Design of Service

1Document control and approval

Revision history

Date	By	Action	Description
2026-08-18 11:02	Faisal Al-Otaibi	created	DOS initiated for extended well test
2026-08-24 15:40	Marwa Saad	reviewed	Technical review complete, no comments
2026-08-26 11:20	Rajesh Nair	approved	Approved for execution

2Scope and objectives

This Design of Service defines the surface well testing programme for well QDM-0221 in the Qidam field, producing from the Thamama reservoir. The objective is a 168 hour extended well test at a target liquid rate of 6,200 bbl/d, with the wellhead held at 900 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	ADNOC Onshore	Client reference	ADN-2026-3390
Service line	Surface Well Testing	Operation type	Extended Well Test
Location	Onshore	Planned start	2026-09-02
Planned duration	168 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-5015	Surface Test Tree 5-1/8 in 10K	10,000 psi	250 °F	API 6A EE-NL-PSL3-PR1	Yes
Choke Manifold	CM-1002	Dual Choke Manifold 3-1/16 in 10K	10,000 psi	250 °F	API 6A EE-NL-PSL3	Yes
Flowline	FL-0400	4 in Sch 160 flowline, 10K rated	10,000 psi	250 °F	ASTM A106 Gr.B / NACE	Yes
Heater	HT-0250	Indirect Glycol Bath Heater 2.5 MMBtu/hr	10,000 psi	250 °F	ASME Sec VIII Div 1	Yes
Separator	SP-1440	3-Phase Horizontal Separator 1440 psi, 42 in x 12 ft	1,440 psi	250 °F	ASME Sec VIII Div 1 / NACE	Yes
Surge Tank	ST-0100	Atmospheric Surge Tank 100 bbl	50 psi	150 °F	API 12F	Yes
Burner	BN-4801	Green Dragon Oil Burner, twin head	—	—	—	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)	0.8319 -	γ_o = 141.5 / (131.5 + °API) 141.5 / (131.5 + 38.6) = 0.8319 API standard gravity definition
Oil rate at target (q_o)	4,836 stb/d	q_o = q_liq × (1 − WC) 6,200 × (1 − 0.220) = 4,836 Test objective
Water rate at target (q_w)	1,364 bbl/d	q_w = q_liq × WC 6,200 × 0.220 = 1,364 Test objective
Associated gas rate (q_g)	1.838 MMscf/d	q_g = q_o × GOR 4,836 × 380 = 1,837,680 scf/d Test objective
Gas-liquid ratio (R)	296 scf/bbl	GLR = q_g / q_liq 1,837,680 / 6,200 = 296 Drives the choke correlation
Blended liquid specific gravity (γ_l)	0.8755 -	γ_l = (1 − WC)·γ_o + WC·γ_w (1 − 0.220)·0.8319 + 0.220·1.0300 = 0.8755 Volume-weighted blend
Pseudo-critical temperature (sweet basis) (T_pc)	380.0 °R	T_pc = 169.2 + 349.5·γ_g − 74.0·γ_g² 169.2 + 349.5(0.7100) − 74.0(0.7100)² = 380.0 Sutton (1985)
Pseudo-critical pressure (sweet basis) (P_pc)	662.0 psia	P_pc = 756.8 − 131.0·γ_g − 3.6·γ_g² 756.8 − 131.0(0.7100) − 3.6(0.7100)² = 662.0 Sutton (1985)
Wichert-Aziz acid gas correction (ε)	3.33 °R	ε = 120(A^0.9 − A^1.6) + 15(B^0.5 − B⁴), A = y_H2S + y_CO2, B = y_H2S A = 0.01908, B = 0.000085 → ε = 3.33 °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)	0.9064 -	Z = A + (1−A)/e^B + C·P_pr^D (Brill & Beggs fit to Standing-Katz) P_pr = 1.372, T_pr = 1.624 → Z = 0.9064 Brill & Beggs (1974)
Gas density at wellhead (ρ_g)	3.111 lb/ft³	ρ_g = 2.70·γ_g·P / (Z·T) 2.70(0.7100)(900) / (0.9064 × 611.7) = 3.111 Real gas law
Oil formation volume factor (B_o)	1.2045 rb/stb	B_o = 0.9759 + 0.00012·[R_s·√(γ_g/γ_o) + 1.25·T]^1.2 R_s = 380, T = 152 °F → B_o = 1.2045 Standing (1947)
Total mass flow rate (ṁ)	83,386 lb/hr	ṁ = ṁ_gas + ṁ_oil + ṁ_water 4,151 + 58,726 + 20,509 = 83,386 lb/hr Mass balance
Gas mass fraction (x_g)	5.0 %	x_g = ṁ_gas / ṁ_total 4,151 / 83,386 = 5.0 % Used to weight the Joule-Thomson coefficient

