neqsim-subsea-and-wells

name	neqsim-subsea-and-wells
description	Subsea production systems, DNV-RP-F109 on-bottom stability screening, DNV-RP-F105 free-span screening, DNV-RP-F101 corroded-pipeline screening, well design, SURF cost estimation, and tieback analysis with NeqSim. USE WHEN: designing subsea fields, screening pipeline/cable/umbilical seabed stability or inspected metal loss, sizing flowlines and umbilicals, estimating well costs, performing casing design, running tieback comparisons, or configuring subsea equipment (trees, manifolds, boosters, risers).
last_verified	2026-08-02

NeqSim Subsea & Wells Skill

Reference for subsea production system design, well mechanical design, SURF cost estimation, and tieback analysis using NeqSim.

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Subsea Development Architecture

A typical subsea development consists of:

Reservoir → Wells → Subsea Trees → Jumpers → Manifold → Flowlines → Riser → Host
                                                    ↑
                                            Umbilical (power, control, chemicals)

Equipment Classes in NeqSim

Equipment	NeqSim Class	Package
Subsea well	SubseaWell	process.equipment.subsea
Christmas tree	SubseaTree	process.equipment.subsea
Manifold	SubseaManifold	process.equipment.subsea
Subsea booster	SubseaBooster	process.equipment.subsea
Jumper	SubseaJumper	process.equipment.subsea
Flowline	SimpleFlowLine	process.equipment.subsea
Flexible riser	FlexiblePipe	process.equipment.subsea
Steel/rigid riser	SimpleFlowLine	process.equipment.subsea
Umbilical	Umbilical	process.equipment.subsea
PLET	PLET	process.equipment.subsea
PLEM	PLEM	process.equipment.subsea
Floating production	FloatingSubstructure	process.equipment.subsea
Mooring	MooringSystem	process.equipment.subsea

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Well Design

Casing Design (API 5C3 / NORSOK D-010)

SubseaWell well = new SubseaWell("Producer-1", stream);
well.setWellType(SubseaWell.WellType.OIL_PRODUCER);
well.setCompletionType(SubseaWell.CompletionType.CASED_PERFORATED);
well.setRigType(SubseaWell.RigType.SEMI_SUBMERSIBLE);
well.setWellLocationType(WellCostEstimator.WellLocationType.SUBSEA_WET_TREE);

// Geometry
well.setMeasuredDepth(3800.0);
well.setTrueVerticalDepth(3200.0);
well.setWaterDepth(350.0);
well.setMaxWellheadPressure(345.0);
well.setReservoirPressure(400.0);

// Casing program
well.setConductorOD(30.0);          well.setConductorDepth(100.0);
well.setSurfaceCasingOD(20.0);       well.setSurfaceCasingDepth(800.0);
well.setIntermediateCasingOD(13.375); well.setIntermediateCasingDepth(2500.0);
well.setProductionCasingOD(9.625);    well.setProductionCasingDepth(3800.0);
well.setTubingOD(5.5);
well.setTubingWeight(23.0);
well.setTubingGrade("L80");

// Barrier elements (NORSOK D-010 two-barrier principle)
well.setPrimaryBarrierElements(3);
well.setSecondaryBarrierElements(3);
well.setHasDHSV(true);

// Drilling schedule & costs
well.setDrillingDays(45.0);
well.setCompletionDays(25.0);
well.setRigDayRate(540000.0);

// Mechanical design
well.initMechanicalDesign();
WellMechanicalDesign design = (WellMechanicalDesign) well.getMechanicalDesign();
design.calcDesign();
design.calculateCostEstimate();

// Results
double   design.getProductionCasingBurstDF();     
   design.getProductionCasingCollapseDF(); 
   design.getProductionCasingTensionDF();   
   design.isBarrierVerificationPassed();
   design.getTotalCostUSD();
   design.toJson();

Dry vs Wet Wells

Use WellCostEstimator.WellLocationType to distinguish subsea wet-tree wells from platform dry-tree wells. The same flag is carried by SubseaWell and fed into WellMechanicalDesign.calculateCostEstimate().

