Once hydrocarbons reach the platform, the mixed well stream is routed through a train of processing steps to make oil, gas and water fit for export or disposal. Typically, production passes through wellhead chokes and manifolds, then into high-pressure separators where gas is flashed off and liquids are split. Further stages include secondary and sometimes tertiary separation, crude oil stabilisation, dehydration and desalting, produced-water treatment, and gas treatment (dehydration, sweetening, hydrocarbon dew-point control) followed by compression for export or reinjection. Throughout, extensive use of chemical injection, heating/cooling, and pressure control is used to prevent corrosion, hydrate formation, and foaming, while instrumentation and control systems keep the process within safe operating limits.
Primary separation happens in large pressure vessels called production separators, usually operated at high pressure close to wellhead conditions. When the multiphase well stream enters, the sudden reduction in velocity and carefully designed internals allow gas to disengage and rise, while liquids fall and separate by density into oil and water layers. Gravity separation is enhanced by baffles, inlet devices, coalescers and level control systems. Gas exits from the top to further treatment and compression, oil from the middle to downstream separators and stabilisation, and produced water from the bottom to water-treatment systems. Operators use level controllers, pressure control valves and interface measurements to maintain separation efficiency and avoid carry-over or carry-under, which would otherwise compromise downstream equipment and export specifications. Ref
Stabilisation reduces the vapour pressure of produced crude so it can be safely stored and transported without excessive gas breakout or cavitation in pumps. Offshore, this is commonly achieved by passing oil through a series of separators at progressively lower pressures and sometimes through dedicated stabiliser columns. Each pressure step flashes off light hydrocarbons, which are routed to gas compression, while heating and residence time help drive off remaining volatile components. The goal is to meet Reid Vapour Pressure or True Vapour Pressure limits set by export pipelines, shuttle tankers or FPSOs. Properly stabilised crude minimises emissions and safety risks in storage and offloading operations, while also improving measurement accuracy for custody transfer and reducing downstream processing issues.
Produced water is the aqueous phase separated from the well stream, containing dispersed oil, dissolved organics, salts, solids and treatment chemicals. Offshore, it is typically treated in several steps to meet overboard-discharge or reinjection standards. After bulk removal in primary separators, water may pass through hydrocyclones, flotation units (induced gas flotation, dissolved gas flotation) and coalescing filters to reduce oil-in-water to ppm-level regulatory limits. Additional polishing stages, such as membrane filtration or adsorption, can be applied where regulations are strict or where water is reused for injection or EOR. Sand removal, scaling control and corrosion inhibition must be managed in parallel. The final route is usually overboard discharge within environmental limits or reinjection into disposal or pressure-maintenance wells. Ref
Associated gas separated from crude is a valuable product and a critical utility. First, it is cooled and scrubbed to remove liquids and solids, then dehydrated to prevent hydrates and corrosion in pipelines. Sweetening may be required to remove H₂S and CO₂ using amine units or similar processes. Hydrocarbon dew-point control (via chilling or expansion) ensures heavier components don’t condense in export lines. Depending on field strategy, conditioned gas is then used as fuel gas on the facility, injected back into the reservoir for pressure support or gas lift, exported via pipeline, or processed further (e.g., NGL recovery, FLNG). Compression stages between these steps raise the pressure to pipeline or injection requirements while safeguarding equipment integrity and efficiency. Ref
Gas compression raises the pressure of associated or non-associated gas so it can be exported through pipelines, reinjected into the reservoir, or used for gas lift. Offshore, multi-stage compression trains with inter-cooling are common, often combining centrifugal, screw or reciprocating compressors. Upstream, gas is separated, cooled and scrubbed to remove liquids and solids that could damage machinery. Compression maintains sufficient discharge pressure to overcome pipeline friction, subsea backpressure and reservoir injection requirements. It also stabilises topsides processing by controlling gas volumes and preventing bottlenecks in separators. Because compression consumes large amounts of power, efficiency and reliability are central design and operating concerns, tied closely to facility uptime and overall field economics. Ref
Dehydration and sweetening ensure gas is dry and non-corrosive before export, reinjection or use as fuel. Dehydration often employs triethylene glycol (TEG) contactors to absorb water vapour, with the glycol regenerated in a reboiler loop and recirculated. Alternatives include molecular sieves for deeper drying. Sweetening removes acid gases such as H₂S and CO₂, typically with amine absorption/regeneration systems. Treated “sweet” gas exits meeting pipeline or injection specifications for water content and acid-gas limits, reducing corrosion risk, hydrate formation and environmental impacts. On compact offshore facilities, modular, intensified units and rotating packed beds are increasingly considered to save weight and footprint while maintaining high mass-transfer efficiency. Ref
