01Introduction & standards overviewP-002 §1

📌 How to use this course
This mini course is intended as a quick-scan reference to help you find the right criteria fast. It is not a substitute for reading the actual standard. Always verify the criteria against the latest edition of each standard applicable to your project, and always follow your project-specific design basis and company standards — they may be more conservative than the values shown here.

The line sizing criteria in this course are based on NORSOK P-002 Edition 1 (August 2014), supported by API RP 14E (2021 reaffirmation) and ISO 13703 where P-002 refers to them.

NORSOK P-001 → P-002: NORSOK P-001 Edition 5 (2006) has been replaced and absorbed into NORSOK P-002 Edition 1 (2014). P-002 combined P-001 and P-100 into a single document. If you encounter references to P-001 on older projects, the line sizing criteria are in P-002 §7. The section structure and table numbers have changed — Table 3 is now Table 6, Table 4 is now Table 7, and line sizing moved from §6 to §7.

Standards used in this course

Standard	Full title	Key section
NORSOK P-002 Ed. 1, Aug 2014	Process System Design — topside process piping and equipment for offshore facilities	§7 Line sizing
API RP 14E 2021 reaffirm.	Design and Installation of Offshore Production Platform Piping Systems	§2.4 Erosional velocity
ISO 13703 2000	Design and Installation of Piping Systems on Offshore Production Platforms	§5.3 Pipe sizing

⚠ Always check the latest version. Standards are revised regularly. NORSOK P-002:2014 was itself superseded by P-002:2023, which updated the gas and two-phase line sizing methodology. API RP 14E and ISO 13703 also have active review cycles. Before applying any criteria on a real project, confirm the governing edition with your project design basis.

NORSOK P-002 Ed.1 (2014) API RP 14E (2021) ISO 13703 (2000)

Check your understanding

Where do you find the line sizing criteria in NORSOK P-002 (2014)?

02§7.2 Sizing of liquid linesP-002 §7.2 / Table 6

Liquid lines are sized against maximum velocity from Table 6 and a pressure drop limit. Both criteria apply simultaneously — the more stringent governs. Velocities are differentiated by pipe material.

Table 6 — Maximum velocities for liquid lines (§7.2.1)

Fluid	CS (m/s)	SS / Ti (m/s)	Cu-Ni (m/s)	GRP (m/s)
Liquids — general	6	7 ¹⁾	3	6
Liquids with sand	5	7	—	6
Liquids with mud / silt	3	—	—	—
Untreated seawater	3	7	3 ²⁾	—
Deoxygenated seawater	6	7	3	6

¹⁾ SS/Ti limited only by available ΔP and reaction forces — 7 m/s is a typical starting value. ²⁾ For Cu-Ni pipe < DN 200, refer to BS MA-18 for velocity limits. Minimum Cu-Ni velocity = 1 m/s; intermittent service may reach 10 m/s.

§7.2.2 Pump suction lines — pressure drop limits

Condition	Max velocity	Max ΔP (bar / 100 m)
Sub-cooled (≥15°C below boiling point)	Table 6	0.25
Boiling / near-boiling liquid	Table 6	0.05

Always verify NPSH independently. These ΔP limits are starting criteria — NPSH calculations govern the final suction line size. The boiling liquid limit of 0.05 bar/100 m is very tight and will typically drive a larger bore than the velocity criterion alone.

§7.2.3 – §7.2.5 Discharge, control valves and gravity flow

Service	Criterion
Pump discharge	Table 6 velocity; guideline ΔP ≤ 0.9 bar / 100 m
Control valve inlet	Size to maintain single-phase liquid upstream of valve
Gravity flow — fixed installation	Min slope 1 : 100; with sand/mud → 1 : 50
Gravity flow — floating installation	Evaluate slope per planned installation trim

NORSOK P-002 §7.2, Table 6BS MA-18 (Cu-Ni < DN 200)

Check your understanding

What is the P-002 maximum ΔP for a boiling liquid pump suction line?

03§7.3 Sizing of gas linesP-002 §7.3 / Table 7

Gas lines are sized against a noise/vibration velocity limit (Formula 4) and, when ΔP is critical, a pressure drop guideline (Table 7). Both must be checked.