SubseaWell wetWell = new SubseaWell("Subsea producer", stream);
wetWell.setWellLocationType(WellCostEstimator.WellLocationType.SUBSEA_WET_TREE);

SubseaWell dryWell = new SubseaWell("Platform producer", stream);
dryWell.setWellLocationType(WellCostEstimator.WellLocationType.PLATFORM_DRY_TREE);

API 5CT Casing Grades

Grade	SMYS (MPa)	Typical Use
H40	276	Conductor
K55	379	Surface casing
N80 / L80	552	Intermediate casing, tubing
C90	621	Sour service (H2S)
P110	758	Production casing (high pressure)
Q125	862	Ultra-deep / HP-HT

NORSOK D-010 Design Factors

Check	Minimum DF	Formula
Burst	1.10	DF = Burst_rating / (P_internal - P_external)
Collapse	1.00	DF = Collapse_rating / (P_external - P_internal)
Tension	1.60	DF = Yield_strength / Axial_load
Triaxial (VME)	1.25	Von Mises equivalent stress check

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SURF Cost Estimation

SURFCostEstimator

SURFCostEstimator surf = new SURFCostEstimator();
surf.setRegion(SubseaCostEstimator.Region.NORWAY);
surf.setNumberOfWells(4);
surf.setWaterDepthM(350.0);          // m
surf.setTreePressureRatingPsi(10000);
surf.setTreeBoreSizeInches(6.0);
surf.setHorizontalTrees(true);
surf.setManifoldSlots(4);
surf.setNumberOfPLETs(2);
surf.setNumberOfPLEMs(1);
surf.setNumberOfJumpers(4);
surf.setJumperLengthM(30.0);
surf.setUmbilicalLengthKm(27.0);
surf.setUmbilicalHydraulicLines(8);
surf.setUmbilicalChemicalLines(2);
surf.setUmbilicalElectricalCables(2);
surf.setIncludeRisers(true);
surf.setFlexibleRiser(true);
surf.setRiserDiameterInches(12.0);
surf.setRiserLengthM(525.0);
surf.setInfieldFlowlineLengthKm(8.0);
surf.setExportPipelineLengthKm(25.0);
surf.setExportPipelineDiameterInches(12.0);
surf.setContingencyPct(0.35);        // FRACTION, not a percent - see the warning below

surf.calculate();
double surfCapex = surf.getTotalSURFCostUSD();
double subseaHardware = surf.getSubseaCostUSD();
double umbilicals = surf.getUmbilicalCostUSD();
double risers = surf.getRiserCostUSD();
double flowlines = surf.getFlowlineCostUSD();
List<Map<String, Object>> lineItems = surf.getLineItems();

WARNING: setContingencyPct takes a FRACTION, not a percent

Despite the Pct in the name, both SURFCostEstimator.setContingencyPct and WellCostEstimator.setContingencyPct multiply the subtotal by the value as given:

est.setContingencyPct(30.0);   // WRONG - contingency = 30 x subtotal
est.setContingencyPct(0.30);   // RIGHT - contingency = 0.30 x subtotal

The symptom is a cost that is roughly 100x too large and still looks internally consistent, e.g. a subsea gas well at 2 295 MUSD instead of 96 MUSD. Always sanity-check the result against getCostBreakdown() / getLineItems(), where the reported contingencyPct field shows the value actually applied.

Regional Cost Factors

Region	Factor	Basis
Norway (NCS)	1.0	Reference
UK (UKCS)	0.85-0.95	Lower labor cost
Gulf of Mexico	0.80-0.90	Established supply chain
Brazil (pre-salt)	1.10-1.30	Deep water, local content
West Africa	1.05-1.20	Logistics premium

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Tieback Analysis

Workflow

1. Define the satellite field (reservoir, fluid, wells)
2. Define candidate host facilities with available capacity
3. Configure tieback options (distance, diameter, insulation, boosting)
4. Screen flow assurance (hydrate margin, arrival temperature, pressure drop)
5. Estimate SURF CAPEX for each option
6. Rank by NPV or unit technical cost

Usage

TiebackAnalyzer analyzer = new TiebackAnalyzer();

// Define host
HostFacility host = new HostFacility("Platform Alpha");
host.setAvailableCapacity(30000.0);   // boe/d spare capacity
host.setProcessingPressure(70.0);     // bara
host.setLocation(61.5, 2.5);         // lat, lon

// Define options
TiebackOption opt1 = new TiebackOption("Direct Tieback");
opt1.setFlowlineLength(15.0);
opt1.setFlowlineDiameter(10.0);
opt1.setWaterDepth(350.0);
opt1.setInsulationType("wet_insulation");

TiebackOption opt2 = new TiebackOption("Boosted Tieback");
opt2.setFlowlineLength(30.0);
opt2.setFlowlineDiameter(12.0);
opt2.setWaterDepth(450.0);
opt2.setHasBooster(true);
opt2.setBoosterType("multiphase_pump");

analyzer.setHost(host);
analyzer.addOption(opt1);
analyzer.addOption(opt2);
analyzer.setFluid(reservoirFluid);

