Archives for posts with tag: rig

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.

Rollercoaster

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.

OIMT201501

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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.

OIMT201412

‘Pre-salt’ is usually a term associated with Brazil, where giant offshore field discoveries in the Santos and Campos basins have been grabbing headlines since 2007. Now oil companies are looking across the ocean for their pre-salt game. Conjugate basins offshore Gabon, Congo and Angola could be as juicy as the Santos and Campos pre-salt plays have proved. Following a number of recent scores by Cobalt, Eni, Harvest, Maersk and Total, the hunt is on.

Gearing Up

As the Graph of the Month shows, 16 wells targeting West African pre-salt reservoirs have been drilled since start 2011 with a success rate of 75%: 9 offshore Angola, 6 off Gabon and one off Congo. Oil from West African pre-salt was in fact first found in 1968. Its prospective yield was not appreciated though, as only recently did seismic imaging become able to give an accurate picture of the pre-salt. The ultra-deepwater of Angola’s Kwanza Basin also inhibited pre-salt exploration before sixth generation floaters. But, as Brazil has shown, operators now have all the technology they need to pursue the pre-salt.

Hunting Elephants

Some 27 future pre-salt wells are reportedly planned by oil companies or are anticipated through to end 2015, as the Graph of the Month shows. Four of these wells have been spudded. Often smaller E&P companies play a vital role in opening up new frontiers. In West Africa though, supermajors and other large players are already loading up. Conoco has 4 planned wells; Repsol, 3; Eni, 2; Shell, 2; and Total, 2. Of the 27 wells, 70% are offshore Angola and will therefore be in water depths ranging from 800-2,000m. The remainder are to be spudded off Gabon, likely in water depths up to 300m. In either case, companies will be hoping to hit world-class finds, like Cobalt’s Cameia discovery, which is expected to be brought onstream at 80-120,000 bpd in 2017.

Fieldcraft

So, the West African pre-salt play is still in the early stages of exploration and appraisal. If it proves prolific though, and if operators can bring it to fruition, a pre-salt bonanza would more than offset production decline from West Africa’s mature fields. With less stringent local content requirements and more international oil company control, development may be less fraught than in Brazil. Cobalt have already announced plans for 3 multi-field pre-salt hubs centred around the Cameia, Lontra and Orca fields offshore Angola. Given that the average water depth of Angolan pre-salt wells is 1,274m, MOPU solutions are likely to be favoured. The previous caveats noted, the FPSO ordering boom in Brazil could be replicated in Angola, which already accounts for 23% of world FPSO deployment (second to Brazil). In the shallower waters off Gabon, fixed platform solutions are probable, if finds reach the development stage.

In the near term then, the pre-salt safari offshore Africa looks to be an exciting campaign, with potential to generate even more interest in the region and hence opportunities for survey vessel and rig owners. Out towards the end of the decade, Angola could be the new Brazil, with pre-salt development contracts abounding.

OIMT201406

OIMT01Since the start of 2010, the drillship fleet has grown 98% and the number of semi-subs capable of drilling in >5,000ft of water has grown 45%. This suggests increasing demand for rigs capable of drilling in deep and ultra-deep water, but how much is currently taking place at these depths?

Rigs In The Middle

The Graph of the Month shows known current water depths in which active drilling rigs are deployed. Whilst jack-ups dominate shallow depths, floaters are drilling mostly in “midwater” (500-5,000ft), where 57% of semi-subs and 45% of drillships are currently deployed.
In deeper water (5,000-7,500ft), 19 >5,000ft semi-subs and 33 drillships are known to be currently drilling. However, only 10% of the active drillship fleet and only 1% of semi-subs are currently deployed in ultra-deepwater. Overall, this means that only half of the active drillships and less than a quarter (24%) of >5,000ft semi-subs are currently located in deep and ultra-deep water. Only 4% of the current floater fleet are currently deployed in ultra-deepwater.

