API Specification 17D Explained: Subsea Wellhead and Tree Equipment

Illustrative image only: a generic subsea tree and ROV scene, not an API figure and not a proprietary equipment drawing.

Imagine a machine sitting in darkness on the seabed, deeper than any human diver can safely reach. It has to hold back reservoir pressure, guide tools into a live well, let a remote vehicle operate valves, survive seawater for years, and still be testable before it leaves the factory. API Specification 17D is the rulebook that tries to make that possible.

API Specification 17D is the API standard for subsea wellhead and subsea tree equipment. In simple language, it explains how subsea wellheads, mudline wellheads, drill-through mudline systems, vertical trees, horizontal trees, tubing hangers, connectors, valves, chokes, and associated tools should be designed, validated, manufactured, factory tested, marked, preserved, and shipped before offshore use. Cross reference: API 17D, Section 1 and Section 4.1.

This article is an original engineering explanation. It does not reproduce API's protected tables, figures, or standard text. Use it as a map, not as the legal or technical source of record. For design, procurement, inspection, FAT, or project acceptance, always verify every requirement in the official licensed copy of API Specification 17D and the project specification.

The one-minute picture

If you are new to subsea equipment, start with this mental model: a subsea wellhead is the structural and pressure foundation at the top of the well; a subsea tree is the valve and connection assembly installed above it to control production, injection, annulus access, monitoring, and intervention interfaces. API 17D sits at the point where pressure containment, remote operation, material selection, test evidence, and factory quality all meet.

Question	Plain answer	API 17D cross reference
What is API 17D for?	It specifies requirements for new subsea wellhead, mudline wellhead, subsea tree, tubing hanger, connector, valve, choke, and related tooling equipment.	Section 1; Section 4.1
Is it only a pressure-test standard?	No. It covers design, materials, welding, validation, quality control, FAT, marking, storage, and shipping.	Section 1; Sections 5.1 to 5.6
Does it cover the whole subsea production system?	No. It excludes many adjacent systems such as control modules, manifolds, jumpers, risers, WCPs, and subsea test trees.	Section 4.1
What is the main pressure-test rule?	For many pressure-containing items, hydrostatic body testing is at minimum 1.5 x RWP, but equipment-specific clauses and Table 6 must be checked.	Section 5.4.5.1; Table 6; Sections 6 to 11

Purpose of API Specification 17D

The purpose of API 17D is to create a common technical baseline for subsea wellhead and tree equipment. It tells the manufacturer what has to be demonstrated, tells the purchaser what has to be specified, and gives inspectors a way to check that the equipment has been built and factory tested to the right level before it is sent offshore. Cross reference: API 17D, Section 1.

That last phrase, before it is sent offshore, is important. API 17D is mainly a new-equipment manufacturing and factory acceptance specification. It does not cover repair or rework of used equipment, in-situ testing, or system integration testing. Those activities normally need separate procedures, project requirements, and other applicable standards. Cross reference: API 17D, Section 1.

The standard also helps define technical boundaries. A subsea tree may connect to a flowline, a control system, an intervention package, a jumper, or a protective structure, but API 17D is not automatically the governing document for all of those. API 17D refers to other standards where those interfaces belong elsewhere. Cross reference: API 17D, Section 2 and Section 4.1.

Which subsea equipment refers to API 17D?

API 17D is used whenever a project is procuring, qualifying, or reviewing subsea wellhead and tree equipment within its scope. The standard lists the equipment directly, including eligible PSL levels where applicable. Cross reference: API 17D, Section 4.1.

Subsea tree equipment

For subsea trees, API 17D covers the tree assembly and many tree-related components: tree and tubing head connectors, valves and valve blocks, chokes, hydraulic or electric actuators/operators, underwater safety valves, tree caps, crown plugs, tree piping, tree frames, completion guidebases, tree running tools, tree cap running tools, and tubing heads. Cross reference: API 17D, Section 4.1(a), Section 6, and Section 7.

Subsea wellhead equipment

For subsea wellheads, API 17D covers conductor or low-pressure housings, high-pressure wellhead housings, casing hangers, submudline casing hangers, annulus seal assemblies, submudline annulus seal assemblies, casing hanger lockdown bushings, guidebases, bore protectors, wear bushings, and corrosion caps. Cross reference: API 17D, Section 4.1(b) and Section 8.

