Alternate approach best suited to longer-term projects
Susanne Pearce
Wood
Sometimes during offshore oil and gas operations, individual production systems are intentionally suspended: this can be to accommodate platform repairs, wells waiting on a workover, or difficulties sustaining viable production due to factors such as the oil price.
Suspension allows operators to minimize costs and safety risks, with the option of re-activating their system at a later date after the repairs are complete, or when economic or other circumstances change (i.e. the opportunity to tie in a satellite field). But it is also critical to conduct suspension appropriately to avoid the deterioration that can set in when an asset is left idle for an extended period.
One offshore operator of a gas/condensate platform was mindful that an asset had exceeded its forecast end of field life (EOFL) date, with the wells lacking sufficient pressure to maintain an economic and operationally viable flow. However, the not normally manned platform, equipped with dehydration facilities and an export pipeline back to an onshore gas plant, had been constructed mainly from corrosion-resistant materials, and along with the export pipeline, was in a generally very good condition. The operator, which was considering various options to extend the platform’s service, including tying back and producing an adjacent reservoir, commissioned Wood to examine how to best to suspend and preserve the facility until the new production source could be brought online.
Suspension using operational fluids overcomes many key challenges commonly faced when suspending a platform.
Conventional cleanouts
The conventional suspension approach would have been to shut down the platform, flush it free of hydrocarbons, clean out all associated process vessels and pipework, and leave them filled with inert gas or preservation fluid. At the same time, new isolations would have had to be fitted and rotating equipment and electrical systems would need to undergo preservation measures, all involving extensive construction activity on the remote installation. And when the time came to restore normal service, all these modifications would have to be reversed.
Wood, in addressing the operator’s concerns over the cost, risk and environmental impact, proposed an alternative solution: suspending the majority of the platform and its subsea infrastructure using operational hydrocarbon fluids. Due to the corrosion-resistant materials, the platform and upstream production systems would not be at risk of degradation if shut-in with produced fluids.
However, the initial plan to shut-in most of the system, leaving the produced fluids in place, was not feasible because the flare system could not be isolated, so a minimum flow rate had to be maintained to prevent air back-flowing into the facility. The engineering team responded by devising a method that allowed residual gas from the wells to be diverted to keep the flare working. Much of the platform and the export pipeline could then be shut in with production fluids, while the upstream pipeline, and a modified route through the platform, would be kept operational at a minimal flow rate to maintain the flare.
Wood’s team also consulted with the operator on other ways of challenging or improving the standard procedure. This resulted in the preservation program being technically validated, with subsequent tests by the operator verifying the proposal’s viability.
Suspension using operational fluids overcomes many key challenges commonly faced when suspending a platform.
The conventional approach of isolating, cleaning, flushing, and inerting involves substantial offshore activity. Hydrocarbon containment must be breached in order to install isolations and confined space entry is needed for cleaning. Flushing fluids and debris must be disposed of. Minimizing the number of isolations and construction/lifting activity and avoiding entry into and cleaning of process vessels lessens the safety and environmental risks.
One irony of suspension is that cleaning and inerting can sometimes cause more damage than they prevent, as the facilities are designed to handle oil and gas, not preservation fluids or the air. Corrosion-resistant materials used in oil and gas topsides systems can withstand the produced fluids but may be subject to corrosion or cracking risks when exposed to air or steam cleaning. However, provided the system does not rely on active corrosion control such as inhibitor injection, suspending with process fluids maintains the item in its ‘as-designed’ state, with a far lower risk of inadvertent damage during suspension.
If the hydrocarbon containment of a system must be breached for suspension, for example, to install isolations or enter vessels for cleaning, there is a risk that the breach will leak when restored to service. This also makes it necessary to remove the inert environment before re-commissioning. But maintaining equipment using process fluids enables the system to remain in an operational status, making it much easier to re-start.
For this project, the original cost projections for the conventional preservation approach were around $21 million to shut down the platform, and $10 million capex to recondition and reinstate it. Even subsequent downward revisions put the suspension and preservation capex at $11 million. Implementing Wood’s solution when the EOFL arrives should save $6-7 million.
The conventional approach also requires transportation of construction crews and cleaning equipment offshore to clean and preserve the equipment, and waste fluids from cleaning must be captured and managed, and in certain cases transported ashore. Wood’s solution, which can be run from the platform’s existing control room, reduces the number of man-hours required, and minimizes worker and equipment transport needs and exposure to hazardous environments.
Use of operational fluids for preservation is by no means a universal solution for all systems facing suspension, because of the nature of the fluids concerned and the facility’s design details. And calculating the cost benefit depends on several factors, mainly the duration of the proposed suspension. Calculations to date suggest that suspension projects of 12 months or less are likely to benefit from this new method, with a much stronger case for investing capital in a full clean-out for projects lasting longer than a year.
Nonetheless, this is a methodology with a proven application that can be realistically incorporated into operators’ standards and specifications for temporary suspension, providing a potentially cost-effective approach to future offshore suspension projects. •
