Archives for posts with tag: North Sea

Over the hill; past its peak; long in the tooth: like a worn-out old racehorse, the North Sea E&P sector is sometimes discussed in disparaging terms. In recent years however, it has been making something of a comeback, gaining ground when it comes to exploration and at least holding steady-ish when it comes to production. The question is, can this pace be sustained in the current oil price environment?

Saddling Up

The UK and Norway have long been the front-runners when it comes to offshore activity in the North Sea. In the 1970s, an average of 187 offshore wells were spudded per year in UK and Norwegian waters. As the graph shows, in the years 1970-76, more than 50% of these were exploration wells. Production was low (0.85m boepd in 1975), as few of the discoveries made since the first find in 1965 had been developed. But then in 1976, Brent started up, with Ekofisk following in 1977. During the course of bringing these and other large fields onstream, appraisal and development drilling raced ahead of exploration; from 1990, the number of exploration wells drilled each year began falling too. Field operators were now focusing on production over exploration. The two countries’ offshore production peaked in 2002 at 8.64m boepd from 337 fields. This year was also the nadir for exploration drilling: of 503 wells spudded, just 32 (6.4%) were exploration wells.

Second Wind

Oil companies therefore found total production falling just as reserves were being replaced at the slowest rate since North Sea exploration began. The more prudent then applied the spur to exploration once more, even as they tried to stop production decline using EOR. Exploration in the years 2003-14 in the central North Sea met with some notable successes, like the giant Johan Sverdrup discovery in 2010, with 2P reserves of 2.2bn bbl oil and 394bn cf gas. Operators also began venturing into the mostly unexplored Barents Sea and west of Shetlands waters. Hence, in 2014, 27% of wells spudded in UK or Norwegian waters were for exploration, a share similar to the late 1980s. Production, meanwhile, fell by only 0.8% y-o-y, versus the average y-o-y decline over 2002-14 of 3.9%.

The Final Furlong?

The area’s offshore sector was thus moving at a relatively good pace. However, 2014 exploration campaigns and most incipient development projects were conceived in a more robust oil price environment than the present: E&P economics in frontier areas like the Barents Sea are highly uncertain while the oil price is less than $80/bbl. Perhaps then, with oil company spending cuts, the recovery in exploration will be stopped in its tracks and production decline may resume. On the other hand, some smaller operators are taking advantage of low rig and OSV day rates to increase exploration. Falling EPC costs could also help to reduce development project breakevens, flogging North Sea E&P onwards once more. And if the oil price were to return to $100/bbl+, then there is the potential for further upside.

So there you have it. The weaker oil price has made some oil companies pull on the reins, but there is still potential for the second burst of North Sea E&P activity to run on, in the right conditions. The area may no longer be the fiery colt of offshore E&P, but it probably has some way to run yet before being put out to pasture.


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 AHTS spot market in the North Sea is notable for the speed in which rates can shift, responding rapidly to supply and demand pressures. In 2014 alone the spot charter rate for an AHTS 18,000+ bhp fluctuated dramatically from a high of £170,165/day in August to a low of £5,819/day in the last week of the year.

Blame It On The Weatherman

Rig moves are the key AHTS demand driver in the North Sea. Pressures that affect the volume of these, along with the supply of units in the North Sea, dictate the number of available units, which in turn determine AHTS spot fixtures rates.

The largest peak in spot rates in the last three years occurred in August and September 2014. It was the result of a temporary removal of some North Sea units for work on exploration campaigns in the Russian Arctic. This caused a drop in the supply of vessels, that was eventually compounded by numerous rig moves, dropping availability and lifting spot rates.

Conversely, during December, a short three months after the September peak, AHTS spot rates in the region had fallen below £10,000/day for the first time since 2010. During the month, North West Europe was battered by a large weather depression resulting in strong winds and high seas, suspending many rig moves and forcing AHTSs to compete with PSVs for supply duty charters, bringing down the spot rates for both AHTSs and PSVs.


The price of Brent crude has fallen over 50% since June 2014 to below $50/barrel at the time of writing. As oil companies seek to rebalance their budgets in a new oil price world, exploration budgets have been cut. One of the ways in which drill rigs are utilised is the drilling of exploration and appraisal wells, demand for which has suffered in Q4 2014, negatively impacting AHTS demand in this period.

