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API Publ 2391-2013: Upstream Facility Piping and Pipeline Integrity Management – A Comprehensive Guide
Understanding the scope, technical requirements, and compliance strategies for API Publication 2391
API Publ 2391-2013 (First Edition) provides recommended practices for the integrity management of piping systems and pipelines in upstream oil and gas facilities. Published by the American Petroleum Institute, this publication bridges the gap between general pipeline integrity standards and the unique operational challenges encountered in upstream operations—from wellhead to the first point of processing or custody transfer. This article explores the document’s scope, core technical requirements, implementation insights, and compliance considerations for operators and engineers.
Scope and Applicability
API Publ 2391-2013 specifically addresses the upstream segment (Subsegment 3.2 of API’s classification) and applies to both onshore and offshore facilities. It covers metallic and non-metallic piping and pipelines that handle produced fluids, including oil, gas, condensate, and water. The publication explicitly excludes downstream refinery piping, transportation pipelines (covered by API 1160 or ASME B31.8), and gas distribution systems.
The document adopts a risk-based integrity management framework, emphasizing a systematic process to identify threats, assess risks, and prioritize mitigation actions. It is intended for use by integrity engineers, facility managers, and operations personnel who are responsible for maintaining the mechanical integrity of upstream piping assets.
Important: API Publ 2391 is a guidance publication, not a consensus standard. It does not replace jurisdictional regulations or code requirements. Operators must confirm that their integrity management program meets all applicable legal mandates.
Key Technical Requirements
API Publ 2391 outlines a five‐element integrity management process that forms the backbone of any upstream piping integrity program. The elements are presented as an iterative cycle, encouraging continuous improvement.
Integrity Management Framework
| Element | Description |
|---|---|
| 1. Data Collection & Management | Assemble design, construction, operating, maintenance, inspection, and incident history data. Organize in a retrievable format (e.g., database). |
| 2. Threat Identification & Risk Assessment | Identify credible threats (e.g., internal/external corrosion, erosion, mechanical damage, stress‑corrosion cracking). Conduct qualitative or quantitative risk assessment considering likelihood and consequences. |
| 3. Inspection & Monitoring | Develop risk‑based inspection plans. Select appropriate NDE methods (UT, RT, MFL, guided wave) at intervals based on threat mechanisms and risk level. |
| 4. Mitigation & Repair | Implement mitigation measures (e.g., chemical treatment, cathodic protection, flow assurance) and repair criteria. Follow API 570 or other applicable acceptance standards. |
| 5. Performance Monitoring & Review | Track key performance indicators (KPIs) such as failure rates, inspection coverage, and repair timeliness. Review program annually and update risk models periodically. |
The publication provides detailed guidance on each element, including sample risk‑assessment matrices, inspection frequency tables, and recommended mitigation actions for common threats like corrosion under insulation (CUI) and microbial‑influenced corrosion (MIC).
Tip: When developing the threat identification step, engage cross‑functional teams (operations, corrosion, inspection, process safety) to capture all plausible failure mechanisms. A bowtie analysis can help visualize barriers and consequences.
Implementation Highlights
Putting API Publ 2391 into practice involves more than simply documenting the five elements. Successful implementation requires organizational commitment, clear roles and responsibilities, and integration with existing management systems (e.g., ISO 55000, SMS, or PSM).
Risk‑Based Inspection (RBI) Deployment
The publication strongly encourages RBI to optimize inspection frequency and method. Operators should initially classify all piping circuits and pipelines into risk categories. High‑risk circuits may require detailed fitness‑for‑service (FFS) assessments per API 579‑1/ASME FFS‑1. Low‑risk circuits can be managed with reduced inspection.
Data Integrity and Traceability
API Publ 2391 emphasizes the importance of accurate data. Inconsistent or incomplete data leads to poor risk decisions. Operators should establish data governance procedures, including validation rules for inspection reports and corrosion monitoring logs.
Implementation Success Factor: Start with a pilot program on a representative facility. Document lessons learned, then scale to other assets. This approach builds confidence and demonstrates value to management.
Management of Change (MOC)
Any change in feed composition, operating conditions, or equipment must trigger a review of the integrity management program. The publication outlines a simplified MOC process tailored for upstream piping systems, including a threat screening checklist.
Compliance and Auditing Considerations
Because API Publ 2391 is a guidance document, compliance is often measured against self‑defined program commitments and regulatory expectations. However, many regulatory bodies (e.g., BSEE, BOEM, and some state agencies) incorporate the publication by reference or expect operators to follow a “recognized and generally accepted good engineering practice” (RAGAGEP), which API Publ 2391 satisfies.
Audit Readiness
To demonstrate compliance, operators should maintain:
- a written integrity management plan referenced to API Publ 2391;
- inspection and mitigation records with traceability to risk assessments;
- training records showing personnel competency in the publication’s processes;
- documented annual reviews with management sign‑off.
Common Gap: Many operators fail to close the performance monitoring loop. Without trending KPIs and conducting periodic risk model updates, the integrity program becomes a static document rather than a living process. Ensure your audit schedule includes a review of performance data and corrective actions.
Operators across jurisdictions—from the Gulf of Mexico to the North Sea—have adopted API Publ 2391 as their internal standard. Its risk‑based, systematic approach aligns well with modern process safety frameworks (e.g., CCPS RBPS) and supports both regulatory compliance and operational excellence.
Frequently Asked Questions
Q: Is API Publ 2391 mandatory for upstream operators?
A: No, it is a recommended practice publication, not a mandatory standard. However, many regulators and company policies require operators to follow a RAGAGEP, and API Publ 2391 is often cited as such. Check your local jurisdiction for specific references.
A: No, it is a recommended practice publication, not a mandatory standard. However, many regulators and company policies require operators to follow a RAGAGEP, and API Publ 2391 is often cited as such. Check your local jurisdiction for specific references.
Q: How does API Publ 2391 relate to API 570?
A: API 570 covers inspection, repair, and alteration of in‑service piping systems primarily in downstream and process industries. API Publ 2391 is tailored for upstream upstream piping systems, including pipelines within a facility boundary. Both use risk‑based principles, but API Publ 2391 addresses upstream‑specific threats like erosion due to sand production and gas hydrate blockages.
A: API 570 covers inspection, repair, and alteration of in‑service piping systems primarily in downstream and process industries. API Publ 2391 is tailored for upstream upstream piping systems, including pipelines within a facility boundary. Both use risk‑based principles, but API Publ 2391 addresses upstream‑specific threats like erosion due to sand production and gas hydrate blockages.
Q: Does the publication cover integrity of well tubing or flowlines?
A: The scope includes flowlines from the wellhead to the first separator or manifold, as well as facility piping. Well tubing (downhole) is excluded; it is typically managed under separate well integrity programs (e.g., API 14B/14C or ISO 16530).
A: The scope includes flowlines from the wellhead to the first separator or manifold, as well as facility piping. Well tubing (downhole) is excluded; it is typically managed under separate well integrity programs (e.g., API 14B/14C or ISO 16530).
Q: Can non‑metallic piping be managed using this publication?
A: Yes. Appendix B of API Publ 2391 provides additional guidance on non‑metallic piping integrity, covering threats such as permeation, fiber degradation, and quality assurance during installation.
A: Yes. Appendix B of API Publ 2391 provides additional guidance on non‑metallic piping integrity, covering threats such as permeation, fiber degradation, and quality assurance during installation.
Last updated: 2026