Powering platforms from shore: electrification feasibility, load studies and cable routing

Most offshore power comes from gas turbines running well short of their best operating point. The platform has to hold spinning reserve for the biggest motor start and for trip events, so the machines sit part-loaded most of the time. That sets the fuel bill, the emissions profile and the maintenance load on rotating kit. It also ties platform availability to turbine hot-section overhauls. Shore power looks like the obvious fix. But a study that stops at "the grid has capacity" tends to come apart in detailed design, when the cable, the converter or grid-code compliance turns out to be the real constraint. A credible feasibility study treats electrification as a system problem: a demand profile, a transmission architecture, a converter choice, a routed cable, and an honest look at what happens when the supply drops out.

Standards and requirements context

No single standard governs power from shore. The study works across several families:

• IEC 61892-1, with its companion parts, covers electrical installations on mobile and fixed offshore units and sets the baseline for the topside system.
• IEC 60079 covers equipment for explosive atmospheres. It applies to new switchgear rooms, converter modules and any equipment placed in or near classified areas.
• IEC 60287 covers calculation of the current rating of electric cables. Its methods underpin thermal sizing, including the thermal resistivity of seabed backfill and the effect of burial or rock cover.
• IEEE 519 covers harmonic control in electric power systems. It is the usual reference for assessing converter harmonic emissions at the point of connection.
• IEC 61511 applies where the electrical system supports safety instrumented functions, such as emergency shutdown logic that must behave correctly on loss of the shore feed.

Beyond these, the onshore grid operator's connection requirements and the flag or classification authority's rules shape the design. The latter often drive how black-start and islanded operation get handled.

What a shore-power feasibility study contains

Five blocks make up the work, and they have to stay consistent with each other:

1. Demand profiling, both present and forecast.
2. Transmission architecture and converter selection.
3. Subsea cable design and route.
4. Reliability and availability, including what remains offshore as backup.
5. Supply sourcing, including renewable integration.

This is the block most often under-scoped at concept stage.

Demand profiling

Build the load from equipment, not from the turbine nameplate

Installed generation capacity overstates demand because of redundancy. Build the profile bottom-up from the electrical load list: compression, water injection, export pumps, utilities, HVAC and drilling if present. For each load, capture:

• Absorbed power at defined operating cases (plateau, decline, turndown, shutdown and restart).
• Whether it is fixed-speed or variable-speed driven.
• Starting method and starting current.
• Power factor and harmonic contribution.

Annual energy follows from the profile: E = Σ(Pᵢ × tᵢ), where Pᵢ is the average demand in operating case i and tᵢ is the time spent in it. That energy figure drives the carbon case, the supply contract and any renewable matching.

Include the transient cases

Steady state doesn't set the design power. The worst credible combination does: a large motor start, a compressor restart after trip, and the loss of one cable or converter. Dynamic simulation has to show voltage and frequency staying within equipment limits through those events. If large drivers are being converted from gas turbines to electric motors, decide early whether the shore supply must support direct-on-line starting. Variable-speed drives or soft starters ease the weak-grid problem, but they bring harmonic and footprint penalties with them.

The Martin Linge field is a useful anchor for scale. Design power and distance together are what push the choice of transmission technology.

Transmission architecture and converter selection

AC versus DC

The central trade-off is HVAC against HVDC. In AC, cable charging current grows with length and with the square of voltage. The reactive power generated by a three-phase cable is:

Q_c = ω × C × V²

where ω = 2πf is the angular frequency, C is the line-to-neutral capacitance of one phase (farads) and V is the line-to-line voltage (volts), so Q_c is in var. C scales with cable length. Reactive power therefore eats into cable current capacity as distance grows, until little real power gets through without compensation. That's why long AC links need shunt reactors at one or both ends, and why very long distances usually push the study toward DC. The MDPI review of offshore electrification architectures and power conversion (2023) is a good starting point for comparing the topologies.

Converter options

When the platform runs at a different frequency from the shore grid, or the loads need variable speed, a static frequency converter goes in. The SPE paper on active front end, grid-forming static frequency converters (2025) covers this converter class for offshore electrification. For a study, the control mode is the key point. A grid-forming converter sets voltage and frequency for the platform island instead of following an existing grid. So it has to ride through motor starts and sudden load steps on a weak or nearly empty platform network.

When you compare converter offers, ask for:

• Behaviour on loss of the shore feed and the sequence for re-energising.
• Short-circuit current contribution, which affects protection coordination with existing switchgear.
• Harmonic spectrum at the point of connection, assessed against the IEEE 519 approach.
• Cooling, space and weight in the offered module.