Deeper Potential

Although the current active drilling fleet contains over 105 floaters capable of drilling in >7,500ft water depths, the graph shows that only 9 floaters are currently deployed at such depths. The remaining rigs are therefore deployed in water depths much shallower than their specifications allow.

For example, of the 25 rigs in the current active fleet capable of drilling in water depths 12,000ft or greater, only 5 are currently known to be drilling in ultra-deep water. Of the remainder, 8 are in deepwater and 12 are in midwater. Despite the fleet’s ability to drill in ultra-deepwater, present demand is at mid- and deepwater depths.
The newer generations of floating MDUs have additional advantages in terms of technological sophistication (such as secondary derricks or drillfloor automation), which can make them attractive to operators that might not necessarily need their full depth capabilities. This can make them attractive in midwater harsh environments (e.g. in the North Sea).

Floater Flexibility

However, demand for ultra-deepwater drilling is increasing and expected to continue growing. Bearing this in mind, the orderbook for rigs capable of drilling >5,000ft remains strong (16 semi-subs of this ability and 76 drillships are currently on order). As ultra-deep fields are increasingly explored and developed it is anticipated that a greater share of floaters will be deployed in deeper water, maximising their capabilities.

Ultra-deepwater is expected to be the most rapid source of future demand growth for floating MDUs. However, mid/deepwater demand will remain important. As shown, the existing fleet and orderbook is well equipped to cater for this shift. Depths in which floaters are deployed in the future depend on whether there is investment in next-generation specialist midwater floaters, equipped with the technical innovations of recent ultra-deep rigs. Alternatively, operators may prefer to add to rig supply for ultra-deepwater drilling, which will still provide options for deployment in a broad range of water depths if required.

OIM08In 1947, the first offshore oil discovery was drilled out of sight of land. Albeit only 29km away from the Louisiana coastline, and in water depths of just 4.3m, this achievement began an new era of offshore oil production. The movement of offshore operations into deeper and more remote regions has been previously documented by Clarkson Research, and as this trend continues we take a look at how the industry has prepared for this development.

Deeper and Darker

The Graph of the Month shows the trend in the characteristics of all known offshore oilfields against their year of discovery. As the more accessible fields became less available and less productive, companies moved further offshore and into deeper waters. In 1970 the average distance from shore of known oilfields stood at 60km, with the average water depth being 54m. By 2013 the average distance to shore had more than doubled to 134km, and the average water depth was 15 times deeper at an impressive 876m.

As well as increasing average water depths and distance to shore, many newly discovered fields are also in areas designated as harsh environments. Vessels operating in these frontier regions may face adverse weather conditions, longer periods of deployment and greater demand for capacity in order to maximise their efficiency.

Building for Tomorrow

In response to these more challenging requirements, the offshore industry has already altered its contracting preferences. One example of this is the trend in newbuild contracting of PSV vessels. Large PSV (>4,000 dwt) newbuild contracting in 2012 was almost 5 times higher than the number of contracts in 2009. In comparison small PSV (<3,000 dwt) newbuild contracting has decreased by 14% in the same period. The average deadweight of PSV contracted increased by almost 60% between 1990 and 2012, from 2,500 dwt to 4,000 dwt.

Another example of the offshore industry’s response to the increased water depths of newly discovered fields can be seen in the volume of newbuild orders for drillships. At present the number of drillships on the orderbook stands at 80, which is 88% of the current active fleet. In comparison to this the orderbook for Jack-Up rigs capable of drilling up to 300ft is just 13 units, a mere 4% of the existing fleet, highlighting the move from low specification, shallow water drilling units towards higher specification, deep water rigs.

Further Preparations

Whilst newbuilding of higher specification units has increased, some exceptions do remain. For example, ordering of ice class vessels has slowed in recent years despite an increase in Arctic exploration. Whilst this is still a developing sector which could fuel medium-term contracting demand, it is understandable that the recent focus of contracting has been on units intended for warmer waters. This is where the majority of deep water discoveries have occurred, and is the reason the offshore industry is gearing up for remote drilling accordingly.