Mudline and drill-through mudline equipment

The standard also covers mudline suspension systems and drill-through mudline systems. This includes landing rings, casing hangers, running tools, tieback tools, subsea completion adaptors, mudline tubing heads, external and internal casing hangers, drill-through casing hanger housings, annulus seal assemblies, bore protectors, and wear bushings. Cross reference: API 17D, Section 4.1(c), Section 4.1(d), Section 10, Section 11, Annex E, and Annex M.

Tubing hanger systems

Tubing hangers and tubing hanger running tools are also covered. In a horizontal tree, crown plugs and internal tree cap interfaces become especially important because they act as pressure barriers in the tree/tubing-hanger system. Cross reference: API 17D, Section 4.1(e), Section 9, and Annex L.

What API 17D does not cover

A common mistake is to stretch API 17D across the entire subsea field architecture. The standard specifically excludes subsea well control packages, subsea test trees, production risers, intervention riser systems, control systems and control modules, platform tiebacks, protective structures, subsea process equipment, manifolds, jumpers, jumper connectors, subsea wellhead tools, template structures, and subsea manifold piping. Cross reference: API 17D, Section 4.1.

That means an engineer should ask two questions before using API 17D: first, is the item actually in the API 17D scope; second, is the clause being used the right clause for that equipment type? A flowline connector, for example, can sit physically near the tree, but the connector side, piping-code side, and API 17R side need to be separated correctly. Cross reference: API 17D, Section 7.16 and Section 7.17.

Illustrative image only: API 17D equipment is designed to be operated, inspected, tested, and sometimes recovered by remote tooling and ROV support.

The engineering logic behind the standard

API 17D should not be read as a list of isolated numbers. Its logic is more like a chain. First define the service, then select pressure rating, temperature class, material class, sour service requirement, PSL, water-depth requirements, and project loads. Then verify the design, validate the product family, manufacture it under controlled quality requirements, perform FAT on the shipped item, mark it correctly, and preserve it for storage and shipment. Cross reference: API 17D, Section 4 and Section 5.

The standard pressure ratings for most API 17D equipment are 5000 psi, 10000 psi, and 15000 psi. The chosen standard pressure rating is normally the rated working pressure, or RWP, used for testing. Small-bore line ratings, mudline equipment, drill-through equipment, and HPHT equipment may have special treatment. Cross reference: API 17D, Section 5.1.2.1, Table 2, Section 10, Section 11, Annex D, and Annex E.

Pressure in API 17D is gauge pressure. This sounds simple, but it matters when reviewing pressure charts, test reports, hydrostatic head corrections, and project datasheets. Cross reference: API 17D, Section 4.2.1.

PSL: why the level matters

Product Specification Level, or PSL, is one of the main quality levers in API 17D. Pressure-containing and pressure-controlling components are normally manufactured to PSL 2, PSL 3, or PSL 3G. PSL 3G is not just a label; it means PSL 3 plus additional gas testing. Cross reference: API 17D, Section 4.3, Section 5.4.2, and Section 5.4.6.

The PSL of an assembled wellhead or tree system is controlled by the lowest PSL of the pressure-containing or pressure-controlling components in that assembly. In simple words, a chain is not stronger than its weakest pressure-boundary link. Cross reference: API 17D, Section 4.3.

Annex B gives practical purchasing guidance for PSL selection. It points the user/purchaser toward PSL 2 for some lower-pressure general service cases, PSL 3 for higher-pressure or sour primary equipment, PSL 3G for gas-producing, high gas-oil ratio, or gas-injection service, and PSL 4S for HPHT equipment under Annex D. Cross reference: API 17D, Annex B.

Materials and sour service

API 17D expects the user/purchaser to define materials for pressure-containing and pressure-controlling equipment. The material class is not just a procurement preference; it affects compatibility with retained fluids, sour service, corrosion resistance, marking, and traceability. Cross reference: API 17D, Section 4.2.3, Section 5.1.1.4, and Table 1.

Material classes AA through HH are used for different service conditions and corrosion severity. Sour service classes are tied to NACE MR0175/ISO 15156 requirements. If the fluid environment or material choice falls outside the normal class rules, material class ZZ may be used with user/purchaser-approved material specifications and traceable records. Cross reference: API 17D, Section 4.2.3 and Section 5.1.1.4.

