Design of Service

1Document control and approval

Revision history

Date	By	Action	Description
2026-09-11 09:15	Faisal Al-Otaibi	created	DOS initiated for HP/HT exploration DST

2Scope and objectives

This Design of Service defines the surface well testing programme for well SHB-003 in the Sahba field, producing from the Najmah reservoir. The objective is a 96 hour hp/ht exploration dst at a target liquid rate of 1,200 bbl/d, with the wellhead held at 5,200 psia flowing pressure. All equipment sizing, operating limits and safety distances in this document are derived from the well and fluid data in section 3 using the calculation basis in section 5 and the assumptions register extract in section 8.

Client	Kuwait Oil Company	Client reference	KOC-EXP-118
Service line	Surface Well Testing	Operation type	HP/HT Exploration DST
Location	Onshore	Planned start	2026-10-19
Planned duration	96 hours	Service classification	Sour (see section 7)

3Well, reservoir and fluid data

4Equipment spread

Position	Asset	Description	MAWP	Temp rating	Material class	Sour
Flowhead	FH-3015	Surface Test Tree 3-1/16 in 15K	15,000 psi	350 °F	API 6A FF-HH-PSL3G-PR2	Yes
Choke Manifold	CM-1503	Dual Choke Manifold 3-1/16 in 15K	15,000 psi	350 °F	API 6A FF-HH-PSL3G	Yes
Flowline	FL-0300	3 in Sch 160 flowline, 10K rated	10,000 psi	250 °F	ASTM A106 Gr.B / NACE	Yes
Heater	HT-1000	Indirect Bath Heater 10.0 MMBtu/hr	15,000 psi	350 °F	ASME Sec VIII Div 1	Yes
Separator	SP-2160	3-Phase Horizontal Separator 2160 psi, 48 in x 15 ft	2,160 psi	300 °F	ASME Sec VIII Div 1 / NACE	Yes
Gas Flare	GF-0801	Vertical Gas Flare Stack 8 in, 40 ft	—	—	—	No
Esd	ES-0001	Wellhead ESD Panel, 3-station	—	—	—	Yes

5Design calculations

Each value below is produced by the platform's calculation engine from the data in section 3. The governing expression and the substituted values are printed with every result so that the calculation can be checked line by line without access to the software.

5.1 Fluid properties

Quantity	Value	Basis and calculation
Oil specific gravity (γ_o)	0.7711 -	γ_o = 141.5 / (131.5 + °API) 141.5 / (131.5 + 52.0) = 0.7711 API standard gravity definition
Oil rate at target (q_o)	1,152 stb/d	q_o = q_liq × (1 − WC) 1,200 × (1 − 0.040) = 1,152 Test objective
Water rate at target (q_w)	48 bbl/d	q_w = q_liq × WC 1,200 × 0.040 = 48 Test objective
Associated gas rate (q_g)	14.400 MMscf/d	q_g = q_o × GOR 1,152 × 12,500 = 14,400,000 scf/d Test objective
Gas-liquid ratio (R)	12,000 scf/bbl	GLR = q_g / q_liq 14,400,000 / 1,200 = 12,000 Drives the choke correlation
Blended liquid specific gravity (γ_l)	0.7827 -	γ_l = (1 − WC)·γ_o + WC·γ_w (1 − 0.040)·0.7711 + 0.040·1.0600 = 0.7827 Volume-weighted blend
Pseudo-critical temperature (sweet basis) (T_pc)	403.7 °R	T_pc = 169.2 + 349.5·γ_g − 74.0·γ_g² 169.2 + 349.5(0.8100) − 74.0(0.8100)² = 403.7 Sutton (1985)
Pseudo-critical pressure (sweet basis) (P_pc)	648.3 psia	P_pc = 756.8 − 131.0·γ_g − 3.6·γ_g² 756.8 − 131.0(0.8100) − 3.6(0.8100)² = 648.3 Sutton (1985)
Wichert-Aziz acid gas correction (ε)	13.62 °R	ε = 120(A^0.9 − A^1.6) + 15(B^0.5 − B⁴), A = y_H2S + y_CO2, B = y_H2S A = 0.09840, B = 0.012400 → ε = 13.62 °R Wichert & Aziz (1972) Without this correction the Z-factor for this sour stream would be wrong, and every downstream volume with it.
Gas compressibility at wellhead (Z)	1.0140 -	Z = A + (1−A)/e^B + C·P_pr^D (Brill & Beggs fit to Standing-Katz) P_pr = 8.304, T_pr = 1.704 → Z = 1.0140 Brill & Beggs (1974)
Gas density at wellhead (ρ_g)	16.872 lb/ft³	ρ_g = 2.70·γ_g·P / (Z·T) 2.70(0.8100)(5,200) / (1.0140 × 664.7) = 16.872 Real gas law
Oil formation volume factor (B_o)	11.4138 rb/stb	B_o = 0.9759 + 0.00012·[R_s·√(γ_g/γ_o) + 1.25·T]^1.2 R_s = 12,500, T = 205 °F → B_o = 11.4138 Standing (1947)
Total mass flow rate (ṁ)	50,822 lb/hr	ṁ = ṁ_gas + ṁ_oil + ṁ_water 37,112 + 12,968 + 743 = 50,822 lb/hr Mass balance
Gas mass fraction (x_g)	73.0 %	x_g = ṁ_gas / ṁ_total 37,112 / 50,822 = 73.0 % Used to weight the Joule-Thomson coefficient

