Archives for category: offshore support

The year just gone was a mixed one for offshore. Incremental progress continued towards rebalancing, while some sectors saw small day rate improvements compared to 2017. Overall though, challenges persisted in an oil price environment characterised by uncertainty and volatility. Several key indicators underperformed relative to start year sentiment and the year ended on something of a negative note.

For the full version of this article, please go to Offshore Intelligence Network.

The global fixed platform “fleet” consists of over 7,700 installed structures, equivalent in unit terms to 58% of the mobile offshore fleet. Yet the significant role played by fixed platforms in generating requirement for offshore vessels and services (such as platform installation and IMR) is at times overshadowed by the role of the mobile offshore fleet. So what, then, is the current outlook for the fixed platform sector?

Back To Basics

Fixed platforms are immobile structures that are attached to the seabed and used to exploit offshore fields. All but 32 fixed platforms are located in water depths of less than 200m and the average water depth of the 7,744 installed units is 42m. Platforms usually consist of a ‘jacket’ (the legs) and ‘topsides’ (the decks), and are fabricated from steel, though concrete or wood have been used. Indeed, the first ever fixed platforms were wooden structures off California in the 1930s; these have been dismantled, but North America still accounts for 31% of the fixed platform “fleet”, a legacy of shallow water E&P in the GoM. Other major historical areas of fixed platform installation include the Middle East/ISC (15% of the fleet), SE Asia (22%) and the North Sea (7%). The North Sea is home to most larger structures, such as the 898,000t “Gullfaks C” gravity base platform. Most structures in areas like the Middle East and the US GoM, meanwhile, are at the opposite end of the scale – unmanned monopod/tripod wellhead platforms of less than 100t.

Construction Crunch

Historically, fixed platforms have been a core business area for a number of fabrication yards and EPCI companies. Installation of small structures tends to involve units like liftboats in the US GoM and crane barges in the Middle East. Larger structures (in the North Sea or West Africa) have required more robust transportation and heavy-lift vessels. At present though, the fabrication and installation outlook is subdued. As shown in the inset graph, 96 platforms were ordered in 2014, down 49% y-o-y; in 2015, 42 were ordered, down another 56% y-o-y. Most ordering has been for smaller units in the Middle East (14%, 2014-15) and SE Asia (39%): platforms like the 43,700t “Johan Sverdrup CPP” (North Sea) are exceptional. Reduced contracting is partly due to the weaker oil price, but it also reflects a longer term shift towards subsea developments and deepwater E&P.

A Shift To Services?

It seems, then, that outside of expansion projects in a few areas, the near term demand generated by fixed platforms is likely to be mainly from servicing existing units: facilities need maintaining, paint needs reapplication and so on. For example, long-term, multi-field IMR contracts have reportedly been awarded for platforms in the UK and Saudi Arabia in recent months. PSV and helicopter demand to supply manned platforms (and ERRV demand in the North Sea) will also persist unless fields are shut down. And even then, potential exists in platform removal: there are currently five planned decommissioning projects involving platforms, each project with a value of c.$400m.

So the fixed platform construction market is fairly challenged. But there are other ways in which fixed platforms can create opportunities. These may be quite niche or oblige EPCI companies to adapt, but with 7,744 units in place, the sector is in several regards still worth some attention.


A sustained period of low oil prices has created a shortfall in offshore support vessel (OSV) demand, at a time when the sector has displayed rapid fleet expansion. Charter rates have fallen significantly, whilst the number of inactive vessels has reached record levels in some regions. An increase in vessel scrapping would seem to be an obvious solution to this problem, so why hasn’t this been the case so far?

Mirror The MODU Model?

OSV demand has fallen – at least 11% of the total fleet was laid up at start September. So far in 2015, 23 removals have been recorded from the OSV fleet (18 AHTS/AHT and 5 PSV/Supply vessels). For AHTS/AHTs this is a 29% increase on 2014 on an annualised basis. PSV removals, however, are down by 46%. In either case, the number of removals seems below what might be expected given the challenging market conditions.

