As 2013 draws to a close, the many thousands of individuals working in the global offshore industry are unlikely to have the time to pause and take stock of just what has been achieved during the course of another hectic year.

Some would say it’s just business as usual in an industry that by its very nature has to push the physical and technical boundaries to find and access new hydrocarbon reserves. But in a year when much of the wider general public’s attention has been drawn by the smooth-running Greenpeace publicity machine to what activity might eventually get under way in the ice-bound waters of the Arctic, the offshore business itself has been busy in less chilly parts of the globe achieving record levels of activity.

This activity has been driven by the E&P sector’s desire to increasingly monetize offshore remote gas via multi-billion-dollar LNG projects in areas such as offshore Western Australia and East Africa as well as the ongoing push into ultra-deepwater and harsh/sour gas environments.

Deeper and darker

So how far has the industry pushed into the deep, dark depths in 2013? To put it into some perspective, in 1970 the average distance from shore of known oil fields stood at 60 km (37.3 miles) with the average water depth being 54 m (177 ft). To date this year the average distance to shore has more than doubled to 134 km (83.3 miles), and the average water depth is 15 times deeper at an impressive 876 m (2,874 ft), according to analyst Clarkson Research Services.

Offshore gas projects have pushed the boundaries even further, with Woodside Petroleum’s deepwater Pluto LNG project off the coast of Western Australia coming onstream in 2012 and currently holding the record for the world’s longest gas well subsea tieback at 210 km (130.5 miles), stretching back to an onshore LNG plant on the Burrup Peninsula.

Offshore production rising

Offshore Review Figure 1

FIGURE 1. Technological advances have reduced the cost of deepwater wells to the point where offshore projects can now compete with onshore rivals for investment dollars. (Data courtesy of Wood Mackenzie; Source: Ocean Rig)

Total offshore production of oil and gas this year is expected to hit close to 50 MMboe/d, according to a recent presentation by analyst Douglas-Westwood.

Offshore oil production makes up around 30% of the world’s crude output of almost 90 MMb/d, while global offshore gas production will be close to 2.8 Bcm/d (100 Bcf/d) or around 18 MMboe/d, Clarkson Research estimated. With the increasing number of major offshore gas and floating LNG (FLNG) projects emerging driven largely by market demand and its more environmentally friendly image, the proportion of gas in terms of total offshore output will continue to grow.

Historically northwest Europe and North America have been the main offshore gas producing regions, accounting for 54% – 991 MMcm/d (35 Bcf/d) – of global output at their peak in 2001. But by 2008 the Middle East began to take on that mantle, to the point that – largely thanks to output from the giant offshore South Pars and North fields of Iran and Qatar, respectively – it accounts this year for around 33% of world offshore gas production. According to Clarkson Research, this continual rise of the Middle East in terms of its offshore gas over the last decade has been complemented by a growth in output from the Asia-Pacific region to an estimated 643 MMcm/d (22.7 Bcf/d)

in 2013, representing approximately 22% of global offshore gas production. Northwest Europe, North America, and the Mediterranean are expected to account for 17%, 9%, and 9% respectively this year.

According to the latest market information, there were 261 offshore fields under development as of September 2013 that will produce associated or nonassociated gas. According to Clarkson Research, a total of 124 are scheduled to come onstream by year-end 2014.

Pragmatic project approach

Amidst such promising signs for the offshore sector, it may seem a little strange in an industry review of 2013 to highlight two of the most high-profile delays to have occurred in world-class offshore megaprojects.

But these delays on BP’s Mad Dog project in the Gulf of Mexico (GoM) and Woodside Petroleum’s Browse LNG development offshore Australia do not reflect a problem during the development and execution process, as one might expect. This is rather a more pragmatic approach by the operators themselves to dealing with spiraling cost estimates before nearing any potential problems and resulting interminable delays. The result? Both went back to the drawing board earlier this year to drive down those estimated costs.