5.2 Inflow performance

Quantity	Value	Basis and calculation
Rate at bubble point (q_b)	1,953 stb/d	q_b = J × (P_r − P_b) 0.420 × (9,850 − 5,200) = 1,953 Straight-line IPR above bubble point
Absolute open flow potential (q_max)	3,166 stb/d	q_max = q_b + J·P_b / 1.8 1,953 + 0.420(5,200)/1.8 = 3,166 Vogel (1968) composite IPR
Flowing bottomhole pressure required (P_wf)	7,107 psia	q/q_max = 1 − 0.2(P_wf/P_r) − 0.8(P_wf/P_r)² solved for P_wf q = 1,152 stb/d → P_wf = 7,107 psia Vogel (1968)
Drawdown at target rate (ΔP)	2,743 psi	ΔP = P_r − P_wf 9,850 − 7,107 = 2,743 Reservoir management constraint
Fraction of open flow potential	36.4 %	q / q_max 1,152 / 3,166 = 36.4 % Rate feasibility screen

5.3 Pressure integrity

Quantity	Value	Basis and calculation
Maximum anticipated surface pressure (MASP)	7,684 psia	MASP = P_r · exp(−0.01875·γ_g·TVD / (Z̄·T̄)) 9,850 · exp(−0.01875(0.8100)(14,200)/(1.3166 × 659.7)) = 7,684 Compressible static gas column, gas-filled tubing worst case
Minimum equipment rating required	8,453 psia	MAWP_min = MASP × (1 + design margin) 7,684 × (1 + 10%) = 8,453 NESR ES-WT-002 design margin
Rated pressure of weakest upstream item	10,000 psi	min(MAWP) across flowhead, choke manifold and flowline 3 in Sch 160 flowline, 10K rated (FL-0300) = 10,000 psi API 6A / ISO 10423 pressure class
Site pressure test value	8,453 psi	P_test = MASP × test factor 7,684 × 1.10 = 8,453 ASME B31.3 / client test procedure Hold 15 minutes with an acceptance criterion of no visible pressure decay.