The drop in oil price has also damaged hope that exploration campaigns in expensive, harsh, Arctic environments will take place. Previously, these campaigns have taken vessels from the North Sea fleet, protecting the market from oversupply. Notably, Statoil has handed back three licenses offshore Greenland and announced that it will slow Arctic and Barents exploration to control CAPEX.

Oversupply in the North Sea can be demonstrated by the increase in the average number of vessels available. This rose steadily in 2012 and 2013, and by 39% in 2014 to an average of 13.1 vessels. This increase in supply has contributed to poorly performing spot rates in most of 2014, aside from the late summer spike. Increasing levels of supply and weaker demand indicators have forced some vessel owners to lay-up more ships in an effort to prevent oversupply impacting spot rates further, even laying-up units built as recently as 2014.

C’est La Vie

Clearly the volatile North Sea AHTS market is highly susceptible to short term demand pressures such as the weather and the whim of oil companies that dictate when rig moves occur. However, there are longer-term supply and demand forces at work, which although often obscured by dramatic short-term changes, can influence spot rates just as strongly.


As the recent plunge in oil prices sees some operators tightening their belts and their appetite for exploration seemingly diminishing, can development drilling provide alternative demand amidst the doom and gloom? The North Sea serves as an interesting example of an active drilling market throughout E&P cycles. Could this observation have implications for rig activity within other regions?

Playing The Risk

The assessment of “risk”, both financial and operational, is one of the most important factors for International Oil Companies (IOCs) when considering future projects. In periods of high oil prices, when company revenues are high and debts are low, operators are prepared to take on higher risk, lower margin projects, and are more comfortable in increasing their exposure to exploration. In a low oil price environment however, companies focus on low risk projects and increasing returns on investment, as opposed to riskier exploration operations.

Produce A Winner

This lower tolerance to risk often results in reductions to exploration budgets and activity, in particular drilling operations. In the last 12 months, global drilling rig utilisation has declined from 95% down to 89% as oil prices have declined to under $70/bbl. This trend has been typical throughout history. In 1985-87, historical reports show that global rig utilisation declined drastically from almost 90% to around 50%, following the oil price crash of the mid-80s. Despite this, some areas have fared much better than others through the bust periods

As the Graph of the Month shows, the number of wells drilled per year in the North Sea during the years 1980-98 increased from 335 to 618, despite the oil price declining to $18/bbl (inflation adjusted to 2013 $/bbl). As companies focussed on increasing production from their portfolio of newly discovered fields, increases in development drilling far outweighed declines in exploration work.
Over the same period, the share of development drilling increased from 68% to 86%, and by end-2002 over 90% of wells drilled were for field developments. This increase, throughout a period of depressed oil prices, highlights the need for development work following exploration.

Develop Your Game

In areas where the number of undeveloped fields is high (the North Sea reached an estimated peak of 583 by end year 1992), it is inevitable that development drilling becomes more prominent, as exploration operations become riskier and thus more expensive. Today, areas such as West Africa and SE Asia, where the current number of undeveloped fields total 379 and 506, are examples of this, and could witness an increase in development drilling similar to that seen in the North Sea during the 80s and 90s.

Whilst reduced exploration will likely result in short-term declines in rig utilisation and dayrates, other sources of demand could exist. Though wildcat spuds and discoveries may dwindle in the near term, areas of previously high exploration activity could see alternative demand for rigs through development drilling. After that? Well, perhaps the world will still have to go and find more oil.


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.


The shuttle tanker fleet consists of a relatively modest 88 vessels, but is of critical importance to the offshore story. The sector has always played a key role in exports from fields divorced from established pipeline infrastructure. As the move offshore into deeper and more remote areas gathers pace, shuttle tankers will be required to support production, particularly off Brazil.

Exponential Growth

The fleet has a long track record of steady growth (it was just 19 vessels at the start of 1989), and has recently undergone another expansion phase, growing from 65 vessels at end 2010 to 88 currently (up 35%). There are 8 vessels on order: until the contracting of three specialised Arctic units at Samsung in July, no orders had been placed since January 2013.

This might appear, on the surface, to be a sign of a fleet sector with muted demand growth prospects, particularly when considered in conjunction with the decade-long decline in North Sea shuttle tanker transportation evident in the Graph of the Month. However, the outlook is actually somewhat brighter. Brazilian usage has gradually increased year on year. Brazilian fields are expected to be at the forefront of the sixty potential field developments identified globally which are likely to use shuttle tankers.