5.2 Inflow performance

Quantity	Value	Basis and calculation
Rate at bubble point (q_b)	5,280 stb/d	q_b = J × (P_r − P_b) 3.200 × (3,100 − 1,450) = 5,280 Straight-line IPR above bubble point
Absolute open flow potential (q_max)	7,858 stb/d	q_max = q_b + J·P_b / 1.8 5,280 + 3.200(1,450)/1.8 = 7,858 Vogel (1968) composite IPR
Flowing bottomhole pressure required (P_wf)	1,589 psia	q/q_max = 1 − 0.2(P_wf/P_r) − 0.8(P_wf/P_r)² solved for P_wf q = 4,836 stb/d → P_wf = 1,589 psia Vogel (1968)
Drawdown at target rate (ΔP)	1,511 psi	ΔP = P_r − P_wf 3,100 − 1,589 = 1,511 Reservoir management constraint
Fraction of open flow potential	61.5 %	q / q_max 4,836 / 7,858 = 61.5 % Rate feasibility screen

5.3 Pressure integrity

Quantity	Value	Basis and calculation
Maximum anticipated surface pressure (MASP)	2,580 psia	MASP = P_r · exp(−0.01875·γ_g·TVD / (Z̄·T̄)) 3,100 · exp(−0.01875(0.7100)(6,900)/(0.8214 × 609.7)) = 2,580 Compressible static gas column, gas-filled tubing worst case
Minimum equipment rating required	2,839 psia	MAWP_min = MASP × (1 + design margin) 2,580 × (1 + 10%) = 2,839 NESR ES-WT-002 design margin
Rated pressure of weakest upstream item	10,000 psi	min(MAWP) across flowhead, choke manifold and flowline Surface Test Tree 5-1/8 in 10K (FH-5015) = 10,000 psi API 6A / ISO 10423 pressure class
Site pressure test value	2,839 psi	P_test = MASP × test factor 2,580 × 1.10 = 2,839 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)	49 64ths in	d = (A · q_liq · R^B / P_wh)^(1/C) (10.000 × 6,200 × 296^0.546 / 900)^(1/1.890) = 48.60 → 49/64 in Gilbert (1954) multiphase critical flow correlation Rounded up to the nearest available bean in the manifold.
Equivalent bean diameter	0.7656 in	d_in = d / 64 49 / 64 = 0.7656 in
Bean flow area (A)	0.46039 in²	A = π·d²/4 π(0.7656)²/4 = 0.46039 in²
Pressure drop across the bean (ΔP)	650 psi	ΔP = P_wh − P_downstream 900 − 250 = 650 Drives Joule-Thomson cooling and erosion
Downstream / upstream pressure ratio	0.278 -	P_dn / P_up vs critical ratio 250 / 900 = 0.278 (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	48.6	0.7594
Ros (1960)	17.400	0.500	2.000	45.4	0.7098
Baxendell (1957)	9.560	0.546	1.930	43.8	0.6845
Achong (1961)	3.820	0.650	1.880	40.7	0.6366

5.5 Flowline erosional velocity

Quantity	Value	Basis and calculation
Mixture density at flowline conditions (ρ_m)	13.254 lb/ft³	ρ_m = (12409·γ_l·P + 2.7·R·γ_g·P) / (198.7·P + R·T·Z) P = 250 psia, T = 577.7 °R, R = 296 scf/bbl, Z = 0.9692 → 13.254 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 0.40 pptb < 1.0 pptb trigger) API RP 14E + NESR ES-WT-011
Erosional velocity limit (V_e)	34.34 ft/s	V_e = C / √ρ_m 125.0 / √13.254 = 34.34 ft/s API RP 14E
Actual volumetric flow at flowline conditions (q)	1.8143 ft³/s	q = q_gas·B_g/86400 + (q_o·B_o + q_w)·5.615/86400 gas 1.3471 + liquid 0.4672 = 1.8143 ft³/s
Actual mixture velocity (V)	28.14 ft/s	V = q / A, A = π·d²/4 1.8143 / 0.06447 = 28.14 ft/s (3.438 in ID)
Erosional velocity ratio (EVR)	0.820 -	EVR = V / V_e 28.14 / 34.34 = 0.820 Design target ≤ 0.80
Minimum flowline ID to satisfy the limit (d_min)	3.113 in	d_min = √(4q / (π·V_e)) √(4×1.8143 / (π×34.34)) = 3.113 in
Produced solids mass rate	0.103 lb/hr	ṁ_sand = q_liq × sand / 1000 / 24 6,200 × 0.40 / 1000 / 24 = 0.103 lb/hr Sand management trigger