5.4 Choke sizing and flow regime

Quantity	Value	Basis and calculation
Required choke bean size (d)	23 64ths in	d = (A · q_liq · R^B / P_wh)^(1/C) (10.000 × 1,200 × 12,000^0.546 / 5,200)^(1/1.890) = 23.47 → 23/64 in Gilbert (1954) multiphase critical flow correlation Rounded up to the nearest available bean in the manifold.
Equivalent bean diameter	0.3594 in	d_in = d / 64 23 / 64 = 0.3594 in
Bean flow area (A)	0.10143 in²	A = π·d²/4 π(0.3594)²/4 = 0.10143 in²
Pressure drop across the bean (ΔP)	4,300 psi	ΔP = P_wh − P_downstream 5,200 − 900 = 4,300 Drives Joule-Thomson cooling and erosion
Downstream / upstream pressure ratio	0.173 -	P_dn / P_up vs critical ratio 900 / 5,200 = 0.173 (critical at ≤ 0.55) Isentropic choked flow Flow is critical. Rate is set by the bean and upstream pressure only, and is independent of separator pressure. This is the condition required for a stable, repeatable test.

Correlation	A	B	C	Bean (64ths)	Bean (in)
Gilbert (1954)	10.000	0.546	1.890	23.5	0.3668
Ros (1960)	17.400	0.500	2.000	21.0	0.3277
Baxendell (1957)	9.560	0.546	1.930	21.5	0.3356
Achong (1961)	3.820	0.650	1.880	24.1	0.3759

5.5 Flowline erosional velocity

Quantity	Value	Basis and calculation
Mixture density at flowline conditions (ρ_m)	4.976 lb/ft³	ρ_m = (12409·γ_l·P + 2.7·R·γ_g·P) / (198.7·P + R·T·Z) P = 900 psia, T = 599.7 °R, R = 12,000 scf/bbl, Z = 0.8789 → 4.976 lb/ft³ API RP 14E section 2.5
Applied erosional C-factor (C)	125.0 -	C = C_intermittent × (sand derate if applicable) 125, no derate (sand 0.60 pptb < 1.0 pptb trigger) API RP 14E + NESR ES-WT-011
Erosional velocity limit (V_e)	56.04 ft/s	V_e = C / √ρ_m 125.0 / √4.976 = 56.04 ft/s API RP 14E
Actual volumetric flow at flowline conditions (q)	3.6176 ft³/s	q = q_gas·B_g/86400 + (q_o·B_o + q_w)·5.615/86400 gas 2.7600 + liquid 0.8576 = 3.6176 ft³/s
Actual mixture velocity (V)	96.33 ft/s	V = q / A, A = π·d²/4 3.6176 / 0.03755 = 96.33 ft/s (2.624 in ID)
Erosional velocity ratio (EVR)	1.719 -	EVR = V / V_e 96.33 / 56.04 = 1.719 Design target ≤ 0.80
Minimum flowline ID to satisfy the limit (d_min)	3.440 in	d_min = √(4q / (π·V_e)) √(4×3.6176 / (π×56.04)) = 3.440 in
Produced solids mass rate	0.030 lb/hr	ṁ_sand = q_liq × sand / 1000 / 24 1,200 × 0.60 / 1000 / 24 = 0.030 lb/hr Sand management trigger

5.6 Joule-Thomson cooling, hydrates and heating

Quantity	Value	Basis and calculation
Effective Joule-Thomson coefficient (μ_JT)	0.03421 °F/psi	μ_JT = x_g·μ_gas + (1 − x_g)·μ_liquid 0.7302(0.0450) + 0.2698(0.0050) = 0.03421 °F/psi Mass-weighted from the stream composition Weighting matters: a gas well cools an order of magnitude more across the same pressure drop than an oil well.
Temperature drop across the bean (ΔT)	147.1 °F	ΔT = μ_JT × ΔP 0.03421 × 4,300 = 147.1 °F Joule-Thomson expansion
Temperature downstream of the bean (T_dn)	57.9 °F	T_dn = T_wh − ΔT 205 − 147.1 = 57.9 °F
Hydrate formation temperature at separator pressure (T_h)	66.5 °F	T_h = −238.245 + 78.997·log P − 5.353·(log P)² + 349.474·γ_g − 150.855·γ_g² − 27.604·γ_g·log P P = 900 psia, γ_g = 0.8100 → T_h = 66.5 °F Motiee (1991)
Minimum process temperature	140.0 °F	T_req = max(T_h + margin, T_separator target) max(66.5 + 10, 140) = 140.0 °F Hydrate margin NESR ES-WT-004; separator target set by emulsion and viscosity control
Heating required	82.1 °F	ΔT_heat = T_req − T_dn 140.0 − 57.9 = 82.1 °F
Process heat duty (Q)	2.248 MMBtu/hr	Q = Σ(ṁ_i · c_p,i) · ΔT (37,112×0.55 + 12,968×0.48 + 743×1.00) × 82.1 = 2,247,778 Btu/hr Sensible heat balance, GPSA specific heats
Fired duty required	3.372 MMBtu/hr	Q_fired = Q × design factor / thermal efficiency 2.248 × 1.20 / 0.80 = 3.372 MMBtu/hr Vendor efficiency, NESR ES-WT-006 design factor

