Hydrate plugs, severe slugging, wax deposition, scale, sand transport, and water hammer - every flow assurance threat has a solution. We have built and validated those solutions on Shah Deniz 2, BP Angola Block 18, ACG Azerbaijan, and deepwater Malaysia.
Every one of these threats is predictable from the fluid properties, the pipeline geometry, and the operating envelope. That means every one of them can be designed out - if the engineering is done correctly at the right project stage.
A single hydrate blockage in a deepwater flowline stops production for weeks, demands specialist coiled tubing intervention, and carries real well-integrity risk. Safe shut-in time, cooldown analysis, MEG/methanol dosing, and restart procedures must all be validated from first steel - not first oil.
Remediation per event: $5M - $80MTerrain and riser slugs trip topsides separators, flare valuable gas, and erode equipment life. A separator that cannot absorb the slug volume defined by the OLGA model will trip every time. This is the most common hidden constraint on production throughput - invisible in steady-state models.
Throughput loss: 5 - 25% MMSCFDResuming production through a cold, wax-gelled or hydrate-risk flowline without a validated restart procedure risks a well shut-in that becomes a permanent plug. Restart simulations - hot and cold - must define the safe operating envelope, the inhibitor volumes, and the ramp-up rate. Guesswork is not acceptable.
Unplanned plug: $2M - $30MBelow the Wax Appearance Temperature, paraffin deposits progressively restrict the flow cross-section and drive pigging frequency beyond what operations can sustain. Without a validated WAT, deposition model, and pigging strategy, wax management becomes reactive - and reactive is expensive.
Pipeline plug remediation: $2M - $30MA pump trip or rapid valve closure on a high-pressure water injection system generates pressure transients that rupture pipework and collapse check valves. AFT Impulse surge analysis and correct surge vessel sizing are not optional scope - they are a fundamental pressure containment obligation.
Incident repair: $1M - $20MWells that produce sand below the minimum transport velocity accumulate beds that progressively restrict flow, corrupt pig passages, and drive wall loss at bends. Establishing the minimum transport velocity from first principles - and designing the operating envelope around it - is the difference between a manageable system and one that fails in year one.
Pipeline failure: $10M - $50M+Every NIQ flow assurance study is governed and quality-assured at doctoral level. We translate complex OLGA outputs, thermodynamic models, and transient simulation results into clear, auditable production KPIs for asset managers, project directors, and HSE authorities - balancing technical integrity, CAPEX/OPEX optimisation, and production availability with quantified risk. Independent peer review, design audits, and expert witness services available.
These are the twelve flow assurance scope elements we deliver completely - the same items BP, TotalEnergies, Shell, and ENI require on their most demanding studies. Each is a standalone deliverable with a formal study report.
Wellhead-to-manifold sizing, temperature and pressure profiling, liquid handling capacity, gas velocity compliance (<=20 m/s), and parametric studies for additional wells and late-life water cut scenarios.
OLGA-based cooldown of jumpers, flowlines, and risers. Hydrate formation time determination, safe shut-in time window, insulation optimisation for active and passive thermal management systems.
Terrain and riser slugging characterisation, slug catcher sizing, active slug control strategy assessment, and impact of additional wells on topsides separator receiving capacity.
Maximum liquid surge volume calculations, separator and slug catcher sizing, interface level control assessment, and brownfield debottlenecking for liquid handling systems.
WAT/WDT determination from fluid characterisation, deposition rate modelling, pigging interval optimisation, gel formation risk, and restart pressure assessment after extended shutdowns.
MEG/methanol injection rate design, distribution hydraulic modelling across multiple injection points, dosing optimisation against CAPEX/OPEX trade-offs, and storage/regeneration facility sizing.
Dosage calculation, storage volume requirements, injection ramp-up profiles, and verification of distribution to all subsea isolation points before and during restart operations.
Minimum transport velocity using field analogue methods, sand accumulation risk at reduced flow, erosional velocity ratio compliance, and sand monitoring strategy.
Slugging behaviour during designed well ramp-up sequences, thermal recovery profiles, separator surge arrival timing, and operating procedure development for controlled restart.
Thermal and hydraulic performance during unplanned cold restart, hydrate window analysis, depressurisation requirements, back-pressure management, and minimum restart flow conditions.
Consistency check of field operating philosophy against all flow assurance findings. Operating envelope definition, alarm/trip setpoint recommendations, and operator guidance documentation.
Pump trip, valve closure, and water hammer transient analysis using AFT Impulse. Surge vessel sizing, check valve dynamics, and pipeline pressure rating verification. Full surge report.
Our flow assurance work spans every production environment - from ultra-deepwater subsea tiebacks to onshore slug catchers. We follow the fluid from reservoir to export.
Subsea systems demand the most rigorous flow assurance philosophy. Remoteness, deepwater pressures, low seabed temperatures, and the impossibility of rapid intervention mean that every failure mode must be anticipated and designed out at FEED. Shah Deniz 2 and Block 18 Angola are the benchmark - we have worked on both.