This more cautious attitude in tackling megaprojects is a welcome recognition by the upstream industry that its performance thus far on such large developments has been distinctly unimpressive. According to Edward Merrow, founder and CEO of Independent Project Analysis Inc., four out of every five upstream oil and gas megaprojects fail. Cost-wise he defines such projects as requiring a minimum of US $1.5 billion in capital cost while also being highly complex in terms of engineering and resources.

Worryingly, he points out that a project that does not exceed 25% of its initial budget is currently considered successful as long as it also experiences no cumulative delays of longer than a year. It also is apparent that two-thirds of failed projects studied suffered production-attainment problems, meaning these didn’t even achieve 50% of the targeted production for the first two years of operation.

It is often a field operator’s perceived need to bring projects onstream as quickly as possible that causes these problems, but it appears that – this year at least – the offshore sector is learning the lessons of the recent past.

Costs cause Mad Dog rethink

On Mad Dog, BP has opted for a slimmed-down spar production platform for Phase 2 of the development in the GoM, having stalled the project earlier this year due to the rising forecast costs.

Highlighting the problem of soaring cost inflation levels generally on offshore projects, BP laid the blame for its rethink squarely on this issue and put its so-called “Big Dog” spar on a weight-loss program with the help of its project contractors.

BP CEO Bob Dudley admitted in the major’s mid-2013 results presentation that the company was seeing sector inflation of around 5% per year for both capex and opex. Dudley said that what the company had done “is I think what you would expect us to do as we refine capital cost and project designs. If they don’t fit, we’ll take a step back rather than committing and then going down the road, as they say in the US, to Abilene [Texas] with some big projects. So I think this is exactly what you’d like to see us do.”

A final investment decision is expected possibly by year-end or early 2014. Mad Dog lies in Green Canyon Block 782 in water depths ranging from 1,372 m to 2,073 m (4,500 ft to 6,800 ft), with recoverable reserves put at up to 450 MMboe. First oil was originally penciled in for 2018.

Browse revamp

Similar to BP, Woodside and its partners pulled the plug on one of the world’s biggest offshore/onshore LNG projects when it ditched plans for an onshore plant to receive gas from its remote Browse deepwater field off Western Australia.

The operator, along with Shell and other partners, is still weighing plans for an FLNG solution for the field after deciding earlier this year that escalating costs were just too much. The companies are considering alternative development concepts for the field, with the FLNG option the favored solution for the project, especially as Shell is already under way with the development of its own Prelude gas field offshore Western Australia via an FLNG unit due onstream in 2017.

Woodside and Shell signed a technology agreement, with the Australian operator saying using an FLNG solution could save around 20% on Browse compared to the original onshore plant plan.

Woodside’s CEO Peter Coleman said that the original plan was shelved after a technical and commercial evaluation determined the concept did not meet the company’s commercial requirements for a positive final investment decision. Coleman said FLNG had the potential to commercialize the Browse resources in the earliest possible timeframe.

He added that the cost escalation on Browse had been “consistent with other projects in Australia. Unfortunately, the cost escalation has been such that the total costs for Browse have resulted in the current development not being commercial. The decision is a commercial one.”

Collaboration trend

The trend of companies increasingly collaborating to reduce costs was a topic discussed at the offshore industry’s biggest event of the year: the 2013 Offshore Technology Conference in Houston.

The operator-funded DeepStar global technology initiative has been the upstream industry’s most successful collaboration in tackling deepwater challenges. But in a DeepStar panel discussion at the show, the need for further collaboration and standardization was stressed as crucial to help companies push into ultra-deep water, both in terms of accessing new reserves and also maximizing production from existing assets.

Occo Roelofsen, director of global oil and gas practice at McKinsey & Co., pointed out that if the GoM was operated by a single company it would dramatically speed up the process of bringing fields onstream, developing standardized technical solutions, and maximizing the value of its assets. This theoretical single operator would have around $50 billion of projects today in action but would have the potential to turn those projects into assets with a net present value of up to $110 billion, mainly through optimization.