In the production phase, subsea wells often produce a multiphase mixture of oil, gas, water and sometimes sand. Flowlines route this mixture to subsea manifolds, where individual well streams are combined and directed toward the host facility. Choke valves at the wellhead or tree regulate flow and protect both reservoir and surface equipment. Flow assurance is a key process activity: operators inject chemicals (e.g., hydrate inhibitors, wax or scale inhibitors), control temperatures, and sometimes use insulation or heating to prevent blockages. Slugging is mitigated through pipeline design, slug catchers or topsides control strategies. In some developments, subsea boosting pumps or compressors are installed to maintain flow and offset declining reservoir pressures, effectively extending the productive life of the field. Ref
Artificial lift maintains economic production when reservoir pressure declines or natural flow is insufficient. Offshore, gas lift is common because high-pressure gas is usually available. In gas-lifted wells, treated and compressed gas is injected down the annulus and enters the production tubing through gas-lift valves. The injected gas lightens the fluid column, reducing bottom-hole flowing pressure and enabling higher drawdown and rates. Field processes around gas lift include gas conditioning, compression, distribution through lift manifolds, and careful control of injection rates per well. Operators adjust valve settings and injection strategies over field life to optimise production and avoid instability or slugging. Other artificial lift methods, such as electrical submersible pumps (ESPs), may be used but present different topsides power and handling requirements.. Ref
Sand production can erode equipment, plug lines and compromise separation performance. Management starts downhole with sand-control completions such as gravel packs or screens, but topsides processes are also critical. High-pressure desanders near the wellhead remove solids early to protect chokes, valves and separators. Downstream, separators and hydrocyclones further capture sand from production and produced-water streams. Collected sand is typically dewatered and transferred to skips for onshore disposal, in line with environmental rules. Continuous monitoring—via erosion probes, acoustic sensors or sand detectors—allows operators to stay within safe operating envelopes and adjust drawdown or choke settings. A structured sand-management strategy is now standard practice in mature offshore fields to sustain production and avoid costly downtime. Ref
Modern offshore facilities rely on integrated control and safety systems to run complex production processes. Distributed control systems (DCS) and programmable logic controllers (PLCs) regulate pressures, temperatures, levels and flow rates across separators, compressors, heaters and utilities. Thousands of field instruments—transmitters, analysers, valves—feed real-time data to operator consoles, where advanced process-control algorithms optimise separation efficiency, compression stability and energy use. Safety instrumented systems (SIS) provide independent shutdown logic for high-risk scenarios, while fire and gas systems monitor for leaks and ignition hazards. Increasingly, digital twins, remote monitoring and condition-based maintenance support predictive decision-making from onshore control centres, enhancing uptime and reducing the need for offshore interventions. All of this control infrastructure is a core “process” in sustaining stable, safe production operations. Ref
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During the production phase, hydrocarbons are processed on either fixed or floating facilities. Fixed jackets and compliant towers are common in shallow to medium water depths, with topsides hosting separators, compressors, utilities and living quarters. In deeper water, floating systems dominate: semi-submersibles, spars, TLPs and especially FPSOs, which combine processing with storage and offloading capability. The choice depends on water depth, metocean conditions, reservoir life, export options and reuse potential. Floating facilities are often preferred where pipelines to shore are long or where shuttle tankers handle export. Each concept is essentially a “host” that carries similar process modules, but with very different hull and mooring philosophies to keep the plant on station. Reference: ScienceDirect overview of production platforms and FPSO systems. Ref
A Floating Production, Storage and Offloading (FPSO) vessel is a ship-shaped unit that processes well fluids, stores stabilised crude and offloads it to shuttle tankers. Topsides modules typically include inlet manifolds, multi-stage three-phase separation, heaters, crude stabilisation, produced-water treatment, gas compression, gas dehydration/sweetening and fuel-gas systems. Below deck, large cargo tanks store treated crude under inert gas, supported by ballast systems for trim and stability. Offloading systems with loading hoses, transfer pumps and custody-transfer metering connect to shuttle tankers via a bow or side arrangement. Many FPSOs also support water-injection and gas-lift systems. Their flexibility, relocatability and ability to work without a fixed pipeline make them the default production solution for deepwater and remote offshore fields. Reference: industry descriptions of FPSO design and operation. Ref
In subsea developments, the wellhead and Christmas tree sit on the seabed rather than on a surface platform. The wellhead provides structural support and pressure integrity at the seabed, while the subsea tree is a complex valve assembly controlling flow, injection and well safety. It includes master and wing valves, swab valves, choke modules, sensors and hydraulic or electro-hydraulic actuators. Production trees route hydrocarbons into flowlines; separate trees may be dedicated to gas or water injection. Control is provided through subsea control modules and umbilicals from the host facility. Together, these systems allow multi-well templates to be operated remotely, enabling production in deep water without a fixed platform while still providing redundancy, monitoring and rapid shut-in capability when required. Reference: overviews of subsea production systems and trees. Ref
