Remediating Platforms by Raising Topsides

The design of fixed offshore platforms requires a minimum clearance from the mean water level to the topsides structure. This clearance is generally referred to as an air gap. The air gap is determined such that under the maximum design conditions, the crest of the wave passing through the platform does not make contact with or inundate the topsides.

Design codes such as API RP2A assess the air gap using the 1,000-year return period crest elevation combined with storm surge effects. Platform loads (shear and overturning moment) can increase by between 50% and 100% when the storm crest elevation exceeds the air gap and inundates the structure of the topsides.

The consequences of a storm wave impact on a platform’s topsides can be catastrophic. This was graphically shown by the collapse or near destruction of a number of offshore structures in the US Gulf of Mexico (GOM) during hurricanes Ivan in 2004 and Katrina and Rita in 2005. Approximately 250 significant structures, including eight-leg drilling and production platforms in water depths of up to 450 ft, were destroyed by these storms collectively.

Cleanup operations for the destroyed platforms remain ongoing. Costs for decommissioning a hurricane-destroyed platform are 10 times or greater the cost of decommissioning the same standing platform in a planned manner, excluding the value of lost or deferred oil and gas production.

Given that the destroyed platforms were designed according to approved standards and guidelines, why did the structures collapse?

Three primary reasons have been identified.

1. The platforms were in poor condition (suffering from corrosion and historical damage) and thus had design resistances less than planned for in the original design.
2. The maximum wave or waves experienced during these hurricanes were larger than assumed during the original design. Because wave loading on fixed offshore platforms varies with the square of the wave height, the actual loads experienced would be greater than those accounted for in the original design. And if the extreme wave crest exceeded the air gap, the design loads would increase exponentially and greatly exceed the original design case.
3. The air gap for certain platforms was less than at the original time of installation, which resulted in unexpected topsides inundation.

An Unacceptable Air Gap

In view of the critical nature of the air gap in the design and long-term viability of an offshore platform, what are the circumstances under which the air gap distance would no longer be acceptable?

Three specific cases should be considered.

1. Actual design waves and storm surges are greater than those contemplated in the original design.
2. The consequence factor used for the design of the platform has changed, thereby requiring the use of new and more onerous conditions (larger design waves).
3. The platform air gap has decreased because of the offshore platform settling vertically relative to the mean sea level.

Research conducted after the major hurricanes in 2004 and 2005 showed that the numerical storm wave hindcast models, which add updated information to original forecast models, underpredicted extreme wave heights for the central portion of the GOM, compared with data measured during these storms.

The environmental criteria for the 100-year and 1,000-year return periods used for offshore platform design must be extrapolated from historical data recorded over much shorter time frames. Large variations in predicted values can arise from small errors made in fitting the historical data to complex statistical models. For example, the 100-year design wave in the GOM before these major storms was specified with a height of 72 ft.

The updated 100-year design wave is now 91 ft, an increase of more than 25%. This would imply that the air gap selected for platforms designed to handle the smaller design wave will now be too small for the larger design wave condition.

The design of offshore platforms is based on the use of rational risk factors. For example, the consequences of the structural collapse of an unstaffed gas-producing facility are less than for a staffed oil production and storage platform. Consequently, certain regulatory regimes allow the use of different design criteria for these two classes of structure.

The challenge arises when a ­lower-consequence platform is modified or upgraded to that of a higher consequence. The modified platform should be reassessed against the higher risk and more onerous design criteria, which will include a larger design wave, and a larger air gap requirement.

Oil and gas reservoir pressures decline with production flow over time. In certain formations, reservoir compaction may occur when the overburden loading on the reservoir rock is no longer balanced by the internal reservoir pressure.

Depending on the depth below the seabed and the geometry and nature of the strata between the reservoir and the surface, reservoir compaction may also result in the local settlement of a region of the seabed above the reservoir. The areal extent of this surface compaction can be as large as tens of square miles. Any fixed offshore platform situated in a seabed area that has settled will move vertically downward relative to sea level. This movement will result in a loss of air gap.

Surface settlement caused by reservoir compaction is a well-known and common occurrence, particularly for gas-producing reservoirs. It is a common practice for the design of a new offshore platform to account for a fixed amount of expected settlement and air gap reduction over the life of the platform. However, there is a considerable range of uncertainty in these predictions, which in some cases results in the platform air gap falling below the required design level while the field remains in production.

The Ekofisk field offshore Norway is a significant example of a group of platforms that were subjected to a high amount of seabed settlement because of reservoir compaction. A total of 20 ft of settlement over 15 years resulted during the field’s producing life. The original platform design accounted for little or no settlement.