§7.3.1 Maximum velocity — noise limit (Formula 4)

V = 175 / √ρ_G [normal service — V in m/s, ρ in kg/m³] V = 200 / √ρ_G [anti-surge lines, process upsets only] Upper cap: 60 m/s [use whichever is lower: formula or 60 m/s]

The 60 m/s upper cap means that for very low-density gas (ρ < ~8.5 kg/m³), the cap governs before the formula does. For anti-surge lines, the constant 200 applies during upsets only — normal recycle must return to 175/√ρ. If solid particles exist, special attention shall be given to particle erosion.

§7.3.2 Table 7 — ΔP guideline when pressure drop is critical

Operating pressure (barg)	ΔP guideline (bar / 100 m)
0 – 35	0.001 – 0.11
35 – 138	0.11 – 0.27
> 138	P / 500 (P = operating pressure in bara)

ΔP is considered critical when: (a) the cost of additional power from a smaller pipe exceeds savings from reduced pipe diameter, or (b) it causes unacceptable liquid drop-out in compressor suction lines, turbo-expander inlets or contactor inlets.

NORSOK P-002 vs. API RP 14E: API RP 14E uses 146/√ρ as an erosional/momentum limit (metric). P-002 uses 175/√ρ capped at 60 m/s as a noise-driven limit — about 20% higher than API's formula. These are not interchangeable. Where your project requires both standards, apply the more stringent result.

NORSOK P-002 §7.3, Table 7API RP 14E §2.4 (2021)

Check your understanding

Gas at ρ = 1 kg/m³. What is the P-002 maximum velocity for normal service?

04§7.4 Sizing of two-phase / multiphase linesP-002 §7.4 / API RP 14E §2.4

P-002 §7.4 separates two-phase sizing into non-corrosive and corrosive service. API RP 14E (2021) provides the erosional velocity formula for corrosive CS service. Slugging must always be explicitly evaluated.

§7.4.1 General requirement

When sizing two- or multiphase lines, unstable flow and slugging shall be considered. The number and length of multiphase lines should be kept to a minimum where possible.

§7.4.2 Velocity formula (all two-phase)

V_M = c / √ρ_mix [V in m/s, ρ_mix = mixed-phase density in kg/m³]

§7.4.3 Non-corrosive service — CRA or sand-free

Condition	Maximum velocity
CRA piping or minimal sand / proppants	25 m/s (direct cap)
With significant sand or particles	Specialist erosion program required

§7.4.4 Corrosive service — carbon steel (API RP 14E §2.4)

Service	Location	c value (metric)
Continuous, bare CS	Any	122
Intermittent, bare CS	Any	152
Continuous, CRA / inhibited	Onshore	146
Continuous, CRA / inhibited	Offshore	250 ¹⁾
Intermittent, CRA / inhibited	Any	300 ¹⁾

¹⁾ c = 250 (offshore) and c = 300 (intermittent) are for short offshore flowlines and manifolds. For onshore CRA / inhibited two-phase piping use c = 146. Applying c = 250 onshore is not supported by API RP 14E.

NORSOK P-002 §7.4API RP 14E §2.4 (2021)ISO 13703 §5.3

Check your understanding

P-002 §7.4.3: maximum velocity for a CRA two-phase line with minimal sand?

05§7.5 Sizing of flare and vent linesP-002 §7.5 / API Std 520 / 521

P-002 §7.5 uses explicit Mach number limits for flare headers and PSV lines. Detailed PSV and blowdown sizing follows API Std 520 and API Std 521 respectively.

§7.5.1 Flare headers and general flare piping

Line type	P-002 Mach limit
Flare headers and flare piping	≤ Mach 0.6
PSV outlet line — first block valve downstream	≤ Mach 0.7
PSV outlet > Mach 0.7 → reducer required	≤ Mach 0.7 downstream of reducer
PSV inlet and outlet detailed sizing	Per API Std 520
Controlled flaring / blowdown	Per API Std 521

Where PSV outlet velocity exceeds Mach 0.7, install a reducer as close as possible to the PSV (preferably at the PSV outlet flange) to increase line size. Back-pressure at the PSV outlet and at the block valve must always be checked against the PSV back-pressure limits regardless of Mach.

P-002 vs. API Std 521: API Std 521 typically recommends ≤ 0.5 Mach for flare headers. P-002 allows Mach 0.6 for flare headers and Mach 0.7 for PSV tails. Where both apply, use the more conservative limit specified in your project design basis.

NORSOK P-002 §7.5API Std 520 (PSV sizing)API Std 521 (depressuring)

Check your understanding

According to P-002 §7.5, what is the maximum Mach number for a flare header?