Subsea manifolds sit on the seabed and gather, distribute and control produced fluids from multiple wells. They combine flows, route them to export lines, and often integrate isolation valves, pigging loops and metering points. Umbilicals are composite cables carrying hydraulic lines, power and fibre-optic communications between the host facility and subsea equipment, enabling valve actuation, chemical injection and real-time data transmission. Subsea control systems coordinate tree and manifold functions, including safety shutdowns and pressure/temperature monitoring. Together, manifolds, umbilicals and control pods form the “nervous system” of a subsea field, allowing centralised topsides control of remote wells with minimal intervention. They are critical for efficient production management, flow optimisation and rapid response to abnormal conditions. Reference: technical descriptions of manifolds and subsea control systems. Ref
The production phase relies on a network of subsea flowlines and risers to move multiphase fluids from wells to the host. Flowlines run along the seabed, connecting trees to manifolds and manifolds to riser bases. Risers then carry fluids vertically to the platform or FPSO; concepts include flexible risers, steel catenary risers and hybrid riser towers. These systems must withstand internal pressure, external hydrostatic loading, fatigue from waves and currents and thermal expansion. Ancillary hardware such as riser bases, bend stiffeners, buoyancy modules and pipeline end terminations complete the system. Together, they link subsea production equipment to topsides process modules and are central to flow assurance, tieback strategies and overall field layout. Reference: subsea production system descriptions from major suppliers. Ref
A three-phase separator is a pressure vessel that splits the incoming well stream into oil, gas and produced water streams. Using gravity settling, internal baffles, coalescers and mist extractors, it slows the fluid so gas disengages upward, oil forms a middle layer, and water settles at the bottom. Level instruments and control valves maintain stable interfaces and discharge each phase to downstream equipment. Three-phase separators are usually placed early in the process train, right after the choke manifold, to protect downstream compressors and treaters. Their performance directly affects production efficiency, measurement accuracy, water-treatment load and export-quality specifications. Because of this, design and internals selection are carefully optimised for expected pressure, temperature, flow regime and fluid properties. Reference: industry and SPE guidance on oil and gas separators. Ref
Produced water treatment relies on a train of specialised vessels and packages. After bulk separation in primary and secondary separators, water often passes through hydrocyclones that use centrifugal forces to remove dispersed oil droplets. Downstream, induced or dissolved gas flotation units promote bubble-assisted coalescence and flotation of remaining oil to the surface, where skimmers remove it. Polishing stages can include nutshell filters, membrane elements or adsorption media to meet stringent ppm limits before overboard discharge or reinjection. Many packages integrate sand removal and degassing, as well as chemical dosing for flocculation, scale control and corrosion inhibition. Skid-mounted systems are common on FPSOs and platforms where space and weight are constrained. Reference: FPSO topsides descriptions and separation/water-treatment case studies from major OEMs. Ref
Gas compression systems raise the pressure of associated or non-associated gas for export, gas lift or reinjection. Offshore packages typically use centrifugal or reciprocating compressors driven by gas turbines or high-voltage motors, arranged in multiple stages with inter-coolers and scrubbers to remove liquids. Skid-mounted solutions are common on FPSOs and compact platforms, where footprint and weight are critical. Increasingly, hermetically sealed motor-compressor units and subsea compressors are deployed to improve reliability and reduce topsides equipment. These systems must meet stringent availability targets, as compressor downtime often limits overall production. Advanced control systems, condition monitoring and digital twins are now standard to optimise efficiency and predict failures. Reference: vendor material on offshore gas compression systems and recent subsea compression deployments. Ref
Offshore production facilities are effectively small power plants. Primary generation is usually via industrial gas turbines fueled by treated produced gas, often supplemented by diesel generators for backup and black-start. Power is distributed through high-voltage switchgear and transformers to large consumers such as compressors, pumps, crane drives and drilling or intervention equipment, as well as hotel loads. Modern facilities integrate power-management systems that balance load, synchronise generators and shed non-critical consumers during disturbances. Digitalisation initiatives aim to optimise fuel efficiency and reduce emissions through waste-heat recovery, variable-speed drives and intelligent load control. In some developments, subsea processing is powered from shore via HVDC links. Reference: OEM material on topsides power and integrated offshore production facilities. Ref
Once a field is onstream, a core fleet of offshore support vessels (OSVs) keeps it running. Platform Supply Vessels (PSVs) deliver drilling mud, chemicals, dry bulk, fuel, food and spare parts to platforms and FPSOs. Anchor Handling Tug Supply (AHTS) vessels assist with towing, mooring operations and can also act as supply and emergency response vessels. Multi-purpose and construction support vessels carry ROV spreads, cranes and specialised tools for inspection, repair and maintenance. These OSVs are often equipped with dynamic positioning systems to hold station safely alongside installations. Their utilisation strongly correlates with overall offshore production and maintenance activity. Reference: OSV role descriptions from engine manufacturers and maritime industry guides. Ref