5.7 Three-phase separation

Quantity	Value	Basis and calculation
Gas density at separator (ρ_g)	3.7341 lb/ft³	ρ_g = 2.70·γ_g·P / (Z·T) P = 900 psia, T = 140 °F, Z = 0.8789 → 3.7341 lb/ft³
Maximum gas velocity before carryover (V_max)	1.390 ft/s	V_max = K·√((ρ_l − ρ_g)/ρ_g) 0.40·√((48.84 − 3.7341)/3.7341) = 1.390 ft/s Souders-Brown, API 12J, K for horizontal vessel with mist extractor
Gas disengagement area	6.283 ft²	A_gas = (1 − fill)·π·D²/4 (1 − 0.50)·π(4.00)²/4 = 6.283 ft² Half-full horizontal vessel design case
Separator gas capacity	45.57 MMscf/d	q_max = V_max · A_gas · 86400 / B_g 1.390 × 6.283 × 86400 / 0.01656 = 45.57 MMscf/d API 12J
Gas capacity utilisation	31.6 %	q_gas / q_max 14.400 / 45.57 = 31.6 %
Liquid volume required for retention	14.04 ft³	V = (q_o·t_o + q_w·t_w) × 5.615 / 1440 (1,152×3.0 + 48×3.0) × 5.615 / 1440 = 14.04 ft³ API 12J retention times
Liquid volume available	94.25 ft³	V = fill · π·D²/4 · L 0.50 · π(4.00)²/4 · 15.0 = 94.25 ft³
Separator liquid capacity	8,057 bbl/d	q_max = V_avail / 5.615 × 1440 / t_retention 94.25 / 5.615 × 1440 / 3.0 = 8,057 bbl/d API 12J
Liquid capacity utilisation	14.9 %	V_required / V_available 14.04 / 94.25 = 14.9 %

5.8 Burner thermal radiation

Quantity	Value	Basis and calculation
Total heat release at the burner (Q)	630.0 MMBtu/hr	Q = ṁ_oil·LHV_oil + q_gas·LHV_gas 0 lb/hr × 18,300 + 600,000 scf/hr × 1,050 = 630,000,000 Btu/hr GPSA heating values
Flame length (L)	96.4 ft	L = 0.006 · Q^0.478 0.006 × (630,000,000)^0.478 = 96.4 ft API STD 521 Annex C
Fraction of heat radiated (F)	0.150 -	Selected by combustion type Gas burner → F = 0.150 API STD 521 Annex C
Safe distance, continuously manned area (D)	123 ft	D = √(τ·F·Q / (4π·K)) √(1.00 × 0.150 × 630,000,000 / (4π × 500)) = 123 ft API STD 521 Table 8, 1.58 kW/m²
Radiation at the planned stand-off (K)	131 Btu/hr·ft²	K = τ·F·Q / (4π·D²) τ·F·Q / (4π × 240²) = 131 Btu/hr·ft² (0.41 kW/m²) API STD 521