TiebackReport report = analyzer.analyze();
// report contains: pressure drop, arrival temperature, hydrate margin,
// SURF cost, NPV ranking, flow assurance verdict per option

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Subsea System Configuration

Complete Subsea Layout

SubseaProductionSystem subseaSystem = new SubseaProductionSystem("Field Layout");
subseaSystem.setArchitecture(SubseaProductionSystem.SubseaArchitecture.MANIFOLD_CLUSTER);
subseaSystem.setWellCount(6);
subseaSystem.setManifoldCount(2);          // 2 manifolds x 3 wells
subseaSystem.setWaterDepthM(400.0);
subseaSystem.setTiebackDistanceKm(30.0);   // km to host
subseaSystem.setUmbilicalLengthKm(32.0);   // slightly longer routing
subseaSystem.setFlowlineDiameterInches(12.0);
subseaSystem.setTubingDiameterInches(6.0);
subseaSystem.setCostRegion(SubseaCostEstimator.Region.NORWAY);
subseaSystem.setWellLocationType(WellCostEstimator.WellLocationType.SUBSEA_WET_TREE);
subseaSystem.setIncludeRisers(true);
subseaSystem.setFlexibleRiser(true);
subseaSystem.setProductionRiserCount(1);
subseaSystem.setReservoirDevelopmentCostMusd(25.0);
subseaSystem.setReservoirFluid(reservoirFluid);

subseaSystem.build();
subseaSystem.run();

int treeCount = subseaSystem.getTrees().size();
int jumperCount = subseaSystem.getJumpers().size();
int manifoldCount = subseaSystem.getManifolds().size();
int pletCount = subseaSystem.getPLETs().size();
int plemCount = subseaSystem.getPLEMs().size();
int umbilicalCount = subseaSystem.getUmbilicals().size();
int flexibleRiserCount  subseaSystem.getRisers().size();
   subseaSystem.getSteelRisers().size();

SubseaProductionSystem.   subseaSystem.getResult();
   result.getTotalSubseaCapexMusd();
   result.getWellCostMusd();
   result.getReservoirCostMusd();
   result.getTotalDevelopmentCapexMusd();

SubseaProductionSystem.build() creates the main process and design equipment: SubseaWell, SubseaTree, SubseaJumper, SubseaManifold, PLET, PLEM, SimpleFlowLine, Umbilical, and risers. With setFlexibleRiser(true) risers are generated as FlexiblePipe; with setFlexibleRiser(false) steel/rigid risers are generated as vertical SimpleFlowLine unit operations. All of these classes expose mechanical design objects, and SURFCostEstimator includes trees, manifolds, PLETs, PLEMs, jumpers, umbilicals, risers, flowlines, and pipelines in the SURF CAPEX. The result separates SURF, well, reservoir, and total development CAPEX.

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Flowline and Pipeline Sizing

Steady-State Pipe Flow

// Beggs & Brill multiphase correlation
PipeBeggsAndBrills pipeline = new PipeBeggsAndBrills("Export Line", feedStream);
pipeline.setLength(50000.0);           // m
pipeline.setDiameter(0.508);           // m (20 inch)
pipeline.setPipeWallRoughness(5e-5);   // m
pipeline.setAngle(0.0);               // horizontal
pipeline.setNumberOfIncrements(50);

// With formation temperature gradient (subsea/buried)
pipeline.setFormationTemperatureGradient(4.0, -0.03, "C");
// 4°C at seabed, -0.03 °C/m depth gradient

pipeline.run();
double pressureDrop = feedStream.getPressure() - pipeline.getOutletPressure();
double arrivalTemp = pipeline.getOutletTemperature() - 273.15;  // °C

Free-span screening (DNV-RP-F105)

For an explicit current DNV-RP-F105 2025-12 basis, use DnvRpF105FreeSpanScreeningKernel. Supply surveyed span/pipe geometry, a separate hydrodynamic diameter, accepted effective modal mass and axial force, normal current/wave inputs, and verified project response triggers. The kernel reports a simply supported first-mode frequency and common dimensionless groups only.

Do not use PipeMechanicalDesignCalculator.calculateAllowableSpanLength(...) as F105 evidence. It is a legacy fixed-assumption estimate with fallback/cap behavior. Do not turn the typed kernel's caller-controlled response triggers into PASS/FAIL against DNV: soil and span-shoulder stiffness, multi-span interaction, detailed VIV/direct-wave response, ULS/FLS, fatigue, monitoring, and intervention remain a controlled external assessment.