It also would have the ability to reduce capex and opex by an estimated $46 billion over the next decade, he added.

Reflecting the apparent thinking behind BP’s and Woodside’s decisions on Mad Dog and Browse, he said, “Deepwater oil and gas has been all about technology. Technology is a very important component – but I would say an important next step is in the economics and collaboration to find more value.”

Drilling highlight

Another speaker, Steve Thurston, Chevron’s vice president of deepwater exploration and projects, flagged another milestone achieved during 2013. He highlighted dual-gradient drilling technology as being a clear example of a DeepStar technology that progressed from an initial research project in 1996 to full deployment earlier this year by Chevron in the US GoM. The technique essentially eliminates water depth constraints for deepwater wells by replacing the mud in the riser with seawater-density fluids.

Rig market

The offshore rig market itself performed strongly throughout the year, with the total number of rigs in action standing at 819 as of mid-November. Utilization rates for deepwater rigs in particular hovered at around 90%, with the highest utilization for that category of rig in Brazil, followed by the North Sea, West Africa, and the US GoM.

Technological advances have reduced the cost of deep-water wells generally, according to a recent briefing by deepwater-focused driller Ocean Rig, to the point where offshore projects are now competitive with onshore ones (Figure 1).

Ultra-deep water remained the key growth market in the drilling space, with exploration drilling activity remaining strong globally. Demand for development drilling programs will naturally follow, it added. However, the contractor did point out that the supply of new ultra-deep units was being limited by yard capacity. A total of 13 ultra-deepwater newbuild units have been ordered by rig contractors as of early November this year.

Rig major Transocean highlighted the favorable market prompting the orders for newbuilds of this type of rig, with day rates for the highest specification units stable at $550,000 to $600,000 throughout 2013. A total of approximately 40 new floating rigs and 60 jackup units are under construction and due to be delivered through 2014, the company said in its latest results presentation.

For shallower waters, fellow rig player Noble Drilling said recently that out of the offshore industry’s existing fleet of 429 jackups, a total of 157 are less than 10 years old. On top of this there are currently another 119 under construction, meaning an eventual total of 276 units will be either new or less than a decade old. That will bring the overall age of the total future fleet of 548 units down significantly, helping to address industry concerns over what had been a potentially alarming aging fleet.

Offshore discovery count

So how many offshore discoveries have been made this year? An end-of-year figure is not yet available, but by the end of the third quarter there already had been 45 significant new oil and gas finds, with at least 19 of those in deep water, according to information compiled from various presentations given at the Barclays CEO Energy Conference.

There is not room to run through them all here, but suffice it to say the key areas for producing the goods reflected the trend of recent years, with Brazil, East and West Africa, the GoM, Western Australia, and the Eastern Mediterranean all contributing significant finds.

Key spend trend of 2013

The upstream industry’s rising development expenditure levels this year reflect the sector’s increased focus on exploiting what it has found offshore in recent years.

The floating production sector’s order activity is always a good indicator, and since the beginning of 2013 there have been orders for 24 floaters with a total contract value of around $19 billion, according to analyst International Maritime Associates. These include 11 FPSO vessels, two tension-leg platforms, one spar, two barges (one for oil and gas and one for LNG), seven floating storage and regasification units, and one mobile offshore production unit.

The order intake pace this year has been averaging 2.4 units per month, IMA said, which is nearly double the long-term average. There were 218 floating production projects in various stages of planning at the beginning of November.

This included an order by Total to Samsung Heavy Industries for a $3 billion FPSO vessel for the operator’s deepwater Egina field offshore Nigeria, achieving the perhaps unwanted milestone of being the most expensive FPSO vessel ever ordered.

However, it also reflects the increasing complexity and scale of many of today’s crop of new field developments in remote or deepwater areas, not only in the floating production sector but also in the subsea and vessel segments.