Raising cogeneration efficiency and cutting total annualised cost by re-optimising the steam network, without replacing existing drives.
The challenge
A process change increased steam recovery from a reactor unit, cutting demand at the site’s very-high-pressure header and unbalancing a network of five steam headers that imports at two pressures and exports to a neighbouring plant.
Replacing turbine drives was off the table, and gas turbine and HRSG integration was out of scope. The task was to re-optimise flows across the existing headers, turbines, letdown valves and desuperheaters for the lowest total annualised cost.
The network was already inefficient: numerous small, low-efficiency drive turbines, steam losses and venting at several headers, and large letdown flows generating no power at all while desuperheaters worked overtime to compensate.
Approach
The system was modelled with a turbine T–M performance model, adding a simple turbine across each expansion zone to absorb the change in heat load. Since existing drives stayed fixed, every extra unit of heat demand had to be met by new turbines or by the letdown valves, which put a clear cost on uncontrolled letdown.
Three configurations separated the value of process fixes from the value of upgrading the utility system itself:
- Case A — all existing turbines retained
- Case B — only motor-backed-up turbines replaced with larger, more efficient units
- Case C — all turbines replaced, approximating an ideal cogeneration system
For each case, a project roadmap was ranked by marginal benefit across investment limits from 1 to 9 MM$.
Results
Re-optimising flows, with no new hardware, delivered an immediate win. Steam import fell by 25 t/h, matching the extra steam now recovered from the process. A new turbine sized for the extra 27 t/h added 2.2 MW. Header losses and venting were eliminated by rebalancing away from letdown valves and switching off one under-used turbine, a 0.2 MW loss offset by the new turbine. That freed 7 t/h of surplus 42 barg steam for export to the neighbouring plant.
Ending steam import and enabling the export saved about 2.6 MM$/yr, plus 0.5 MM$/yr from exported power. Against a 1.5 MM$ fixed cost, that is a net reduction of about 2.8 MM$/yr, before any capital project.
Investment roadmaps
Across all three cases, replacing letdown valves and undersized turbines with larger units always gave the largest marginal benefit and was implemented first. A small efficiency gain translated into an outsized economic one.
Beyond that, the best sequence diverged by case. Project 13 dominated Cases A and B across nearly the full investment range but dropped out entirely once all turbines were replaced. Only four of eight candidate process units were ever worth modifying, and which four depended on the configuration assumed.
A closer look at turbine sizing showed that adding capacity in stages, rather than one unit sized for the final load, cut time spent at high turndown and lowered cost further. Three staged turbines proved optimal at the intermediate-pressure header. Gas turbine and HRSG integration was tested from 10 to 100 MW and raised total annualised cost linearly in every scenario, so it was not economic for this site.
What it comes down to
- Utility configuration and process modification are coupled. The best process projects change with the utility system assumed, so they cannot be optimised separately.
- The investment limit itself flips the optimal configuration. Full turbine replacement wins at low budgets; targeted process projects win as the budget grows.
- Ranking by total annualised cost narrows a long project list fast. Only half the candidate process units were ever worth touching.
- Staged turbine additions, sized to the shutdown schedule rather than the final load, avoid the efficiency losses of running oversized equipment at high turndown.
- Conventional payback-period screening misses all of this. It gives the same roadmap regardless of utility configuration.