Corroded-pipeline screening (DNV-RP-F101)

For an explicit current DNV-RP-F101 2019-09+AMD:2025-09 basis, use DnvRpF101CorrodedPipelineScreeningKernel only for one verified isolated longitudinal metal-loss defect under internal pressure. Supply assessment wall thickness, measured maximum depth and axial length, caller-controlled depth allowance, characteristic ultimate tensile strength, internal/external absolute pressures, and a verified project-controlled pressure factor.

Keep interacting/complex defects, combined longitudinal compression, probabilistic and inspection- accuracy models, corrosion growth, crack/dent/gouge/blister or weld damage, repair, inspection interval, and fitness-for-service approval external. M-506 rate prediction is not inspected defect sizing. RP-F101 does not replace DNV-ST-F101 pressure containment, collapse, propagation/local buckling, interaction, fatigue, pressure cases, de-rating, safety class, ovality, fabrication, or installation-strain checks.

Pipeline Mechanical Design

AdiabaticPipe pipe = new AdiabaticPipe("Pipeline", feedStream);
pipe.setLength(50000.0);
pipe.setDiameter(0.508);

PipelineMechanicalDesign mechDesign =
    (PipelineMechanicalDesign) pipe.getMechanicalDesign();
mechDesign.setMaxOperationPressure(150.0);
mechDesign.setMaterialGrade("X65");
mechDesign.setDesignStandardCode("DNV-OS-F101");
mechDesign.calcDesign();

double wallThickness = mechDesign.getWallThickness();  // mm
String report = mechDesign.toJson();

DNV-RP-F109 On-Bottom Stability Screening

Use DnvRpF109OnBottomStabilityKernel for typed, fail-closed vertical and lateral screening of a pipeline, cable, or umbilical. The exact supported edition is 2021-05+AMD 2025-09. Supply every project coefficient, factor, soil resistance, environmental load case, and submerged weight explicitly; there are no numerical project defaults.

Build DnvRpF109OnBottomStabilityInput with the exact edition, matching asset and equipment types, geometry, engineering-basis reference, and one or more explicit LoadCase values. Call DnvRpF109OnBottomStabilityKernel.calculate(input, context) and retain its readiness findings and full input provenance. See docs/process/dnv_rp_f109_on_bottom_stability.md for the complete Java pattern.

The absolute-static route calculates normal Morison drag/inertia and lift, then checks vertical equilibrium and horizontal demand against friction plus explicit passive soil resistance. External-response routes check supplied displacement at 0.5D, 10D, or a project limit, and require affirmative response-model validity plus a traceable basis. NeqSim does not reproduce generalized design tables, generate dynamic response, qualify pipe-soil inputs, or claim DNV conformity. Treat every result, including a pass, as CALCULATED_REVIEW_REQUIRED.

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Flowline Cooldown and No-Touch Time

After a planned or unplanned shutdown, an insulated subsea flowline or riser cools toward the seabed temperature. The no-touch time is how long operators can wait before the fluid reaches the hydrate formation temperature (plus a safety margin) and remedial action (depressurization, MEG/methanol injection) is required. NeqSim couples a live fluid to a lumped cooldown engine with SurfCooldownAnalyzer.

// Live fluid carries composition; analyzer auto-extracts density, Cp, hydrate Teq
SurfCooldownAnalyzer analyzer = new SurfCooldownAnalyzer(fluid);  // SystemInterface
analyzer.setInternalDiameter(0.254);        // m
analyzer.setWallThickness(0.0159);          // m
analyzer.setInsulationThickness(0.060);     // m
analyzer.setInsulationConductivity(0.17);   // W/m·K (wet insulation, PP foam)
analyzer.setSeabedTemperature(4.0);         // °C
analyzer.setHydrateMargin(3.0);             // K above hydrate Teq
analyzer.setRequiredNoTouchTimeHours(8.0);  // operational target (optional)

// Either give an overall U-value directly, or let the layer model compute it:
analyzer.setOverallUValue(2.5);             // W/m²·K  (skip for layer calc)

analyzer.calculate();
double noTouch = analyzer.getNoTouchTimeHours();
String verdict = analyzer.getVerdict();     // OK / MARGINAL / CRITICAL / NO_HYDRATE_RISK
double hydrateTeqC = analyzer.getHydrateEquilibriumTemperatureK() - 273.15;
double tau = analyzer.getTimeConstantHours();
String json = analyzer.toJson();

How it works:

• Clones the fluid, runs TPflash + initProperties, and reads getDensity("kg/m3") and getCp("J/kgK") for the lumped thermal mass.
• Computes the hydrate equilibrium temperature via hydrateFormationTemperature(). If the fluid has no free water (no hydrate risk), the verdict is NO_HYDRATE_RISK.
• Delegates the transient to PipelineCooldownCalculator (exponential lumped cooldown, layer or direct U-value). No-touch time is the time to reach hydrateTeq + margin.
• Verdict bands: with a required no-touch time, OK ≥ required, MARGINAL ≥ 0.75×, else CRITICAL. Without one, OK ≥ 12 h, MARGINAL ≥ 6 h, else CRITICAL.

