification
• Leak survey

6.3 Vessels and Tanks

Initial internal inspection timing

• All ASME pressure vessels: 3 years
• All AEME/API piping: 3 years
• All API 650/620/12F and UL 142 Tanks: 5 years

Phase 4 — Steady-State MI Program

7. Risk-Based Inspection (RBI)

Implement the program in accordance with API 580/581.

7.1 Required Elements

•  Collect data
• Damage mechanism review
• Equipment strategy validation
• Inspection effectiveness historical review (if applicable)
• Risk Analysis
• Inspection plan optimization

Note: Inspection credit must reflect real field effectiveness, not theoretical POD. The effectiveness shall be determined from the approved Equipment Strategies.

8. Deficiency Management

8.1 Anomaly Evaluation

All anomalies must be:

1. Documented
2. Evaluated for fitness-for-service
3. Risk-ranked
4. Tracked to closure

Use API 579 Fitness For Service (FFS) analysis where applicable.

8.2 Temporary Repairs

Must include:

• Engineering approval
• A time limit
• An inspection plan
• A permanent repair date

9. Management of Change (MOC)

Required for:

• Pressure changes
• Chemistry changes
• Throughput increases
• Artificial lift conversions
• Tie-ins and reroutes

Note: Production ramp-ups or declines frequently invalidate corrosion assumptions.

10. Data and Digital Infrastructure

10.1 Asset Registry

Each asset/equipment must have:

• Unique ID
• Design conditions
• Materials
• Inspection history
• RBI Analysis
• Inspection plan

10.2 CMMS Integration

Ideally, the RBI software should be integrated with the CMMS, unless the RBI software is used as the CMMS. Regardless the following must be tracked:

• Inspection tasks
• PM tasks
• Anomalies/Deficiencies
• Temporary repairs
• Task deferrals
• Damage mechanisms
• Risk analysis

11. Performance Metrics (KPIs)

Track at minimum:

• % inspections completed on time
• Corrosion rate vs. allowance and estimated
• Safety-critical PM compliance
• Temporary repair aging
• Loss of primary containment (leaks)
• PSV failures
• Unexpected corrosion/damage mechanism discoveries

12. Specific Risk Focus Areas

The high-risk damage mechanisms shown below can cause failures from Phase 3 onward:

• CO₂ corrosion in multiphase lines
• MIC in produced water systems
• Erosion at choke points
• Sand erosion in early-life wells
• Tank bottom corrosion
• Deadlegs from pad buildouts
• Rapid water cut transitions

13. Governance and Oversight

Please see the department responsibilities below:

Engineering

• Damage mechanisms
• RBI
• FFS

Operations

• Field surveillance
• First-line anomaly detection

Inspection

• NDE execution
• Data quality

Management

• Barrier health oversight
• Resource allocation

14. Independent Review

At least every 3–5 years, the following must be independently reviewed:

• RBI damage mechanism validation
• Inspection effectiveness audit
• MI program health assessment

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