Pipeline construction has the tightest pipeline MTC requirements in the metals industry. The combination of long-distance transport of hazardous fluids, remote installation conditions, regulatory oversight across multiple jurisdictions, and the catastrophic consequence of a failure means that linepipe documentation requirements are detailed, specific, and systematically enforced.
A gap that would result in a hold notice on a general fabrication project — a missing Charpy test temperature, an absent heat number stencil — can stop spool fabrication entirely on a pipeline project, because the downstream consequences of non-conforming pipe in a buried or subsea pipeline are so severe that no inspection authority will approve a waiver without comprehensive retesting.
This guide covers the complete documentation requirements for pipeline linepipe MTCs under the standards that pipeline projects encounter most: API 5L for onshore and offshore production, DNV-ST-F101 for subsea applications, and ASME B31.8 for gas transmission systems. It also covers the specific issues that arise for sour-service lines and for material sourced through distributors rather than direct from the mill.
API 5L: The Foundation of Pipeline Linepipe Certification
API 5L (Specification for Line Pipe) is the globally dominant product specification for steel pipe for pipeline service. It is used as the procurement specification for the vast majority of onshore and offshore pipelines worldwide, including all ASME B31.8 (Gas Transmission) and most ASME B31.4 (Liquid Transportation) applications.
API 5L defines two Product Specification Levels with meaningfully different MTC requirements:
PSL 1 is the basic commercial specification. The MTC must document: heat chemical analysis (C, Mn, P, S, minimum), outside diameter and wall thickness, yield strength, tensile strength, and elongation. CVN impact testing is not required under PSL 1 unless specifically ordered. PSL 1 is appropriate for mild-service onshore pipelines in non-sour, relatively low-consequence environments.
PSL 2 is mandatory for offshore pipelines, sour-service lines, high-pressure transmission pipelines, and any application where a higher level of quality assurance is specified. PSL 2 adds: full chemistry (15+ elements), carbon equivalent (both IIW CE and Pcm formulas for applicable grades), Charpy V-notch impact testing at the specified temperature, Drop-Weight Tear Test (DWTT) for grades X52 and above in pipe ≥ 19.1mm wall, hydrostatic pressure test, and NDE method documentation. For sour-service grades (X52MS through X80MS), HIC and SSC test results are additionally required.
PSL 2 Mandatory MTC Data Fields: The Complete List
For an API 5L PSL 2 MTC to be technically complete, every one of the following fields must be present and within specification:
Chemical Analysis:
- Carbon (C) — by heat and product analysis
- Manganese (Mn)
- Phosphorus (P) — note sour grades require ≤ 0.020%
- Sulfur (S) — note sour grades require ≤ 0.003%
- Silicon (Si)
- Niobium (Nb), Vanadium (V), Titanium (Ti) — all three, not just those present in measurable quantities
- Copper (Cu), Nickel (Ni), Chromium (Cr), Molybdenum (Mo), Boron (B), Aluminum (Al), Nitrogen (N)
Carbon Equivalent Formulas:
- CE (IIW formula): C + Mn/6 + (Cr+Mo+V)/5 + (Ni+Cu)/15
- Pcm (Ito-Bessyo): C + Si/30 + (Mn+Cu+Cr)/20 + Ni/60 + Mo/15 + V/10 + 5B
- Both must appear for grades where Pcm is the controlling weldability parameter (typically higher-strength grades X60 and above in sour service)
Mechanical Properties:
- Specified Minimum Yield Strength (SMYS) — actual yield, both 0.5% EUT method and 0.2% offset where applicable
- Ultimate Tensile Strength (UTS) — actual value; yield-to-tensile ratio must not exceed 0.93 for PSL 2
- Elongation — minimum 21% for PSL 2 (grade-dependent)
Charpy V-Notch Impact Testing:
- Average absorbed energy (required) and individual specimen values
- Test temperature — must match the minimum design temperature of the pipeline
- Specimen size and orientation (transverse to pipe axis for body specimens; longitudinal for weld specimens on SAW pipe)
- Location tested: pipe body (at 12, 3, or 9 o'clock position per API 5L)
- For submerged arc welded (SAW) pipe: separate CVN results for weld metal, HAZ, and base metal
Drop-Weight Tear Test (DWTT):
- Required for grades X52 and above when wall thickness ≥ 19.1 mm (0.750 in)
- Shear area percentage at the specified test temperature
- Must meet minimum shear area per API 5L Table E.8 (typically 85% minimum average)
Dimensional and Manufacturing:
- Outside diameter (OD) and wall thickness (WT) at measured locations
- Pipe length
- Pipe category (seamless / EW / SAW / DSAW / LSAW)
- Seam weld NDE method and acceptance standard (for welded pipe)
Hydrostatic Test:
- Test pressure and test duration
- Leakage: none
DNV-ST-F101 Subsea Pipeline Traceability Requirements
For offshore and subsea pipelines certified under DNV class, DNV-ST-F101 (Submarine Pipeline Systems) adds traceability requirements on top of API 5L.
Mill qualification. The pipe mill must be pre-qualified per DNV-ST-F101 Annex A before project pipe can be ordered. Mill qualification includes an audit of the mill's quality management system and a qualification pipe order with third-party witnessed testing. A mill that is not pre-qualified cannot supply DNV-approved pipe regardless of how complete the MTC is.