06§7 at a glance — complete referenceP-002 §7 summary

📌 Quick-scan only. This summary is a working reference — not a replacement for the standard itself. Always verify against the governing edition on your project and your project design basis.

§7.2 — Liquid velocities (Table 6) and pump suction ΔP

Service / condition	CS	SS/Ti	Cu-Ni	GRP
General liquids	6 m/s	7 m/s	3 m/s	6 m/s
With sand	5 m/s	7 m/s	—	6 m/s
With mud / silt	3 m/s	—	—	—
Untreated seawater	3 m/s	7 m/s	3 m/s	—
Deoxygenated seawater	6 m/s	7 m/s	3 m/s	6 m/s
Pump suction — sub-cooled	Table 6 + ΔP ≤ 0.25 bar/100 m
Pump suction — boiling	Table 6 + ΔP ≤ 0.05 bar/100 m
Pump discharge	Table 6 + ΔP guideline ≤ 0.9 bar/100 m
Gravity — fixed	Min slope 1:100 (sand/mud → 1:50)

§7.3 — Gas: velocity (Formula 4) and ΔP (Table 7)

Service	Velocity / ΔP
Normal service	175/√ρ or 60 m/s — lower governs
Anti-surge (upsets only)	200/√ρ (temporary)
0 – 35 barg (critical ΔP)	0.001 – 0.11 bar/100 m
35 – 138 barg (critical ΔP)	0.11 – 0.27 bar/100 m
> 138 barg (critical ΔP)	P/500 bar/100 m (P in bara)

§7.4 — Two-phase / multiphase

Service	Velocity limit
CRA / non-corrosive / minimal sand	≤ 25 m/s
With significant sand / particles	Specialist erosion program
CS continuous (API RP 14E)	122/√ρ_mix
CS intermittent (API RP 14E)	152/√ρ_mix
CRA/inhibited onshore continuous (API RP 14E)	146/√ρ_mix
CRA/inhibited offshore continuous (API RP 14E)	250/√ρ_mix ¹⁾
All two-phase	Slugging shall be evaluated

¹⁾ Offshore short flowlines/manifolds only. Use 146/√ρ for onshore even with CRA.

§7.5 — Flare and vent lines

Line type	Limit
Flare headers and piping	≤ Mach 0.6
PSV outlet — first block valve downstream	≤ Mach 0.7
PSV inlet + outlet detailed sizing	Per API Std 520
Controlled flaring / blowdown	Per API Std 521

NORSOK P-002 §7 (2014) API RP 14E §2.4 (2021) API Std 520 / 521 ISO 13703

07Final quiz — P-002 §7 all criteria§7.1 – 7.5

Five questions across all §7 sections. Each references the exact clause and standard.

Question 1 of 5 — §7.2, Table 6

Carbon steel line carrying untreated seawater. Maximum velocity per P-002 Table 6?

Question 2 of 5 — §7.3, Formula 4

Gas line at ρ = 50 kg/m³, normal service. Maximum velocity per P-002?

Question 3 of 5 — §7.4

Onshore two-phase line, CS pipe, corrosion inhibition applied, continuous service. Which c-value applies (API RP 14E, metric)?

Question 4 of 5 — §7.5

PSV outlet line calculated at Mach 0.85. What does P-002 §7.5 require?

Question 5 of 5 — §7.3, Table 7

Gas line at 160 barg, P_static = 161 bara. P-002 Table 7 ΔP guideline when pressure drop is critical?

✓Course complete!

—score

NORSOK P-002 §7 — done

You've covered all line sizing criteria from NORSOK P-002 Edition 1 (2014), Section 7.

📌 A final reminder
This course is a quick-scan guide only. Always verify every criterion against the latest edition of the standard applicable to your project. NORSOK P-002:2014 was superseded by P-002:2023. API RP 14E and ISO 13703 also have active revision cycles. Your project design basis and company standards take precedence over any generic guideline — including this one.

Key numbers — P-002 §7 quick reference

§	Criterion	Value
7.2	Pump suction — sub-cooled ΔP	≤ 0.25 bar/100 m
7.2	Pump suction — boiling ΔP	≤ 0.05 bar/100 m
7.3	Gas velocity — normal service	175/√ρ or 60 m/s
7.4	Two-phase — CRA/non-corrosive cap	25 m/s
7.5	Flare headers	≤ Mach 0.6
7.5	PSV outlet line	≤ Mach 0.7

Process Line Sizing Criteria

NORSOK P-002 §7 — done