Subsea cable design and routing

Route selection

Route engineering starts with desktop data: bathymetry, seabed sediment, existing pipelines and cables, fishing activity, anchorage areas and protected zones. Geophysical and geotechnical surveys then confirm the route. Pick the route that minimises length, but accept extra length if it avoids crossings, steep slopes, boulder fields or unstable sediment. Every pipeline or cable crossing needs an agreement with the owner and a designed separation layer.

Landfall and platform approach

Landfall is often where the schedule slips. Options include horizontal directional drilling, trenching through the surf zone or a pre-installed conduit. At the platform, the approach is usually a J-tube or an I-tube. In the shallow-water and splash-zone section the cable takes wave action, so assess fatigue and bend-radius protection there. Brownfield platforms often have only a handful of spare J-tubes, so confirm their availability and orientation at the start of the study.

Thermal and mechanical sizing

Current rating follows the methods in IEC 60287. Burial depth, backfill conductivity and proximity to other cables all derate the cable. Mechanical protection against trawl gear and dropped objects, by burial or rock cover, affects both thermal rating and cost. If the route has a dynamic section, the design has to address fatigue and the cable's armour construction.

Where renewable supply fits

Shore power doesn't decarbonise anything on its own. The emissions benefit depends on the onshore mix feeding the link. Renewable integration options include:

• A contractual supply (such as a power purchase agreement) matched to the demand profile from the energy calculation above.
• Offshore wind connected into the same cable or to the platform network, so the platform acts as a hub.
• Hybrid operation, in which local generation stays on as a backup and stabiliser.

The technical issue is variability. Wind output follows the weather, while platform demand follows the process. The converter and any storage need enough control authority to absorb that mismatch without disturbing the platform island. An offshore wind connection also changes the cable and converter duty, since power can flow in either direction. The cable rating, protection and converter control all have to be studied for those cases.

Illustrative scenario: a brownfield platform study

This scenario is illustrative and not drawn from a specific project.

An ageing platform runs several gas turbine generators. The operator wants a shore connection at a distance where HVAC is borderline. The study goes like this:

1. The load list is rebuilt. The biggest motor start and the restart after a full trip become the sizing cases.
2. AC charging reactive power, Q_c = ω × C × V², is calculated for the candidate voltages and route length. If reactive compensation eats up much of the cable's current capacity, the study compares HVAC with compensation against HVDC.
3. The converter shortlist is judged on grid-forming capability, fault current, and the space and weight available on the platform.
4. The route survey turns up a pipeline crossing and a steep seabed section. The route gets lengthened to avoid the slope, and the thermal rating is re-checked at the new length.
5. The availability review concludes that one cable is a single point of failure. The operator either keeps reduced turbine capability for critical loads or designs a second cable, and the cost comparison reflects that choice.

The result isn't a single number. It's a ranked set of options, each with named residual risks.

Practical checklist

• Is the load list rebuilt from equipment, with operating cases and a decline forecast?
• Have the largest motor start, restart after trip and loss of cable been simulated?
• Has the AC charging reactive power been calculated for each voltage and route length, and has the AC/DC decision been documented?
• Does the converter specification define grid-forming behaviour, fault current, harmonics and loss-of-feed sequence?
• Are harmonic limits agreed with the grid operator at the point of connection?
• Is J-tube or I-tube availability confirmed on the platform?
• Has the route been checked for crossings, landfall method, trawl exposure and thermal derating?
• Is retained generation defined for black start and for critical loads?
• Does the onshore supply source have a stated carbon basis, and is the renewable matching strategy defined?
• Are hot work and live-tie-in plans on the hydrocarbon platform covered by the permit-to-work system, with hazardous-area precautions and gas detection in place?
• Do the shutdown logic and any safety instrumented functions behave correctly on loss of shore supply, assessed under IEC 61511?

Conclusion

A shore-power feasibility study is a demand, reliability and routing exercise, and the converter and cable choices constrain each other. Start by rebuilding the load profile and pinning down the transient sizing cases. Run the AC charging calculation to decide whether HVAC is viable. Shortlist converters on grid-forming performance and protection behaviour. Then let the route survey confirm or overturn the desktop cable length. Finish with an availability assessment that decides what generation stays offshore. For deeper reading, the Martin Linge paper (2014) covers long-distance AC selection, the MDPI review (2023) covers architectures, and the 2025 PCIC and SPE papers cover grid-forming converters and North Sea platform electrification.