Exposure category	Limit	Equivalent	Minimum distance
Continuously manned area	500 Btu/hr·ft²	1.58 kW/m²	123 ft
Escape route, seconds of exposure	1,500 Btu/hr·ft²	4.73 kW/m²	71 ft
Equipment and unmanned areas	2,000 Btu/hr·ft²	6.31 kW/m²	61 ft

5.9 Sour service classification

Quantity	Value	Basis and calculation
H₂S partial pressure at MASP (p_H2S)	95.2845 psia	p_H2S = y_H2S × P (12,400 / 10⁶) × 7,684 = 95.2845 psia NACE MR0175 / ISO 15156-1
Service classification	Sour service	p_H2S ≥ 0.05 psia → sour service NACE MR0175 / ISO 15156 All wetted pressure-containing components must carry NACE MR0175 certification, and personnel controls for H₂S apply for the full duration of the test.
Personal alarm set point	10 ppm	Fixed by HSE case 10 ppm Client HSE case
Immediately dangerous to life or health	100 ppm	NIOSH IDLH 100 ppm NIOSH

6Design limit verification

Every check below is evaluated automatically against the standard named in the basis column. A critical failure prevents this document from being issued.

Ref	Check	Result	Actual vs limit	Finding and basis
ERO-001	Erosional velocity in the flowline critical	FAIL	EVR 1.719 ≤ 0.80	Mixture velocity of 96.3 ft/s exceeds the API RP 14E erosional limit of 56.0 ft/s. Minimum acceptable flowline ID is 3.44 in against the 2.624 in selected. Action required: Select a flowline of at least 3.44 in ID, or reduce the target rate. API RP 14E
HYD-001	Hydrate formation margin downstream of the bean critical	FAIL	-8.6 °F margin ≥ 10 °F	Without heating the stream reaches 57.9 °F against a hydrate temperature of 66.5 °F. Hydrates will form in the choke body and flowline. Action required: Bring the heater on line before opening the well, or inject methanol / MEG at the choke inlet. Motiee (1991) hydrate correlation, NESR ES-WT-004 margin
SOU-002	H₂S exposure controls major	CAUTION	12,400 ppm in stream IDLH 100 ppm	Stream H₂S concentration exceeds the IDLH threshold. Continuous gas detection, cascade breathing air, wind socks, muster points and a documented H₂S contingency plan are mandatory for the full test. Action required: Attach the H₂S contingency plan and the drill record to this DOS before issue. NIOSH / client HSE case
CHK-001	Critical flow across the bean major	PASS	ratio 0.173 ≤ 0.55	The bean is in critical flow, so measured rates will be stable and independent of downstream conditions. Isentropic choked flow, k ≈ 1.27
CHK-002	Choke correlation sensitivity advisory	PASS	13.1 % spread below 40 %	The four published correlations disagree by 13.1 % on bean size for this fluid. The correlations are in reasonable agreement for this fluid. Comparison of Gilbert, Ros, Baxendell and Achong
DEL-001	Target rate against inflow performance major	PASS	36.4 % of AOF below 90 % of AOF	The target rate is comfortably inside the well's deliverability. Vogel (1968) IPR from the supplied productivity index
FLU-001	Z-factor correlation validity advisory	PASS	T_pr 1.70 / P_pr 8.30 1.15 < T_pr < 2.4, P_pr < 15	Wellhead conditions are inside the published validity window of the correlation. Brill & Beggs (1974)
HYD-002	Heater duty adequacy major	PASS	3.372 MMBtu/hr required 10.00 MMBtu/hr rated	Selected heater covers the fired duty at 34 % utilisation. The selected 10.0 MMBtu/hr unit is significantly oversized at 34 % utilisation; a smaller unit would reduce mobilisation cost. NESR ES-WT-006
PRS-001	Upstream pressure containment critical	PASS	MASP 7,684 psia MAWP 10,000 psi	Weakest upstream component is rated 10,000 psi against a MASP of 7,684 psia, a margin of 23.2 %. API 6A / NESR ES-WT-002
PRS-002	Separator relief protection critical	PASS	Operating 900 psia MAWP 2,160 psi	Separator rating is adequate for the planned operating pressure. A relief valve sized for the choke-washout case is still required. Action required: Confirm PSV set pressure at or below the vessel MAWP and size it for full choke bypass flow. API RP 14C / API 12J
RAD-001	Thermal radiation at manned areas critical	PASS	131 Btu/hr·ft² 500 Btu/hr·ft²	Radiation at the planned stand-off is 26 % of the manned-area limit. API STD 521 Table 8 / IOGP 434-18
SEP-001	Separator gas handling capacity critical	PASS	31.6 % ≤ 85 %	Vessel has adequate capacity for the design case. API SPEC 12J
SEP-002	Separator liquid retention capacity critical	PASS	14.9 % ≤ 85 %	Vessel has adequate capacity for the design case. API SPEC 12J
SOU-001	Sour service material compliance critical	PASS	95.2845 psia H₂S ≥ 0.05 psia triggers sour service	Sour service confirmed at 95.284 psia H₂S partial pressure. All rated components on the spread carry NACE MR0175 certification. NACE MR0175 / ISO 15156