One subtle but important point: all wellbore-wetted pressure-containing components are treated as bodies for material trim selection, while metal seals are treated as pressure-controlling parts. That affects how trim tables, CRA overlays, seal materials, and manufacturing records should be reviewed. Cross reference: API 17D, Section 5.1.1.4 and Table 1.

Design validation versus FAT

API 17D separates design validation from factory acceptance testing. Validation proves that the design or product family can meet its intended pressure, temperature, load, endurance, and functional requirements. FAT proves that the actual shipped item was assembled, operated, inspected, and pressure tested where required. Cross reference: API 17D, Section 5.1.7 and Section 5.4.

Validation uses representative test articles. If a design changes in a way that could affect performance, the manufacturer has to document the effect of the change and explain whether revalidation is required. Cross reference: API 17D, Section 5.1.7.2.

Table 5 is the validation map. It covers pressure/load cycling, temperature cycling, and endurance cycling for seals, connectors, valves, actuators, chokes, tubing hangers, casing hangers, annulus seal assemblies, running tools, and other items. Cross reference: API 17D, Section 5.1.7 and Table 5.

For validation pressure-hold periods on pressure-containing and pressure-controlling equipment, gas test media is generally required. Hydrostatic body pressure testing of validation test equipment is performed first using liquid at ambient temperature. Cross reference: API 17D, Section 5.1.7.3.

Barrier philosophy in a subsea tree

A subsea tree is not just a bundle of valves. It is a pressure-barrier system arranged so that production, injection, annulus access, intervention, control lines, chemical injection, and monitoring can be managed safely. API 17D makes the engineer think about which bore is being protected, which penetration is being introduced, and which closures are testable and fail-closed. Cross reference: API 17D, Section 6.2.

Vertical trees require one or more master valves in the production or injection bore and in the annulus access bore where applicable. At least one valve in each bore must be actuated fail-closed. Horizontal trees have corresponding requirements for production/injection and annulus paths. Cross reference: API 17D, Section 6.2.1 and Section 6.2.2.

For any penetration leading into the production path of the tree or tubing head, API 17D requires at least two fail-closed pressure closures, with one of them actuated fail-closed. For annulus-path penetrations, at least one testable pressure closure is required between the wellhead and the penetration. Cross reference: API 17D, Section 6.2.9.

SCSSV control-line penetrations receive special attention because trapped hydraulic pressure can keep a downhole safety valve open when it should close. API 17D requires pressure-controlling closure at those penetrations and prohibits check valves in the SCSSV circuit where their closure could prevent venting down control pressure. Cross reference: API 17D, Section 6.2.10.

Chemical injection lines through the tubing hanger require two fail-closed barriers, with at least one actuated fail-closed valve. Monitoring and test lines require pressure-controlling closures, and lines that may communicate with wellbore pressure need matching pressure-rating logic. Cross reference: API 17D, Section 6.2.11 and Section 6.2.12.

API 17D also forces a simple but powerful question: can pressure become trapped? Trapped fluid volumes, tree caps, chokes, hydraulic lock, control stabs, and test/vent/gauge fittings must be designed so pressure can be managed and safely vented. Cross reference: API 17D, Section 5.1.4.4, Section 6.3, Section 7.12.3.2, Section 7.19.2.9, and Section 7.20.2.2.6.

Pressure testing requirements in simple language

The general hydrostatic pressure-test rule is found in Section 5.4.5.1. For equipment in Sections 6 through 11, hydrostatic pressure testing follows API 6A PSL 2, PSL 3, or PSL 3G requirements unless API 17D gives a specific addition, exception, or modification. Cross reference: API 17D, Section 5.4.5.1.

For all pressure ratings, the hydrostatic body test pressure is minimum 1.5 x RWP. The hydrostatic seat test pressure is minimum 1.0 x RWP. The acceptance criterion is no visible leakage during the hold period. Cross reference: API 17D, Section 5.4.5.1.

The final settling pressure cannot be below the specified test pressure at the end of the hold period. Initial test pressure cannot exceed the specified test pressure by more than 5 percent. Hydrostatic pressure testing is performed at ambient temperature. Cross reference: API 17D, Section 5.4.5.1.

During a pressure hold, the pressure variation from the start of hold is limited to the lesser of 3 percent or 300 psi. Momentary electronic data-acquisition noise can be acceptable only if the final pressure remains above the required minimum and the gauge system stayed isolated from the pressure source during the hold. Cross reference: API 17D, Section 5.4.5.1.