For the AHTS sector in particular, rig moves provide an invaluable source of demand – a decrease in utilisation for these units has not been surprising given the sharp fall in E&P expenditure following the drop in oil prices. Oversupply is also a significant issue for the MODU market. However, the reaction from owners in that sector has been very different, as is evident from a net decrease of 15 units from the fleet so far in 2015.

The decrease in MODU numbers has been achieved in two ways. Firstly, by reducing the number of existing units – removals are currently up by 94% in 2015 on an annualised basis, already surpassing the record number of removals recorded for any full year. Secondly, the addition of newbuilds has been restricted, with the number of deliveries down by 39% in annualised terms in 2015.

Short-Term Gains

A likely reason for the low uptake in OSV removals relative to the MODU sector is that there is comparatively more value in scrapping rigs (in particular, floaters), compared to OSVs, on account of their larger size and steel content. Furthermore, it is relatively easy and cost-effective to lay-up or stack OSVs, which has been the preferred option for owners – at least 340 AHTSs and 254 PSVs are estimated to be laid up, although in reality this number may be even greater. Similarly, the sale of vessels for use in other sectors (e.g. utility support) provides some means of reducing active vessel numbers, although sales activity for OSVs in 2015 is currently down by 25% on an annualised basis.

However, whilst stacking of OSVs provides some respite for owners during times of oversupply, it can only be considered a short-term solution – especially given the size of the current OSV orderbook: the number of OSVs on order is equivalent to 11% of the active fleet and, although some slippage is expected, 293 units are slated for delivery by end 2015.

Long-Term Woes

The OSV dayrate index has fallen by 27% since the start of 2015 and, with no significant upturn in oil prices looking likely, pressures seem set to continue. Fleet growth stands at 2.3% y-o-y, and the issue of OSV oversupply is expected to remain significant. Against this background, the discussion of removals is likely to be ongoing theme.


On July 14th 2015, after 20 months of negotiations, Iran and the so-called “P5+1” signed the “Joint Comprehensive Plan of Action”: in return for US, EU and UN-mandated sanctions against the country being gradually lifted, Iran has agreed to roll back its nuclear capabilities. Should the deal stick, the door will open to foreign investment once more. What, then, are the possible implications for Iranian offshore oil? Should this deal stick, IOCs will soon be able to operate in Iran once more. What, then, are the possible implications for Iran’s offshore sector?

Political Locks

On the eve of the Islamic Revolution in 1979, total Iranian oil production stood at 6.0m bpd, of which around 12% (0.72m bpd) was from 13 offshore fields producing oil, all located in shallow waters and exploited via fixed platforms. The turmoil of the Revolution saw oil production drop to 1.70m bpd in 1980, and in the ensuing Iran-Iraq War, offshore fields like Salman were shut in due to military action. As a result, actual offshore oil production was less than 50% of capacity for most of the 1980s; after the War, production began to recover, peaking at 88% of capacity (0.60m bpd) in 1997. However, as US and then EU economic sanctions on Iran tightened, IOCs were forced to exit the country, depriving Iran’s offshore sector of key investment and technology. Development work slowed and much of Iran’s offshore 2P reserves (30.3bn bbl of oil; 707 tcf of gas) were locked away. At the same time, Iran lacked the resources to implement EOR at brownfields. As a result, the gap between actual and nameplate offshore production was 1.38m bpd by 2014, with production at 0.54m bpd.

Rusty Hinges

Now that sanctions are to be lifted, indications suggest Iran aims to get as much oil production as possible back onstream in 2015/16. Restoring offshore production is likely to require more than just turning the taps though. Iran’s ability to halt decline at brownfields has been curbed, in contrast to other mature producers like the U.A.E. Half of Iran’s active offshore oil fields predate the Revolution (the oldest started up in 1961). Extensive EOR work is likely to be required at such fields – one opportunity for IOCs. Thus, while offshore production is forecast to grow by 7.3% in 2015, this is mostly due to South Pars condensate production ramping up, rather than utilisation of older capacity.

An Alternative Entrance?

