Flow Assurance Overview

Flow assurance combines fluid characterization, thermodynamics, transport models, operating scenarios, and laboratory or field evidence. NeqSim can calculate several inputs to that assessment, but no single result establishes that a line is safe, restartable, corrosion resistant, or free from deposition.

Use this page to select a screening calculation. Follow the model-specific guides before using a result in design or operations.

What NeqSim calculates

Topic	Supported calculation	Result does not establish
Hydrates	Equilibrium formation temperature or pressure for a specified fluid and thermodynamic inhibitor composition	Formation time, plugging probability, transportability, or inhibitor dosage
Wax	Wax appearance and wax-fraction calculations for a characterized fluid	Deposition rate, gel strength, restart pressure, pigging interval, or chemical performance
Asphaltenes	De Boer empirical screening and configured thermodynamic onset or stability models	A universal onset pressure or deposition rate without fluid-specific calibration
Mineral scale	Saturation indices from specified water chemistry and conditions	Precipitation kinetics, deposited mass, adhesion, or treatment dose
Corrosion	Screening correlations and process-coupled corrosion calculations	Materials qualification, sour-service compliance, or remaining life
Pipelines	Selected steady-state, cooldown, transient, erosion, and multiphase calculations	Qualification of every slugging, restart, erosion, or integrity scenario

A capability in this table is a calculation method, not an engineering approval. Validate the fluid model and inputs over the pressure, temperature, composition, salinity, and phase range of interest.

Executable first screen

The following complete Java 8 program runs three independent screens. It uses:

a hydrate equilibrium calculation for a specified gas, water, MEG, and salt mixture;
the repository’s De Boer implementation, using absolute pressure in bar and in-situ oil density in kg/m3;
mineral saturation indices from explicit produced-water chemistry in mg/L.

import neqsim.pvtsimulation.flowassurance.DeBoerAsphalteneScreening;
import neqsim.pvtsimulation.flowassurance.DeBoerAsphalteneScreening.DeBoerRisk;
import neqsim.pvtsimulation.flowassurance.ScalePredictionCalculator;
import neqsim.thermo.system.SystemElectrolyteCPAstatoil;
import neqsim.thermo.system.SystemInterface;
import neqsim.thermodynamicoperations.ThermodynamicOperations;

public class FlowAssuranceScreen {
    public static void main(String[] args) throws Exception {
        SystemInterface hydrateFluid =
            new SystemElectrolyteCPAstatoil(273.15 + 10.0, 50.0);
        hydrateFluid.addComponent("water", 0.494505);
        hydrateFluid.addComponent("MEG", 0.164835);
        hydrateFluid.addComponent("methane", 0.247253);
        hydrateFluid.addComponent("ethane", 0.0164835);
        hydrateFluid.addComponent("propane", 0.010989);
        hydrateFluid.addComponent("i-butane", 0.00549451);
        hydrateFluid.addComponent("n-butane", 0.00549451);
        hydrateFluid.addComponent("Na+", 0.0274725);
        hydrateFluid.addComponent("Cl-", 0.0274725);
        hydrateFluid.setMixingRule(10);
        hydrateFluid.setMultiPhaseCheck(true);
        hydrateFluid.setHydrateCheck(true);

        ThermodynamicOperations hydrateOps =
            new ThermodynamicOperations(hydrateFluid);
        hydrateOps.hydrateFormationTemperature();
        double hydrateTemperatureC = hydrateFluid.getTemperature("C");

        DeBoerAsphalteneScreening asphalteneScreen =
            new DeBoerAsphalteneScreening(350.0, 150.0, 750.0);
        DeBoerRisk asphalteneRisk = asphalteneScreen.evaluateRisk();
        double asphalteneRiskIndex = asphalteneScreen.calculateRiskIndex();

        ScalePredictionCalculator scaleScreen =
            new ScalePredictionCalculator();
        scaleScreen.setTemperatureCelsius(80.0);
        scaleScreen.setPressureBara(100.0);
        scaleScreen.setCalciumConcentration(400.0);
        scaleScreen.setBariumConcentration(10.0);
        scaleScreen.setStrontiumConcentration(5.0);
        scaleScreen.setIronConcentration(2.0);
        scaleScreen.setMagnesiumConcentration(1300.0);
        scaleScreen.setSodiumConcentration(11000.0);
        scaleScreen.setBicarbonateConcentration(150.0);
        scaleScreen.setSulphateConcentration(10.0);
        scaleScreen.setTotalDissolvedSolids(35000.0);
        scaleScreen.setCO2PartialPressure(2.0);
        scaleScreen.enableAutoPH();
        scaleScreen.calculate();