For PSL 3G equipment, hydrostatic body and seat testing must be completed before gas testing. Gas body testing uses nitrogen at ambient temperature, normally with the equipment submerged in water or with an agreed alternate leak-detection method. The gas body test pressure is 1.0 x RWP with a monitored hold of at least 15 minutes. Cross reference: API 17D, Section 5.4.6.2 and Section 5.4.6.3.

For valve gas seat testing, API 17D uses a primary RWP hold and a secondary low-pressure hold at 300 psi +/- 30 psi. Each monitored hold is 15 minutes. Bidirectional valves are tested from both sides. Cross reference: API 17D, Section 5.4.6.4.

Hydraulic systems are tested separately. Components containing hydraulic control fluid are hydrostatically body tested at 1.5 x hydraulic RWP using the hydraulic system fluid. Operating subsystems such as actuators or connectors must function at no more than 0.9 x hydraulic RWP. Cross reference: API 17D, Section 5.4.7.

Illustrative image only: factory pressure testing confirms the actual shipped equipment, while validation confirms the design or product family.

Equipment-wise pressure testing and FAT summary

The table below is a practical navigation guide. It is not a replacement for the official standard or project FAT procedure.

Equipment	Pressure testing or FAT idea	Cross reference
Subsea tree assembly	Factory tested using actual mating equipment or representative test fixtures. The complete tree assembly is pressure tested to 1.0 x RWP. Table 6 guides test locations and pressures.	Section 6.4.2; Table 6
Tree and tubing head connectors	Body proof testing is 1.5 x RWP. Hydraulic connector circuits, pistons, and cylinder cavities are tested at minimum 1.5 x hydraulic RWP with no visible leakage and at least 3 minutes hold.	Section 7.8.1.1; Section 7.8.3.2
Tubing heads	PSL 2 and PSL 3 tubing heads follow the general hydrostatic test clause. PSL 3G tubing heads follow the additional gas-test clause.	Section 7.8.1.2.3
Tree stab/seal subs	Pressure-controlling stab/seal subs are proof tested at 1.0 x rating; pressure-containing stab/seal subs at 1.5 x rating. Small-bore circuit pressure rating must be checked carefully.	Section 7.9.1
Valves and valve blocks	Each valve and actuator/operator is hydrostatically and operationally tested. PSL 2, PSL 3, and PSL 3G have different body, seat, hold-time, and gas-test sequences.	Section 7.10.4.2; Tables 20a to 20c
Hydraulic valve actuators	Hydraulic actuator cylinders and pistons are tested at minimum 1.5 x hydraulic RWP with no visible leakage. Seal tests include low and rated hydraulic pressures.	Section 7.10.4.2.3
Tree caps	Pressure-containing tree caps need installation pressure-test capability, venting before removal, hydraulic-lock prevention, and connector-style FAT where applicable.	Section 7.12.3; Section 7.12.5.3
Tree piping	Inboard tree piping follows API 17D Section 5.4. Outboard piping follows the specified piping code, or Section 5.4 if no piping code is specified.	Section 7.16.2.6
Flowline connectors	Hydrostatically tested to the selected external piping code using subsea tree RWP as design pressure, plus connector-style testing where applicable.	Section 7.17.3.3
Subsea chokes	Hydrostatic testing follows Section 5.4. Choke/actuator assemblies are stroked at atmospheric pressure and at RWP to demonstrate correct operation and no backdriving.	Section 7.20.2.3; Section 7.20.4
Wellhead high-pressure housing	Mandatory hydrostatic FAT before shipment. Tested to PSL 3 requirements with test pressure based on housing RWP and Table 32. No visible leakage is allowed.	Section 8.5.5; Table 32
Casing hangers	Validation includes internal pressure structural integrity. FAT requires dimensional check or drift test; pressure testing is not required as part of FAT.	Section 8.6.3.1; Section 8.6.3.2
Annulus seal assemblies	Validation follows Section 5.1.7 and API 6A mandrel-hanger grouping. FAT is dimensional inspection per manufacturer specification.	Section 8.7.4
Casing hanger lockdown bushings	Validation covers pressure and load capability. FAT requires dimensional check or drift test; pressure testing is not required as part of FAT.	Section 8.8.3
Bore protectors and wear bushings	FAT requires dimensional check or drift test. Bore protectors do not require pressure testing.	Section 8.9.4
Tubing hangers	Mandatory hydrostatic FAT before shipment. Production and annulus bores are tested to at least 1.5 x RWP. Control and injection passages are tested to 1.5 x their respective RWP.	Section 9.3.2.1; Table 6
Tubing hanger running tools	Wellbore pressure-containing or pressure-controlling parts follow Section 5.4.5, with through-bores tested to at least 1.5 x RWP.	Section 9.3.2.2
Mudline suspension equipment	Hydrostatic FAT is not required. If testing is included in the manufacturer specification, pressure must not exceed calculated limits.	Section 10.1.4.2; Table 34
Mudline conversion tubing-head assemblies	Mandatory hydrostatic FAT before shipment. Even PSL 2 includes a secondary hold of at least 15 minutes. Test pressure is limited by the lesser controlling rating.	Section 10.6.4; Annex E
Drill-through casing hanger housings	Mandatory hydrostatic FAT before shipment, including secondary hold of at least 15 minutes even for PSL 2. Test pressure is controlled by the applicable body, riser, or hanger rating.	Section 11.3.5; Table 35
Internal drill-through casing hangers	Validation is required. FAT requires dimensional check or drift test. Hydrostatic testing is not required as part of FAT.	Section 11.4.3
HPHT equipment	Annex D adds PSL 4S, risk assessment, material, validation, QA/QC, and special pressure-testing requirements. Gas is not permitted for hydrostatic body pressure testing at hydrostatic pressure.	Annex D, D.8.2