7Operating limits and safety envelope

Parameter	Limit	Basis
Maximum anticipated surface pressure	7,684 psia	Static gas column from reservoir pressure
Site pressure test value	8,453 psi, 15 minute hold	ASME B31.3 / client test procedure
Choke bean, design case	23/64 in	Governed choke correlation
Minimum separator inlet temperature	66 °F + 10 °F margin	Hydrate control
Maximum flowline velocity	56.0 ft/s	API RP 14E erosional limit
Separator operating pressure	900 psia	Design case, PSV set at vessel MAWP
Minimum stand-off, manned areas	123 ft	API STD 521, 500 Btu/hr·ft²
H₂S personal alarm	10 ppm, evacuate at 15 ppm	Client HSE case
ESD closure, surface safety valve	7 seconds maximum	API RP 14C

8Assumptions register extract

The constants, correlation coefficients and design limits below were read from the company assumptions register at the time this document was generated. Each carries its revision number, so the calculation can be reproduced exactly at any future date.

Category	Assumption	Value	Rev	Basis
Choke model	Achong coefficient A	3.82 -	1	Achong (1961)
Choke model	Achong exponent B (GLR)	0.65 -	1	Achong (1961)
Choke model	Achong exponent C (bean)	1.88 -	1	Achong (1961)
Choke model	Baxendell coefficient A	9.56 -	1	Baxendell (1957)
Choke model	Baxendell exponent B (GLR)	0.546 -	1	Baxendell (1957)
Choke model	Baxendell exponent C (bean)	1.93 -	1	Baxendell (1957)
Choke model	Critical (sonic) pressure ratio	0.55 Pdn/Pup	2	Isentropic choked flow, k~1.27
Choke model	Gilbert coefficient A	10 -	1	Gilbert (1954), API 14B practice
Choke model	Gilbert exponent B (GLR)	0.546 -	1	Gilbert (1954)
Choke model	Gilbert exponent C (bean)	1.89 -	1	Gilbert (1954)
Choke model	Ros coefficient A	17.4 -	1	Ros (1960)
Choke model	Ros exponent B (GLR)	0.5 -	1	Ros (1960)
Choke model	Ros exponent C (bean)	2 -	1	Ros (1960)
Deliverability	Vogel IPR coefficient on (Pwf/Pr)	0.2 -	1	Vogel (1968)
Deliverability	Vogel IPR coefficient on (Pwf/Pr)^2	0.8 -	1	Vogel (1968)
Erosion	API 14E C-factor, intermittent service	125 -	1	API RP 14E 2.5
Erosion	C-factor derating when sand is present	0.6 fraction	3	NESR internal ES-WT-011
Erosion	Erosional velocity ratio caution threshold	0.8 -	1	NESR internal ES-WT-011
Erosion	Sand concentration triggering derate	1 pptb	2	NESR internal ES-WT-011
Heating	Heater duty design factor	1.2 -	2	NESR internal ES-WT-006
Heating	Indirect heater thermal efficiency	0.8 fraction	1	Vendor data, glycol bath heaters
Heating	Specific heat of crude oil	0.48 Btu/lb-degF	1	GPSA Data Book Sec. 23
Heating	Specific heat of gas	0.55 Btu/lb-degF	1	GPSA Data Book Fig. 24-7
Heating	Specific heat of produced water	1 Btu/lb-degF	1	Standard
Hydrates	Joule-Thomson cooling coefficient, gas phase	0.045 degF/psi	4	Field-calibrated, MENA gas 0.6-0.75 SG