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Flow assurance refers to ensuring the safe, reliable and uninterrupted transport of well fluids from the reservoir to the processing facility. Key challenges include hydrate formation, wax or asphaltene deposition, scale formation, slugging and sand in the lines. These phenomena can occur due to changing pressure/temperature conditions as production declines, and they can reduce throughput, increase downtime, cause damage to pipelines, risers and facilities, and drive unplanned maintenance. Effective management includes chemical injection, thermal insulation/heating, slug catchers, pigging and real-time monitoring. In offshore production, the remote, harsh and constrained environment makes flow assurance a critical milestone during ramp-up and throughout plateau. Ref
Corrosion and material degradation are pervasive hazards in offshore production: produced fluids often contain CO₂, H₂S and water, all of which can trigger corrosion mechanisms such as sulfide stress cracking, hydrogen-induced cracking and corrosion fatigue. Assurance of materials, coatings and cathodic protection is required. If not properly managed, corrosion may lead to leaks, equipment failure, unplanned shutdowns and environmental incidents. In high-pressure, high-temperature (HP/HT) or sour-service wells, the challenge is amplified. Identifying this hazard and implementing integrity-management systems is a key operational milestone in a production field’s life. Ref
Process safety is central in offshore production because large volumes of hydrocarbons are handled under high pressure in a harsh environment. Hazards include gas leaks, jet fires, and explosions (for example, the famous Piper Alpha disaster). Facilities must achieve key milestones such as commissioning of Safety Instrumented Systems (SIS), installation of gas detectors and flare systems, emergency shutdown (ESD) loads testing, and fire-fighting system acceptance. Until these milestones are achieved, the facility cannot safely enter full production. Regular audits, maintenance and training sustain the safety barrier systems. Ref
Offshore production facilities often operate in remote areas subjected to extreme weather, waves, currents, storms and icing. These conditions challenge logistics, personnel transfers, emergency evacuation, equipment reliability and maintenance access. For example, rough seas may delay ROV or vessel operations, impede offloading or interrupt supplies. Reaching key operational milestones—such as first production, export ramp-up and stable plateau—depends on reliable logistics. Infrastructure must be built and maintained for the environment, and contingency planning for weather-related interruptions becomes a constant operational hazard. Ref
As an offshore field progresses through production life, infrastructure such as wells, flowlines, risers, processing equipment and moorings age. This leads to increased failure risk, obsolescence, reduced operability and higher maintenance costs. Milestones like life-extension assessments, major inspection campaigns (e.g., integrity of risers, jackets, subsea components) and retrofit upgrades must be achieved to ensure continued safe production. If ageing is not managed, the hazard of unplanned shutdowns, spill incidents and asset loss increases, which can compromise field economics and operator reputation. Ref
Production operations must adhere to a wide set of regulatory and environmental standards: emissions, discharges, produced water treatment, flaring limits, biodiversity protection and marine pollution. Achieving milestones such as Environmental Impact Assessment approvals, discharge permits, sulphur-emission limits, regular monitoring, and audits are critical. Non-compliance can lead to fines, downtime, loss of licence or reputational damage. The hazard is that if processes or equipment do not meet regulatory standards (for example, for produced water oil-in-water levels or flare reduction), production may be curtailed or stopped. Ref
With modern offshore production relying heavily on digital systems, connectivity, remote monitoring and automation, cyber threats and vulnerabilities become significant hazards. Offshore assets are remote, often integrated via SCADA/IIoT systems and may be less physically accessible. A cyberattack disrupting control systems could lead to production loss, safety incidents or environmental spills. Key milestones include cybersecurity assessments, secure network architecture, incident-response plans and regular penetration testing. While not always front of mind, this challenge is growing in importance as digitalisation deepens. Ref
After construction and hook-up, the move into the production phase includes ramping up wells, processing modules, and export systems. Achieving design capacity is a major milestone. Challenges during ramp-up include commissioning of complex processing trains, stabilising flow regimes, managing start-up flows with higher risks (slugging, sand, noise), training personnel, establishing steady maintenance routines and validating production and export measurement. Delays or failures during ramp-up can delay cash flow, increase costs, and elevate hazard exposure, as systems may not yet be fully mature. Ref
Over time, reservoir pressure declines, wells produce more water or gas, and deliver lower flows — this is normal, but poses a challenge to maintain profitability and stable operations. The milestone here is the transition from plateau production to decline management, involving increased water handling, gas lift or artificial lift deployment, enhanced recovery investments and possibly tie-ins of new wells. Challenges include redesigning production processes, increasing maintenance for water and gas handling, and managing the economic and operational impact of lower rates. If not addressed, production may become uneconomic or unsafe. Ref
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