        System.out.printf(
            "Hydrate equilibrium temperature: %.2f °C%n",
            hydrateTemperatureC);
        System.out.printf(
            "De Boer screen: %s; risk index %.3f%n",
            asphalteneRisk,
            asphalteneRiskIndex);
        System.out.printf(
            "Calcite SI: %.3f; barite SI: %.3f; any scale flag: %s%n",
            scaleScreen.getCaCO3SaturationIndex(),
            scaleScreen.getBaSO4SaturationIndex(),
            scaleScreen.hasScalingRisk());
    }
}

For the stated De Boer inputs, the current implementation returns MODERATE_PROBLEM and a risk index of 1.6. The hydrate and scale results are case-specific. Do not transfer them to another fluid or water analysis.

The example intentionally lets calculation errors propagate. A failed equilibrium calculation is not evidence that no hydrate or scale risk exists.

Interpret the three results

Hydrate equilibrium

For a pipeline point at operating temperature $T_{op}$, define thermodynamic subcooling as:

\[\Delta T_{sub} = T_{eq} - T_{op}\]

A positive value means the operating point is below the calculated hydrate equilibrium temperature. It identifies thermodynamic stability, not nucleation time, growth rate, plugging probability, or acceptable operating margin. Preserve mass- versus-mole-fraction distinctions when preparing inhibitor and salt inputs.

See the hydrate models guide for model selection and the screening tools for profile calculations.

De Boer asphaltene screen

DeBoerAsphalteneScreening evaluates the repository’s implemented boundary curves using reservoir pressure, saturation pressure, and in-situ oil density. Do not replace it with a pressure-difference times asphaltene-content heuristic. Confirm a flagged case with measured onset or precipitation data and a calibrated model.

Use the De Boer guide, then select a thermodynamic or empirical method through the asphaltene overview. A phase count greater than two does not by itself identify an asphaltene-rich phase; inspect the phase type and the configured model.

Mineral-scale saturation index

The screening calculator reports:

\[SI = \log_{10}\left(\frac{IAP}{K_{sp}}\right)\]

Positive SI indicates supersaturation in the calculator. It does not predict how quickly a mineral precipitates, how much adheres to equipment, or the required chemical dose. Use representative water analyses, mixing ratios, dissolved-gas conditions, and uncertainty ranges.

Continue with mineral-scale formation, scale-prediction API details, and mineral-scale treatment validation.

Build a governed flow-assurance study

Define cases. Include normal operation, turndown, start-up, shutdown, cooldown, depressurization, restart, water breakthrough, composition uncertainty, and credible equipment/control states.
Characterize fluids and waters. Record sampling conditions, compositional basis, heavy-end characterization, salinity, ion analyses, inhibitor basis, and data quality.
Calculate profiles. Determine pressure, temperature, phase fractions, water availability, velocities, and residence times before applying local screening models.
Screen each mechanism. Use the hydrate, wax, asphaltene, scale, corrosion, erosion, emulsion, and transient tools only where their required inputs and applicability are satisfied.
Validate and quantify margins. Compare with laboratory measurements, field history, model uncertainty, and sensitivity cases.
Assess mitigation. Model the applicable thermodynamic or hydraulic effect; obtain chemical performance, materials, operability, and mechanical evidence from the accountable disciplines.
Record decisions. Preserve model versions, assumptions, units, input provenance, convergence status, limitations, and required expert review.

Model and mitigation boundaries

Decision	NeqSim contribution	Additional evidence required
MEG or methanol strategy	Hydrate equilibrium with specified composition	Injection basis, partitioning, regeneration, losses, kinetics, operability, and vendor data
Insulation or active heating	Thermal and hydraulic scenarios	Detailed heat-transfer design, installation, degradation, controls, and transient qualification
Wax management	WAT and wax-fraction screening	Deposition/gel testing, restart hydraulics, pigging and chemical qualification
Asphaltene management	Empirical screen or calibrated onset/stability model	Fluid-specific laboratory data, deposition behavior, and chemical qualification
Scale management	Saturation tendency and water-mixing scenarios	Kinetics, precipitation/deposition tests, treatment compatibility, dose and monitoring
Corrosion/materials	Screening rate and process-condition inputs	Applicable standard assessment, wall condition, materials, inspection, and integrity review
Depressurization or restart	Process/pipeline transient scenarios	Safeguarding, flare/blowdown capacity, controls, procedures, and multidisciplinary approval

Do not infer sour-service requirements from bulk H2S mole fraction alone. Do not infer carbonate-scale or corrosion acceptability from bulk CO2 and water fractions. Those decisions require phase-specific conditions and the applicable materials, chemistry, integrity, and standards workflows.