Basis: project thermal-management requirements and API RP 17A subsea-system context. DNV-RP-F109 is an on-bottom stability document and is not a cooldown or no-touch-time basis. This is a screening-level lumped model — use a distributed transient thermal-hydraulic tool for detailed design.

package: neqsim.pvtsimulation.flowassurance — SurfCooldownAnalyzer, PipelineCooldownCalculator.

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Artificial Lift Screening

ArtificialLiftScreener alScreener = new ArtificialLiftScreener();
alScreener.setReservoirPressure(250.0);     // bara
alScreener.setWaterDepth(350.0);
alScreener.setGOR(200.0);                   // Sm3/Sm3
alScreener.setWaterCut(0.30);
alScreener.setDepth(3000.0);                // m TVD
alScreener.setProductionRate(5000.0);       // boe/d

// Screen all methods
Map<String, String> recommendations = alScreener.screen();
// Returns: {"ESP": "RECOMMENDED", "Gas Lift": "FEASIBLE",
//           "Rod Pump": "NOT_RECOMMENDED", ...}

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Gas Lift Design

GasLiftCalculator gasLift = new GasLiftCalculator();
gasLift.setWellDepth(3000.0);
gasLift.setReservoirPressure(250.0);
gasLift.setProductionRate(5000.0);
gasLift.setGLR(500.0);                    // Sm3/Sm3
gasLift.setInjectionPressure(150.0);      // bara

double optimalGLR = gasLift.calculateOptimalGLR();
double injectionRate = gasLift.calculateInjectionRate();

// Multi-well gas lift optimization
GasLiftOptimizer optimizer = new GasLiftOptimizer();
optimizer.addWell(well1, gasLift1);
optimizer.addWell(well2, gasLift2);
optimizer.setTotalGasAvailable(500000.0);  // Sm3/d
Map<String, Double> allocation = optimizer.optimize();

For a choke-back / open-up decision across a well fleet under multiple shared facility ceilings (gas handling + produced-water/PWRI + lift-gas budget) with discrete on/off locks, use ChokeAndGasLiftAllocationOptimizer + StrupeOkeReport (neqsim.process.fielddevelopment.integrated). Build each well's response with GasLiftPerformanceCurve.fromWellSystem(...). See the neqsim-production-optimization skill for the full pattern.

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Design Standards Reference

Domain	Standard	Used For
Casing design	API 5CT / ISO 11960	Casing/tubing grades, SMYS
Casing formulas	API Bull 5C3 / TR 5C3	Burst, collapse, tension
Well barriers	NORSOK D-010	Design factors, two-barrier principle
Submarine pipelines	DNV-ST-F101	Pressure containment and structural limit states
On-bottom stability	DNV-RP-F109	Vertical stability, absolute lateral stability, displacement acceptance
Process piping	ASME B31.3	Onshore/topsides piping
Pressure vessels	ASME VIII Div.1/2	Separator, vessel sizing
Subsea production	API 17A-17Q	Subsea equipment specs
Risers	API 2RD / DNV-OS-F201	Riser design
Flowlines	DNV-RP-F105 2025-12	Use DnvRpF105FreeSpanScreeningKernel for first-mode/dimensionless escalation screening; retain detailed response and acceptance externally
Corroded flowlines/risers	DNV-RP-F101 2019-09+AMD:2025-09	Use DnvRpF101CorrodedPipelineScreeningKernel only for verified isolated longitudinal metal loss under internal pressure; retain full integrity assessment and ST-F101 design checks externally
Fatigue	DNV-RP-C203	S-N curves, fatigue life

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Common Subsea Design Pitfalls

Pitfall	Impact	Prevention
Ignoring hydrate sub-cooling margin	Hydrate blockage	Design for 3-6°C subcooling below hydrate T
Undersized flowline (low rate sensitivity)	Cannot achieve design rate	Size for peak + 20% surge capacity
Missing umbilical in cost estimate	10-15% CAPEX underestimate	Always include umbilical with routing factor 1.1×
Wrong water depth for cost curve	Non-physical costs	Verify depth matches field data
Ignoring slugging in riser	Separator flooding, trips	Include slug catcher sizing, check riser stability
No pipeline end expansion	Structural failure	Account for thermal expansion, expansion loops