5.6 Joule-Thomson cooling, hydrates and heating

Quantity	Value	Basis and calculation
Effective Joule-Thomson coefficient (μ_JT)	0.00699 °F/psi	μ_JT = x_g·μ_gas + (1 − x_g)·μ_liquid 0.0498(0.0450) + 0.9502(0.0050) = 0.00699 °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)	4.5 °F	ΔT = μ_JT × ΔP 0.00699 × 650 = 4.5 °F Joule-Thomson expansion
Temperature downstream of the bean (T_dn)	147.5 °F	T_dn = T_wh − ΔT 152 − 4.5 = 147.5 °F
Hydrate formation temperature at separator pressure (T_h)	45.5 °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 = 250 psia, γ_g = 0.7100 → T_h = 45.5 °F Motiee (1991)
Minimum process temperature	118.0 °F	T_req = max(T_h + margin, T_separator target) max(45.5 + 10, 118) = 118.0 °F Hydrate margin NESR ES-WT-004; separator target set by emulsion and viscosity control
Heating required	0.0 °F	ΔT_heat = T_req − T_dn 118.0 − 147.5 = 0.0 °F No heating required for this design case.
Process heat duty (Q)	0.000 MMBtu/hr	Q = Σ(ṁ_i · c_p,i) · ΔT (4,151×0.55 + 58,726×0.48 + 20,509×1.00) × 0.0 = 0 Btu/hr Sensible heat balance, GPSA specific heats
Fired duty required	0.000 MMBtu/hr	Q_fired = Q × design factor / thermal efficiency 0.000 × 1.20 / 0.80 = 0.000 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)	0.8558 lb/ft³	ρ_g = 2.70·γ_g·P / (Z·T) P = 250 psia, T = 118 °F, Z = 0.9692 → 0.8558 lb/ft³
Maximum gas velocity before carryover (V_max)	3.171 ft/s	V_max = K·√((ρ_l − ρ_g)/ρ_g) 0.40·√((54.63 − 0.8558)/0.8558) = 3.171 ft/s Souders-Brown, API 12J, K for horizontal vessel with mist extractor
Gas disengagement area	4.811 ft²	A_gas = (1 − fill)·π·D²/4 (1 − 0.50)·π(3.50)²/4 = 4.811 ft² Half-full horizontal vessel design case
Separator gas capacity	20.81 MMscf/d	q_max = V_max · A_gas · 86400 / B_g 3.171 × 4.811 × 86400 / 0.06333 = 20.81 MMscf/d API 12J
Gas capacity utilisation	8.8 %	q_gas / q_max 1.838 / 20.81 = 8.8 %
Liquid volume required for retention	72.52 ft³	V = (q_o·t_o + q_w·t_w) × 5.615 / 1440 (4,836×3.0 + 1,364×3.0) × 5.615 / 1440 = 72.52 ft³ API 12J retention times
Liquid volume available	57.73 ft³	V = fill · π·D²/4 · L 0.50 · π(3.50)²/4 · 12.0 = 57.73 ft³
Separator liquid capacity	4,935 bbl/d	q_max = V_avail / 5.615 × 1440 / t_retention 57.73 / 5.615 × 1440 / 3.0 = 4,935 bbl/d API 12J
Liquid capacity utilisation	125.6 %	V_required / V_available 72.52 / 57.73 = 125.6 %