Platform Remediation Steps

If a producing platform has an air gap that is below design requirements, one or more of the following remediation measures are appropriate.

1. Replace the platform with a new structure designed to current criteria.
2. Modify the platform to reduce wave loading.
3. Strengthen the platform to resist the higher loading effects caused by wave inundation of the topsides.
4. Raise the topsides to increase the air gap to the required distance.
5. Conduct an advanced structural analysis to show that the platform in its current condition will not collapse even with wave inundation of the topsides.

Of the above, option 5 is normally the most attractive because the cost will be the lowest if the analysis turns out as hoped. However, equipment could be damaged or destroyed even though a platform does not collapse and production could be lost for an extensive time.

Option 1 is the most expensive and the least likely choice. In some cases, it may be possible to consolidate multiple smaller platforms into one or two larger integrated platforms and realize some element of cost mitigation. In other instances, although an acceptable strength remediation solution is achievable, the age and condition of the production facilities may still require the installation of a new platform.

A significant number of platforms undergo the remediation measures described in options 2 and 3. Cost-effective ways of reducing wave loading include the removal of marine growth by water blasting and the removal of old or unused well conductors. Platform strengthening can be achieved by filling tubular members with grout and in extreme cases by installing clamped and grouted sleeves to serve as additional external foundation piles.

As with option 5, options 2 and 3 do not address the potential for damage and functional loss of deck-mounted equipment.

Option 5 can provide a cost-effective method of remediation with an outcome technically equivalent to option 1, that is, a replacement with a new platform.

Hydraulic Jacking Operations

To date, the author is aware of four platforms worldwide on which remediation involved raising the topsides.

1. The Ekofisk complex in 1987.
2. Two drilling and production platforms in the GOM in 2006 and 2007.
3. A platform complex offshore Indonesia in 2013.

In these projects, the topsides were raised by positioning clusters of hydraulic rams around each supporting leg (Fig. 1 above). Programmable logic-controlled systems were used to control the hydraulic flow to the rams to ensure a level and uniform lifting.

In the Ekofisk project, the legs were cut and the decks were supported solely on the hydraulic rams without additional structural supports or guides. At the end of the raising process, flanged leg sections were bolted in situ to form part of the permanent structure in the raised condition. A total of 45,000 short tons of jacking capacity was used to raise the topsides by 20 ft. According to available public information, the project employed 15,000 people onshore and offshore at its peak and cost the equivalent of USD 1.25 billion (in 2014 dollars).

The raising procedure developed for the two GOM projects used a modified process. Split leg sleeves were introduced. They encapsulated the topsides supporting legs during the raising operation. These sleeves also formed the permanent leg extensions in the raised condition and functioned as a mechanical pin-off system, which provided a fully load-bearing mechanical support within 30 minutes of the topsides having been raised to the new elevation.

This approach introduced lateral support to the topsides during raising and significantly shortened the elapsed time between the start of raising and the establishment of a full load-bearing raised connection. The raising of the Ekofisk topsides was reported to have taken 4 days. The raising of each of the GOM structures required approximately 3 hours, and the estimated cost of raising each was USD 10 million (in 2014 dollars). A total of 8,000 short tons of jacking capacity was used to raise each topsides by 4 ft.

The raising of the offshore platform complex in Indonesia (three platforms, three bridges, and two flare bridge support structures) presented a unique challenge. These platforms provided very short unbraced lengths of deck leg (approximately 4 ft) around which the hydraulic rams could be initially positioned. Because of reservoir compaction, the platform complex needed to be raised by 13 ft to allow the extension of the field’s life.

The raising operation was split into two stages. In stage 1, the complex was raised by 3 ft, using groups of small ­single-stage hydraulic rams that could be positioned around the short leg sections. In stage 2, the complex was elevated by 10 ft, using groups of larger two-stage hydraulic rams that could be positioned once the initial raising operation had been completed. During both stages, the split-sleeve configuration was used, thus providing lateral support and a mechanical pin-off connection at the final elevation.

Completed at a cost of USD 120 million (in 2014 dollars), the project deployed two independent sets of hydraulic rams, each with a total lifting capacity of 14,000 short tons or 28,000 short tons in total.

Summary

Fixed offshore platforms may require some form of remediation over their life span to accommodate an insufficient air gap. The platform air gap (the distance from the sea level to the underside of the topsides) is a critical design parameter, which is intended to prevent topsides inundation during storm wave events. An air gap may be insufficient because of an increase in design wave height or platform settlement as a result of reservoir compaction.

The total collapse of platforms or major damage to them have occurred in the GOM, when topsides have been hit by a storm wave. Among the various air gap remediation options, topsides raising (for either single platforms or platform complexes) may provide a permanent and cost-effective solution.