| 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.
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 |
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);
well.setMeasuredDepth(3800.0);
well.setTrueVerticalDepth(3200.0);
well.setWaterDepth(350.0);
well.setMaxWellheadPressure(345.0);
well.setReservoirPressure(400.0);
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");
well.setPrimaryBarrierElements(3);
well.setSecondaryBarrierElements(3);
well.setHasDHSV(true);
well.setDrillingDays(45.0);
well.setCompletionDays(25.0);
well.setRigDayRate(540000.0);
well.initMechanicalDesign();
WellMechanicalDesign design = (WellMechanicalDesign) well.getMechanicalDesign();
design.calcDesign();
design.calculateCostEstimate();
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 |
SURF Cost Estimation
SURFCostEstimator
SURFCostEstimator surf = new SURFCostEstimator();
surf.setRegion(SubseaCostEstimator.Region.NORWAY);
surf.setNumberOfWells(4);
surf.setWaterDepthM(350.0);
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);
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);
est.setContingencyPct(0.30);
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 |
Tieback Analysis
Workflow
- Define the satellite field (reservoir, fluid, wells)
- Define candidate host facilities with available capacity
- Configure tieback options (distance, diameter, insulation, boosting)
- Screen flow assurance (hydrate margin, arrival temperature, pressure drop)
- Estimate SURF CAPEX for each option
- Rank by NPV or unit technical cost
Usage
TiebackAnalyzer analyzer = new TiebackAnalyzer();
HostFacility host = new HostFacility("Platform Alpha");
host.setAvailableCapacity(30000.0);
host.setProcessingPressure(70.0);
host.setLocation(61.5, 2.5);
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();
Subsea System Configuration
Complete Subsea Layout
SubseaProductionSystem subseaSystem = new SubseaProductionSystem("Field Layout");
subseaSystem.setArchitecture(SubseaProductionSystem.SubseaArchitecture.MANIFOLD_CLUSTER);
subseaSystem.setWellCount(6);
subseaSystem.setManifoldCount(2);
subseaSystem.setWaterDepthM(400.0);
subseaSystem.setTiebackDistanceKm(30.0);
subseaSystem.setUmbilicalLengthKm(32.0);
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.
Flowline and Pipeline Sizing
Steady-State Pipe Flow
PipeBeggsAndBrills pipeline = new PipeBeggsAndBrills("Export Line", feedStream);
pipeline.setLength(50000.0);
pipeline.setDiameter(0.508);
pipeline.setPipeWallRoughness(5e-5);
pipeline.setAngle(0.0);
pipeline.setNumberOfIncrements(50);
pipeline.setFormationTemperatureGradient(4.0, -0.03, "C");
pipeline.run();
double pressureDrop = feedStream.getPressure() - pipeline.getOutletPressure();
double arrivalTemp = pipeline.getOutletTemperature() - 273.15;
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();
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.
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.
SurfCooldownAnalyzer analyzer = new SurfCooldownAnalyzer(fluid);
analyzer.setInternalDiameter(0.254);
analyzer.setWallThickness(0.0159);
analyzer.setInsulationThickness(0.060);
analyzer.setInsulationConductivity(0.17);
analyzer.setSeabedTemperature(4.0);
analyzer.setHydrateMargin(3.0);
analyzer.setRequiredNoTouchTimeHours(8.0);
analyzer.setOverallUValue(2.5);
analyzer.calculate();
double noTouch = analyzer.getNoTouchTimeHours();
String verdict = analyzer.getVerdict();
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.
Artificial Lift Screening
ArtificialLiftScreener alScreener = new ArtificialLiftScreener();
alScreener.setReservoirPressure(250.0);
alScreener.setWaterDepth(350.0);
alScreener.setGOR(200.0);
alScreener.setWaterCut(0.30);
alScreener.setDepth(3000.0);
alScreener.setProductionRate(5000.0);
Map<String, String> recommendations = alScreener.screen();
Gas Lift Design
GasLiftCalculator gasLift = new GasLiftCalculator();
gasLift.setWellDepth(3000.0);
gasLift.setReservoirPressure(250.0);
gasLift.setProductionRate(5000.0);
gasLift.setGLR(500.0);
gasLift.setInjectionPressure(150.0);
double optimalGLR = gasLift.calculateOptimalGLR();
double injectionRate = gasLift.calculateInjectionRate();
GasLiftOptimizer optimizer = new GasLiftOptimizer();
optimizer.addWell(well1, gasLift1);
optimizer.addWell(well2, gasLift2);
optimizer.setTotalGasAvailable(500000.0);
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.
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 |
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 |