EN 10204 certificate type. DNV-ST-F101 requires EN 10204 3.2 with DNV surveyor co-signature for all linepipe. The MTC must carry two signatures: the mill's authorized QA representative and the DNV surveyor who witnessed the testing. A document with only the mill signature — even if labeled 3.2 — is not compliant.
Heat number chain continuity. DNV requires that the heat number be traceable from the original steel heat through: coil or plate manufacture (for ERW or SAW pipe), pipe forming and welding, coating (if applicable), and onto the finished pipe body marking. Any point in this chain where the heat number cannot be confirmed requires the pipe to be re-identified by PMI or re-marked under witnessed conditions.
Post-weld NDE on SAW and DSAW pipe. The weld seam of submerged arc welded pipe must be 100% examined by UT (and optionally RT). Results must be documented with examiner qualifications, calibration standard, and acceptance criteria per DNV-ST-F101 Annex C.
ASME B31.8 Gas Transmission Pipeline Documentation
ASME B31.8 covers design, fabrication, installation, inspection, and testing of gas transmission pipelines. For material used in ASME B31.8 systems, the MTC requirements flow from API 5L (which B31.8 directly references for linepipe material) plus B31.8's own traceability provisions.
ASME B31.8 Para 805.3 requires that records be maintained to demonstrate that material was procured, installed, and tested in accordance with the applicable specification. For Class 1 and 2 location pipelines in non-sour service, PSL 1 certificates with basic chemistry and mechanical data satisfy this requirement. For Class 3 and 4 location pipelines (higher population density, higher consequence), and for any sour-service or high-consequence area (HCA) designation, more rigorous documentation is expected by regulators and pipeline operators.
For US pipelines subject to DOT 49 CFR Part 192 (gas) or 49 CFR Part 195 (liquids), the operator must maintain records that support the maximum allowable operating pressure (MAOP) calculation. For new pipelines, the MTC is part of this record. For legacy pipelines with missing records, 49 CFR requires pressure testing to a specific test factor as a substitute for missing material records — which is expensive and disruptive compared to simply maintaining MTCs through the pipeline's life.
Sour Service and HIC Testing Requirements
For pipelines transporting fluids with H2S above the sour service threshold (H2S partial pressure > 0.05 psia / 0.3 kPaa), NACE MR0175 / ISO 15156 governs the material requirements, and the MTC must document:
- Sulfur content ≤ 0.003% (verified by product analysis, not just heat analysis)
- Carbon equivalent (Pcm formula) — value and result documented
- Hardness ≤ 22 HRC for carbon steel pipe body (248 HV10 / 237 HB)
- HIC test results per NACE TM0284: Crack Length Ratio (CLR), Crack Thickness Ratio (CTR), and Crack Sensitivity Ratio (CSR) for each test coupon at specified acceptance criteria
- SSC test results per NACE TM0177 Method A where required by the engineering specification
HIC test results are often provided on a supplementary test report rather than the main MTC document. The supplementary report must be formally attached to or referenced on the MTC with a cross-reference to the heat number and pipe order number. A PSL2 MTC for a sour-service grade that does not include or reference HIC results is incomplete — the chemistry values and mechanical properties alone do not establish sour service suitability.
Distributor-Sourced Pipe: The Chain-of-Custody Problem
On many pipeline projects, pipe is sourced through distributors or traders rather than direct from the mill. This creates a chain-of-custody documentation challenge that becomes acute when the project requires EN 10204 3.2 certificates or when the distributor has split a heat lot across multiple deliveries.
EN 10204 does not provide a mechanism for a distributor to re-issue or re-certify mill certificates. The original mill certificate is the only valid EN 10204 document for the heat. When a distributor ships a subset of a pipe order — say 30 pipes from a 100-pipe heat lot — they must provide a copy of the original mill certificate plus a delivery/material traceability record that documents the quantity and pipe numbers allocated to the specific delivery. The delivery record is not an EN 10204 document; it is a supplementary traceability record. Both are needed.
If the distributor issues its own certificate in place of the original mill certificate — particularly if labeled with its own company name and signed by its own staff — this is not a valid EN 10204 certificate, regardless of what it says. The DNV surveyor, the Notified Body, and the ASME Authorized Inspector will all reject it.
How TestCert Addresses Pipeline MTC Complexity
Pipeline MTC review is demanding because the field list is long (15+ chemistry elements plus CE and Pcm formulas), the validation is grade-specific (X65 has different limits than X52), the supplementary data fields (HIC results, DWTT, SAW weld NDE) are often in separate documents that must be formally linked, and the EN 10204 type requirement adds a co-signature verification step.
TestCert handles API 5L PSL2 validation natively — extracting all 15+ chemistry elements, both CE formulas, CVN average and individual values, DWTT shear area, and hydrostatic test pressure from each MTC regardless of mill format or language. Chemistry values are compared against the PSL2 grade table automatically, and the Pcm calculation is verified independently if only individual element values are present. For sour-service grades, the system prompts for the HIC supplementary test report reference if it is not already attached.
EN 10204 type verification — confirming that a claimed 3.2 document carries both the mill QA signature and a recognizable third-party body co-signature — is a built-in validation step. Certificates that carry only one signature despite a 3.2 claim are flagged for review before any pipe enters the weld queue.
The complete pipeline MTC package — original API 5L certificate, HIC supplement, DWTT report, SAW NDE report, hydrostatic test record, and EN 10204 type verification — is stored as a linked set, retrievable by heat number in seconds when the DNV surveyor or client inspector asks. Book a demo to see pipeline MTC verification in TestCert at testcert.io.