5.8 Burner thermal radiation

Quantity	Value	Basis and calculation
Total heat release at the burner (Q)	1,155.1 MMBtu/hr	Q = ṁ_oil·LHV_oil + q_gas·LHV_gas 58,726 lb/hr × 18,300 + 76,570 scf/hr × 1,050 = 1,155,081,459 Btu/hr GPSA heating values
Flame length (L)	128.8 ft	L = 0.006 · Q^0.478 0.006 × (1,155,081,459)^0.478 = 128.8 ft API STD 521 Annex C
Fraction of heat radiated (F)	0.200 -	Selected by combustion type Oil burner → F = 0.200 API STD 521 Annex C
Safe distance, continuously manned area (D)	192 ft	D = √(τ·F·Q / (4π·K)) √(1.00 × 0.200 × 1,155,081,459 / (4π × 500)) = 192 ft API STD 521 Table 8, 1.58 kW/m²
Radiation at the planned stand-off (K)	417 Btu/hr·ft²	K = τ·F·Q / (4π·D²) τ·F·Q / (4π × 210²) = 417 Btu/hr·ft² (1.32 kW/m²) API STD 521

Exposure category	Limit	Equivalent	Minimum distance
Continuously manned area	500 Btu/hr·ft²	1.58 kW/m²	192 ft
Escape route, seconds of exposure	1,500 Btu/hr·ft²	4.73 kW/m²	111 ft
Equipment and unmanned areas	2,000 Btu/hr·ft²	6.31 kW/m²	96 ft

5.9 Sour service classification

Quantity	Value	Basis and calculation
H₂S partial pressure at MASP (p_H2S)	0.2193 psia	p_H2S = y_H2S × P (85 / 10⁶) × 2,580 = 0.2193 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
SEP-002	Separator liquid retention capacity critical	FAIL	125.6 % ≤ 85 %	Predicted load exceeds the rated capacity of the selected vessel. Carryover or level control loss is expected. Action required: Select the next size separator, reduce the target rate, or raise separator pressure to shrink gas volume. API SPEC 12J
ERO-001	Erosional velocity in the flowline critical	CAUTION	EVR 0.820 ≤ 0.80	Velocity is at 82 % of the erosional limit. Acceptable for a short test but monitor the sand probe closely. Action required: Select a flowline of at least 3.11 in ID, or reduce the target rate. API RP 14E
SOU-002	H₂S exposure controls major	CAUTION	85 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 0.278 ≤ 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	16.2 % spread below 40 %	The four published correlations disagree by 16.2 % 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	61.5 % 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 1.62 / P_pr 1.37 1.15 < T_pr < 2.4, P_pr < 15	Wellhead conditions are inside the published validity window of the correlation. Brill & Beggs (1974)
HYD-001	Hydrate formation margin downstream of the bean critical	PASS	102.0 °F margin ≥ 10 °F	Stream stays 102.0 °F above the hydrate curve without heating. Motiee (1991) hydrate correlation, NESR ES-WT-004 margin
HYD-002	Heater duty adequacy major	PASS	0.000 MMBtu/hr required 2.50 MMBtu/hr rated	Selected heater covers the fired duty at 0 % utilisation. NESR ES-WT-006
PRS-001	Upstream pressure containment critical	PASS	MASP 2,580 psia MAWP 10,000 psi	Weakest upstream component is rated 10,000 psi against a MASP of 2,580 psia, a margin of 74.2 %. API 6A / NESR ES-WT-002
PRS-002	Separator relief protection critical	PASS	Operating 250 psia MAWP 1,440 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	417 Btu/hr·ft² 500 Btu/hr·ft²	Radiation at the planned stand-off is 83 % of the manned-area limit. API STD 521 Table 8 / IOGP 434-18
SEP-001	Separator gas handling capacity critical	PASS	8.8 % ≤ 85 %	Vessel has adequate capacity for the design case. API SPEC 12J
SOU-001	Sour service material compliance critical	PASS	0.2193 psia H₂S ≥ 0.05 psia triggers sour service	Sour service confirmed at 0.219 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	2,580 psia	Static gas column from reservoir pressure
Site pressure test value	2,839 psi, 15 minute hold	ASME B31.3 / client test procedure
Choke bean, design case	49/64 in	Governed choke correlation
Minimum separator inlet temperature	45 °F + 10 °F margin	Hydrate control
Maximum flowline velocity	34.3 ft/s	API RP 14E erosional limit
Separator operating pressure	250 psia	Design case, PSV set at vessel MAWP
Minimum stand-off, manned areas	192 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, oil burner	0.2 -	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