Iran is planning an “oil contract roadshow” in London in 2H 2015, with the stated aim of attracting foreign investment in E&P of $185 billion by 2020. However, it is likely that much of the investment will be directed towards stalled onshore projects such as Yadavaran, and to restoring production at mature onshore fields like Azadegan. A spate of onshore discoveries made from 2006 to 2008 may also be prioritised by cash-hungry Iran, particularly those in the Khuzestan province spanning the Iraq border. Some of Iran’s 7 undeveloped offshore fields like Esfandiar (532m bbl) may warrant priority, and the South Pars Oil Layer is scheduled to come onstream in 2018. But even taking into account the Caspian (home to the 2011 Sardar-e Jangal 500m bbl find), offshore oil opportunities for IOCs (and so vessel owners) may be limited at first.

It seems, then, that the offshore oil capacity gap could widen before it narrows. Certainly given its reserves Iran has long-term offshore potential, notwithstanding its troubled history. But observers expecting a quick and big uptick in oil-related offshore activity might need to be patient.


Since 1970, 179 offshore gas fields have been discovered in the Browse and Carnarvon Basins of Australia’s Northwest Shelf. From around 2005, as offshore technology advanced and Asian gas demand rose, operators hatched plans of monstrous magnitudes for these fields. However, in an environment of low oil prices and E&P spending cuts, some of these offshore behemoths now look more endangered.

Taming The Seas

The Australian NW Shelf accounts for about 15% of offshore projects globally with CAPEX of over $5bn. NW Shelf projects tend to be capital intensive, in part because they are remote, with an average distance to shore of 161km. Development thus entails long export pipelines (889km for Ichthys, for example) to onshore LNG plants, or as yet unproven FLNG technology. CAPEX in turn contributes to high project breakeven prices, as does OPEX: for example, OSVs make longer trips for far-from-shore projects. Until recently, high project breakevens stymied final investment decisions (FIDs). However, due in part to cost-saving subsea and cryo-technology, in 2007, Chevron approved Greater Gorgon, a $37bn multi-field project with reserves of 40 tcf. Subsequently, 11 more projects received positive FIDS, including Prelude ($12bn), Pluto ($16bn) and Wheatstone ($29bn).

Teething Problems

Since 2007, 4 of these projects have come onstream and the other 8 are due to begin ramping up 2015-17. However, these 12 projects have not been without their problems. Greater Gorgon, for instance, was first scheduled to start up in 2H 2014, rather than 2H 2015; CAPEX has risen by 49% to $55bn. Meanwhile projects yet to be sanctioned have seen FIDs delayed by operators trying to cut costs. Scarborough, a mooted $19bn FLNG development 286km from shore (which has now been delayed again due to the fall in the oil price) underwent multiple FEED studies following the 2010 pre-FEED. Before circumstances changed, a 2019 start-up briefly looked likely.

Monsters Have Feelings Too

NW Shelf gas projects are thought to be some of the more sensitive globally to the change in the oil price since mid-2014. Greater Gorgon’s breakeven is relatively low for the area, but still stands at $67/boe. Projects further from shore are thought to have higher breakevens, in the $80-100/boe range. No Australian project more than 250km from shore has passed FID, though 50% of those yet to reach EPC exceed this distance, casting doubts on their viability. Since the fall in the oil price, Scarborough’s FID has been postponed to 2017/18; start-up before 2023 is considered unlikely. Other projects facing fresh feasibility concerns include Equus, Browse, Greater Sunrise, Crux and Cash Maple. Indeed, the average slippage for such projects already stands at 40 months. Many may not now come onstream before 2023 and a paucity of start-ups is anticipated in the mid-term, 2018-22, due to delayed FIDs 2014-17.

Clearly, then, remote Australian mega-projects are subject to high costs and breakevens, which increases slippage risk. That being said, the long-term fundamentals of energy-hungry non-OECD economies still suggest remaining NW Shelf gas will be viable eventually. These mammoth projects are not extinct yet.