How to use Table 6 without getting trapped

Table 6 is one of the most practical parts of API 17D for tree and tubing hanger test planning. It shows pressure-test positions for vertical and horizontal tree arrangements and distinguishes normal test pressure, hydrostatic body test pressure, and lockdown-retention pressure. Cross reference: API 17D, Section 6.4.2 and Table 6.

The trap is assuming Table 6 replaces the equipment clauses. It does not. Table 6 helps map where tests apply, but each component still has its own design, validation, FAT, and marking requirements in Sections 7, 8, 9, 10, or 11. Cross reference: API 17D, Table 6 and Sections 7 to 11.

Small-bore circuits are another place where engineers must slow down. SCSSV, hydraulic, chemical injection, and monitoring lines may use RWPSB rather than only the tree RWP. The whole small-bore circuit has to be understood, including receiver plates, tubing hanger passages, seal subs, and control pod portions where applicable. Cross reference: API 17D, Section 5.1.2.1, Table 6, Section 7.9, and Section 9.1.7.

HPHT and PSL 4S

For high-pressure high-temperature equipment, Annex D adds another layer. The engineer cannot simply increase a test pressure and call the equipment HPHT-ready. Annex D adds requirements for load identification, risk assessment, design verification, material characterization, validation, QA/QC, PSL 4S, and pressure testing. Cross reference: API 17D, Annex D.

The HPHT approach is life-cycle based. It considers operational pressure and temperature cycles, test loads, environmental loads, cyclic loads, fatigue, and potential failure modes such as plastic collapse under hydrostatic test conditions. Cross reference: API 17D, Annex D, D.3 and D.4.

For HPHT FAT, hydrostatic body pressure tests follow API 17D PSL 3 hydrostatic procedures and hold times. Functional pressure tests for pressure-controlling parts follow API 17D PSL 3G procedures and hold times. For RWP below 20000 psi, minimum hydrostatic body FAT pressure is 1.5 x marked RWP. For RWP at or above 20000 psi, the minimum is 1.25 x marked RWP unless linear elastic design methods are used, in which case 1.5 x RWP applies. Cross reference: API 17D, Annex D, D.8.2.