There are now 25 likely future field developments offshore Brazil, which are expected to need shuttle tankers, and potentially add 1.5m bpd to shuttle tanker movements off Brazil. In the pre-salt areas, pipelines are often not feasible due to deep water and long distances to shore, so fields need shuttle tanker offtake from FPSOs.

The North Sea is an established shuttle tanker region, and now one with much activity under way to halt production decline. There are 9 future start-ups expected to require shuttle tankers, including Bream and Johan Castberg. These are expected to help shore up North Sea oil transportation on shuttle tankers to above 1m bpd in the medium term.

Fleet Consolidation

Recent years have seen the fleet become more consolidated. At the end of 2004 there were over 10 companies with just one shuttle tanker to their name but as of September 2014 there are just two companies owning only a single ship. Teekay Offshore and Knutsen NYK continue to account for a large portion of the fleet, owning 32 and 25 units each. This year alone, Knutsen acquired Lauritzen’s fleet of 3 ships: these were the first recorded shuttle tanker sales for over 5 years.

Tread With Caution

Of course, shuttle tankers are not immune to the usual cyclic problems of the offshore industry. In the past 18 months, delays in field start-ups in Brazil and the North Sea have led some companies to let charter options expire or fail to renew existing timecharters. This may limit ordering (typically orders are placed with an initial charter in mind). Over the longer term, however, further fleet expansion will be required to service additional demand. Whilst the graph no doubt shows the ‘best-case’ scenario, and some field start-up slippage will no doubt intervene, the shuttle tanker sector looks positioned for a relatively bright future.


OIMT_2013_09The South East Asia Oil Producing Area, consisting of Brunei, Myanmar, Indonesia, Malaysia, the Philippines, Thailand and Vietnam, accounted for 6.4% (1.6m bpd) and 16.8% (16.5 bcfpd) of global offshore oil and gas production respectively in 2012. Its 409 active offshore fields – 63.8% of those in the Asia Pacific – are mostly fixed platform developments. However, indicators suggest this historical tendency may be changing.

Shallow Water Bonanza

As the Graph of the Month shows, shallow water development types predominate within South East Asia. Together, fixed platforms, subsea tie-backs and extended reach drilling (ERD) accounts for 95% (388) of producing oil and gas fields in the area, reflecting the historical concentration of E&P activity in shallow Malaysian and Indonesian waters. The average water depth of producing fields is 70m and only nine are located in depths of more than 200m. SE Asia is thus comparable to the North Sea, where these development types also equate to 95% (614) of active fields and average field water depth is 91m.

Topsides Upside

Unlike in the North Sea though, active fields in South East Asia are heavily skewed towards fixed platforms: 77% (315) of active fields produce via fixed platforms in SE Asia. For the North Sea this figure is 40% (258). For every field exploited by subsea tie-back or ERD, there are 7.3 (for subsea) or 10.5 fields (for ERD) developed by fixed platforms in SE Asia. The equivalent global ratio is 2.9 or 9.0 fixed field developments per subsea or ERD field. SE Asia is also likely to remain a source of fabrication contracts for the foreseeable future: development by fixed platform accounts for 56% of fields under development in the area.

Subsea Rising

However, the Graph of the Month also shows a pronounced rise in subsea development: 11% of active fields are subsea tie-backs but 24% of fields under development are such. The average water depth of existing subsea fields in SE Asia is 150m whereas for fields under development by subsea tie-back, the average is 806m. The comparable figures for the North Sea are 129m and 168m. Rather than combining with existing platform infrastructure (as in the North Sea), subsea growth in Asia seems to be being driven by deepwater projects like Gehem, Gendalo and satellites like Gandang (off Indonesia).

MOPUs Multiplying

This suggestion is reinforced by the trend in Mobile Production Unit deployment in the region. While 5% of active fields in the OPA are MOPU developments, 15% of fields under development will employ MOPUs. In deep water, satellite fields with subsea producers are often tied to MOPUs, especially in later project phases. South East Asia accounts for 44% of global developments by MOPUs other than FPSOs (e.g. TLPs or jack-ups).

Fixed platforms will remain common in Asia, particularly given a push to develop many marginal Malaysian fields. Yet equipment and service suppliers will be encouraged by the growth in more complex development types, as more fields are developed and then start up in deeper waters.