The North Sea is home to a dispersed mass of steel and concrete, namely: 509 active fixed platforms with a combined weight exceeding 8 million tonnes; 1,440 subsea structures; 9,370 active wells and their completions; and over 45,000km of pipeline. Under the provisions of the OSPAR Convention, field operators will be obliged to decommission and clean all this up one day. And that day is approaching.

Diamonds And Rust

Decommissioning entails plugging wells, removing platform jackets, topsides and subsea structures, and, ultimately, complete site remediation. Oil companies in the North Sea are now having to contemplate this process at fields as recoverable reserves approach depletion. Since first oil in 1967, approximately 54.1bn bbls of oil have been produced in the area. However, production in 2015 is forecast to stand at just 2.86m bpd, compared to the 2000 peak of 5.9m bpd. The value of offshore field infrastructure consists in its ability to assist in the extraction of oil and gas; for the 47% of fixed platform tonnage installed on North Sea fields that began production more than 25 years ago, the point at which this is no longer the case is getting closer. But only 88 platforms in the area have been decommissioned so far, and for good reason.

Worth Fighting For

Decommissioning can be money and time-intensive. The decommissioning of the Brent facilities is expected to take ten years. Even small projects are expected to take two years and more than $300m in CAPEX. Hence, operators are trying to stave off decommissioning through enhanced oil recovery (EOR) to extend field life, or by tying new field developments to existing structures. For example, while the 12 wells on Heimdal are being abandoned, the platforms are being kept to process gas from Vale and other fields.

However, it is thought that in the current oil price environment, OPEX is encroaching on profits at a rising number of fields. Operators striving for fiscal discipline are between the hammer and the anvil: either run fields at a loss, or shut fields down and book the decommissioning costs.

Pain And Pleasure

This choice might be painful for oil companies but there is potential upside for many vessel owners. Drilling rigs and well intervention vessels will be needed to plug many of the wells. Crane vessels, self-elevating platforms and heavy lift vessels will be needed to remove and transport topsides and jackets (indeed, part of the rationale of the “Pioneering Spirit” is that it is one of very few units capable of lifting massive structures like the 42,500t topsides of the “Gullfaks A” gravity base platform). MSVs, DSVs and ROV Support vessels can be used to assist throughout decommissioning and will be especially important for removing subsea structures and for site remediation, when dredgers will also have a part to play. These various vessels will need to be assisted throughout the process by OSVs and utility support vessels.

Oil companies active in the North Sea might prefer not to charter all these vessels just to exit dead fields. But sooner or later (quite possibly sooner) they will have little choice. This could potentially benefit many different owners, with decommissioning becoming an important driver of North Sea vessel demand.


The rigid pipe layer fleet is complex, varied and sometimes perplexing: S-lay, J-lay, reel-lay; barge, vessel, semi-sub; tensioners, carousels, moonpools – units therein defy easy comparison with one another. And so, unlike in many sectors of the offshore fleet, it is not immediately clear what is a ‘high-spec’ and what a ‘low-spec’ unit. What is needed, then, is a framework to analyse the 172-strong pipe layer fleet…

Offshore Operations

In essence, pipe layers are used to install rigid pipelines on the seabed, primarily during the development of offshore fields. These pipelines are used to export oil/gas to shore, or to transport fluids between seabed or surface installations within a project area. Pipe laying is conducted during the EPC phase of project development, consequent on award of (typically lump-sum) EPIC and SURF contracts, usually to specialist offshore construction companies like Allseas, McDermott, Saipem, Subsea7 or Technip, who own 4, 5, 14, 6 and 6 pipe layers respectively – 20% of the fleet. There is no pipe layer spot market as such, so comparing day rates to pick out the high-spec from low-spec units is not possible.

Inscrutable Idiosyncrasy?