What a subsea engineer should check first

1. Confirm that the item is actually inside API 17D scope. Cross reference: Section 1 and Section 4.1.
2. Identify whether the item is pressure-containing, pressure-controlling, structural, hydraulic, or only a protection/guide item. Cross reference: Section 3, Section 5.1, and equipment-specific clauses.
3. Confirm RWP, temperature class, material class, sour service requirement, H2S limit, water depth, and design life. Cross reference: Section 4.2, Section 5.1.1, Section 5.1.2, and Annex B.
4. Confirm PSL at component level and assembly level. Cross reference: Section 4.3.
5. Check validation evidence against Table 5 and equipment-specific validation clauses. Cross reference: Section 5.1.7 and Table 5.
6. Check pressure-test requirements against both the common test clauses and the equipment-specific FAT clause. Cross reference: Section 5.4 and Sections 6 to 11.
7. For a tree, map pressure tests against the actual tree configuration and Table 6. Cross reference: Section 6.4.2 and Table 6.
8. For penetrations, verify barriers, venting, and fail-closed philosophy. Cross reference: Section 6.2.9 to Section 6.2.14.
9. For HPHT, apply Annex D from the beginning of the design/procurement process. Cross reference: Annex D.
10. Review marking, preservation, and shipping controls before release. Cross reference: Section 5.5 and Section 5.6.

Common mistakes when using API 17D

Mistake 1: Treating 1.5 x RWP as the answer to every test question

Many hydrostatic body tests use 1.5 x RWP, but API 17D also contains seat tests, gas tests, hydraulic system tests, lockdown retention tests, drift checks, interface checks, and equipment-specific exceptions. Cross reference: API 17D, Section 5.4, Section 6.4.2, Table 6, and Sections 7 to 11.

Mistake 2: Confusing validation with FAT

Validation qualifies the design. FAT accepts the actual shipped equipment. A good manufacturing record package needs both, where applicable. Cross reference: API 17D, Section 5.1.7 and Section 5.4.

Mistake 3: Pressure testing internal wellhead components that API 17D only requires to be drift checked at FAT

Casing hangers, lockdown bushings, bore protectors, wear bushings, and some internal drill-through components often require validation plus dimensional/drift FAT, not hydrostatic FAT on every shipped item. Cross reference: API 17D, Section 8.6.3.2, Section 8.8.3.2, Section 8.9.4, and Section 11.4.3.2.

Mistake 4: Forgetting trapped pressure and venting

Pressure trapped under a tree cap, inside a choke cavity, behind a test fitting, or in a hydraulic control circuit can turn a normal operation into a dangerous one. API 17D repeatedly requires venting or hydraulic-lock prevention. Cross reference: API 17D, Section 5.1.4.4, Section 6.3, Section 7.12.3.2, Section 7.19.2.9, and Section 7.20.2.2.6.

Mistake 5: Applying API 17D to equipment that belongs under another standard

Control modules, manifolds, jumpers, WCPs, risers, and protective structures may interface with API 17D equipment, but they are not automatically API 17D equipment. Cross reference: API 17D, Section 4.1.

Quick cross-reference map

Topic	Where to look in API 17D
Scope and exclusions	Section 1; Section 4.1
Covered equipment list	Section 4.1
Service conditions	Section 4.2
PSL rules	Section 4.3; Annex B
Material classes and sour service	Section 4.2.3; Section 5.1.1.4; Table 1
Standard pressure ratings	Section 5.1.2.1; Table 2
Validation requirements	Section 5.1.7; Table 5
Hydrostatic pressure testing	Section 5.4.5.1
PSL 3G gas testing	Section 5.4.6
Hydraulic system testing	Section 5.4.7
Tree valving and penetrations	Section 6.2
Tree assembly FAT and test locations	Section 6.4.2; Table 6
Tree connectors and tubing heads	Section 7.8
Valves, valve blocks, and actuators	Section 7.10; Annex J
Subsea chokes	Section 7.20
Subsea wellhead equipment	Section 8
Tubing hanger systems	Section 9
Mudline suspension equipment	Section 10; Annex E
Drill-through mudline equipment	Section 11; Annex M
HPHT requirements	Annex D
Hyperbaric testing guidance	Annex N
Annulus seal PR3A/PR3AL qualification	Annex Q

Final engineering takeaway

API Specification 17D is not just a document full of test pressures. It is a complete framework for subsea wellhead and tree equipment: define the service, choose the correct PSL and material class, validate the design, manufacture under controlled quality rules, factory test the actual shipped equipment, mark it correctly, and preserve it for offshore use.

The best way to use API 17D is to start with the equipment boundary, then walk through the service conditions, PSL, materials, validation, FAT, and marking requirements in order. When pressure testing is reviewed, the engineer should always combine Section 5.4, Table 6 where relevant, and the exact equipment clause. That is how the standard becomes useful in real subsea engineering work.

This summary is a navigation aid only. It does not replace API Specification 17D, purchaser datasheets, project specifications, approved manufacturer procedures, or engineering judgement.