FPSO and fixed platform flow assurance is dominated by the interface between subsea transient behaviour and topsides processing capacity. An OLGA slug model that hasn't been sized against the separator is not a flow assurance model - it is a theoretical exercise. We integrate both.
Topsides flow assurance covers the interface between the subsea system and the processing train - particularly slug catcher and separator sizing, active slug control, compressor stability, and chemical injection distribution. Getting this interface wrong produces a topsides that trips every time the subsea slugs.
Onshore gathering systems, trunklines, and long-distance gas pipelines present distinct flow assurance challenges - particularly around slug catchers, water injection surge, pigging strategy, and terrain slugging in hilly terrain. We have applied these studies on Nigerian, Mozambican, and UAE onshore assets.
Our Senior Flow Assurance Consultant has 18+ post-doctoral years working on some of the world's most complex deepwater assets - and personally executes every scope.
PhD | 18+ Years Post-Doctoral Industry Experience
Doctor of Philosophy - Multiphase Flow and Thermodynamics | Expert OLGA Practitioner | Versatile in HYSYS, PIPESIM, and process engineering tools
With 18+ years of post-PhD industry experience, this consultant combines deep academic rigour in multiphase flow thermodynamics with hands-on delivery on some of the world's most technically demanding assets. A recognised OLGA authority and co-simulation architect who is equally versed in process engineering tools - making him uniquely capable of integrating flow assurance findings directly into topsides process design and bridging the gap between simulation and operations.
All platforms below have been applied on live IOC projects, validated against field data and client reference models.
| Tool / Platform | Proficiency | Primary Application |
|---|---|---|
| OLGA | Expert | Transient multiphase flow - cooldown, hydrate window, slugging, hot/cold restart, pigging. Shah Deniz 2, Block 18 Angola, ACG, Malaysia validated models. |
| LedaFlow | Advanced | 3-fluid transient simulation, riser dynamics, slug frequency and volume characterisation. |
| PVTsim Nova | Advanced | Fluid characterisation, EOS tuning, hydrate equilibrium curves, wax appearance temperature determination. |
| Multiflash | Advanced | Phase equilibria, wax, asphaltene, scale and hydrate thermodynamics - fluid property inputs to OLGA. |
| PIPESIM | Proficient | Steady-state hydraulic and thermal profiling, line sizing, nodal analysis, operating envelope definition. |
| HYSYS / UniSim | Proficient | Process simulation for topsides integration - separator sizing, compression, co-simulation with OLGA. |
| AFT Impulse | Proficient | Water injection surge analysis, pump trip transients, accumulator sizing, check valve dynamics. |
| K-Spice / UniSim OTS | Working knowledge | Control system dynamics and operator training system development integrated with OLGA. |
Co-simulation capability: NIQ links OLGA/LedaFlow with HYSYS/UniSim dynamics - enabling simultaneous modelling of subsea pipelines, risers, topsides separators, and compression trains. This is the foundation for true digital twins and operator training systems that faithfully represent the real asset under all transient scenarios - including emergency shutdown, cold restart, and slug events.
These are not references from a proposal template. They are assets where our engineer was the flow assurance lead - and where the work is still operational today.
BP - Caspian Sea, Azerbaijan
One of the world's largest and most complex deepwater gas developments. Full-scope flow assurance from FEED through commissioning - OLGA transient cooldown, hydrate management philosophy for infield and export pipelines, riser dynamics, and subsea-to-topsides co-simulation for the South Caucasus Pipeline system. Chemical injection operating guidelines for all shutdown and restart scenarios.
ENI / BP - Offshore Angola
Deepwater subsea development in Block 18 offshore Angola. Flow assurance encompassing HPHT wellhead conditions, severe slugging characterisation and mitigation, ultra-deepwater wax management for long-distance flowlines where seabed temperatures drive wax deposition risk, and full FPSO topsides integration with the transient subsea model.
BP - Azerbaijan, Caspian Sea
Flow assurance support for the ACG field - one of the world's largest offshore oil fields. Integrated subsea and topsides transient modelling across a complex multi-platform, multi-pipeline production system. Operational performance optimisation and production envelope verification using OLGA models validated against field production data.
BP / Operator - Offshore Malaysia
Flow assurance for deepwater gas field development offshore Malaysia. OLGA-based transient modelling of subsea flowlines in high water-depth conditions where thermal performance is critical to hydrate management. MEG injection system design for multi-well development. Operating envelope definition and commissioning support for first gas delivery.
Our Lead Process Engineer covers P&IDs, HYSYS simulation, HAZOP facilitation, flare and relief system design, equipment sizing, and pre-commissioning - on Shah Deniz 2, ADNOC, Saudi Aramco, TotalEnergies, Shell, and ExxonMobil assets. Both disciplines, one team.
Complete field development flow assurance studies, specific transient simulations, independent peer review, operational troubleshooting - delivered by a PhD engineer who has personally worked on equivalent assets at BP, ENI, and operator level.