Vessels’ traits are not immediately helpful either. Monohull structures account for 19% of units and barge/semi-sub structures for 81%. Pipe sections are welded on-board and deployed via J-Lay towers (8% of units) or S-Lay stingers (76%), the letter indicating the curvature of the pipeline as it is lowered to the sea floor. However, 3% of vessels have both J-Lay and S-Lay structures; 16% use cranes or have hybrid, reel-lay systems; and the tensioner capacities of lay systems (i.e. the weight of pipeline they can support) range from under 10mT up to 2,000mT. There is no simple correlation between a single feature and a unit’s capabilities: “Lorelay” has tensioners of 265mT, yet cannot lay pipes in ultra-deepwaters; “C Master”, with tensioners of 160mT, can. The secondary functions of units can also vary greatly: 10% of units have ROV capabilities, for example. Moreover, 19% of units in the flexi-lay fleet can install rigid pipelines (and 5% vice versa). How then, amidst this variation, to distinguish a ‘high-spec’ from a ‘low-spec’ pipe layer?

A Promising Perspective

One way is to cross reference the maximum pipe lay water depth of units with the maximum diameter of pipe they can lay. Thus the 12 units in the “red” segment of the inset chart (e.g. “Seven Borealis” and “Sapura 3000”) could be considered high-spec and versatile, competing with units in the “dark blue” segment for ultra-deepwater subsea contracts, but with the “light blue” segment for large export pipelines in shallower waters. In the opposite quarter of the matrix, the 55 “grey” units are mostly barges, deployed in shallow waters like the Niger Delta and Lake Maracaibo. One could say there are four (overlapping) markets for pipe layer work. The range of EPC contracts for which construction companies are likely to bid will depend in part on the segmentation of their pipe layer fleets.

So, pipe layers have an array of characteristics complicating segmentation. However, some units are clearly better suited to some projects than others. By cross-referencing factors like water depth with pipe width, one can craft a framework for sorting through this diverse fleet.


Self-Elevating Platforms (‘SEPs’) are generally used to provide offshore support for construction and maintenance projects. These units fall within the wider ‘construction’ sector in the segmentation of the offshore fleet, and can generally operate in water depths of up to 120m. The key deployment areas for these structures exist in the US Gulf of Mexico (GoM), West Africa and the Middle East. Despite high numbers of shallow water developments in the North Sea and South East Asia, there has been relatively little deployment of SEPs in these regions, although recent contracting patterns within South East Asia suggest this may soon change.

Rising Above Regional Regimen

The Graph of the Month shows the regional breakdown of producing fields with a water depth of <100m, as well as the share of self-elevating platform deployment across these regions. South-East Asia contains the largest number of shallow water developments with 552 active fields, closely followed by the US GoM (508) and the North Sea (452). However, there is a large disparity between these regions in terms of SEP deployment, with the US GoM accounting for the deployment of 161 units compared to the North Sea and South East Asia where just 10 and 19 structures are deployed respectively.

Lower deployment numbers in these regions can be largely attributed to a major factor in each region. In the North Sea, self-elevating platform use is often restricted by harsh operating conditions. In South-East Asia an ample supply of support vessels has provided ships for use in construction and support duties in the region.

Jacking-Up Orders

The current SEP orderbook includes 24 units with a record combined contract value of almost $2bn, of which 13 are for South-East Asian owners. Of the 15 contracts agreed in 2014, 60% of these are for Asian owners. Although these units will be capable of operating internationally, indications from owners including Teras Offshore, Swissco Marine and East Sunrise Group hint at a South-East Asian target market. There is a large fleet of mid-sized supply vessels in the region and historically these units have worked similar roles to the SEP fleet. However, the mid-sized supply vessel orderbook has diminished from around 200 units in 2012 to the current total of around 70 vessels, potentially supporting future deployment of SEPs in the region.

Lifting Expectations

An abundance of shallow water fields and relatively benign conditions means that South-East Asia is a region with strong potential for the future deployment of SEPs. Despite a lack of historical deployment, the attraction of competitive day rates in comparison to support vessels has reportedly begun to attract interest, in turn leading to investment in newbuild units from Asian owners.

So, a reduced orderbook for mid-sized supply units and an expected increase in field developments within China and South-East Asia could be positive news for SEP owners. Whilst still way below levels of deployment in the Gulf of Mexico, this region could provide impetus to self-elevating platform demand in the future.