Hydrates	Minimum margin above hydrate formation temperature	10 degF	2	NESR internal ES-WT-004
Pressure integrity	Minimum margin of equipment MAWP over MASP	10 %	3	NESR internal ES-WT-002
Pressure integrity	Site pressure test factor on MOP	1.1 -	1	ASME B31.3 / client procedure
Radiation	Atmospheric transmissivity	1 -	1	API STD 521 6.4.2
Radiation	Flame length correlation coefficient	0.006 -	1	API STD 521 Annex C
Radiation	Flame length correlation exponent	0.478 -	1	API STD 521 Annex C
Radiation	Fraction of heat radiated, gas flare	0.15 -	1	API STD 521 Annex C
Radiation	Lower heating value of associated gas	1,050 Btu/scf	2	GPSA Data Book Sec. 23
Radiation	Lower heating value of crude	18,300 Btu/lb	1	GPSA Data Book Sec. 23
Radiation	Radiation limit, continuously manned area	500 Btu/hr-ft2	1	API STD 521 Table 8 (1.58 kW/m2)
Radiation	Radiation limit, equipment and unmanned areas	2,000 Btu/hr-ft2	1	API STD 521 Table 8 (6.31 kW/m2)
Radiation	Radiation limit, escape route, few seconds exposure	1,500 Btu/hr-ft2	1	API STD 521 Table 8 (4.73 kW/m2)
Separation	Design liquid fill fraction of separator volume	0.5 fraction	1	API 12J
Separation	Oil retention time	3 minutes	2	API 12J Table 1, 30-40 API crude
Separation	Separator utilisation caution threshold	0.85 fraction	1	NESR internal ES-WT-008
Separation	Souders-Brown K, horizontal vessel with mist extractor	0.4 ft/s	1	API 12J / Arnold & Stewart
Separation	Water retention time	3 minutes	1	API 12J Table 1
Sour service	H2S immediately dangerous to life or health	100 ppm	1	NIOSH
Sour service	H2S partial pressure threshold for sour service	0.05 psia	1	NACE MR0175 / ISO 15156-1
Sour service	H2S personal alarm set point	10 ppm	1	OSHA / client HSE case

9Reference standards

Reference	Title	Edition	Applied to
API RP 14C	Analysis, Design, Installation and Testing of Basic Surface Safety Systems	8th Ed.	ESD architecture and relief protection
API RP 14E	Design and Installation of Offshore Production Platform Piping Systems	5th Ed.	Erosional velocity limits, flowline sizing
API SPEC 12J	Specification for Oil and Gas Separators	8th Ed.	Separator gas and liquid capacity
API SPEC 6A	Specification for Wellhead and Christmas Tree Equipment	21st Ed.	Pressure ratings of flow control equipment
API STD 521	Pressure-relieving and Depressuring Systems	7th Ed.	Flare / burner thermal radiation and flame length
ASME B31.3	Process Piping	2022	Flowline wall thickness and test pressure
IOGP 434-18	Risk assessment data - thermal radiation exposure	2019	Personnel exposure thresholds
ISO 10423	Wellhead and christmas tree equipment	2009	Equipment pressure/temperature class
NACE MR0175	Materials for use in H2S-containing environments (ISO 15156)	2015	Sour service classification