Glimmer of optimism as offshore learns to do more with less

Simplified well designs, integration of services helping to push operators’ full-cycle returns higher despite low oil price, but more rig retirements are needed and new compensation models must be considered

By Alex Endress, Editorial Coordinator

Signs of recovery – even if only slight – are afoot in the offshore drilling industry. Companies have learned to do more with less, with exploration drilling costs falling by 50% and development drilling costs falling by 30% over the past two years, according to Wood Mackenzie. In fact, the company forecasts that the number of offshore exploration wells drilled is expected to increase by about 14% this year, going from 215 drilled in 2016 to 250 in 2017.

Rig dayrates remain low, however. Many floaters and jackups – if they are working at all – are earning less than 50% of what they were making pre-downturn. “There’s no doubt that rig rates are still strained, and that is a big part of the story, but the performance improvements and improved economics of well designs are also big reasons for the expected increase in offshore exploration activity,” said Dr Andrew Latham, Vice President of Exploration at Wood Mackenzie.

“Even though oil prices have come down and remained much lower than they were a few years ago, we actually think that returns will be better on today’s wells than they were when we had $100 oil prices.”

Full-cycle returns on exploration wells are expected to reach an average of 11% per well – up from only 3% in 2014, Dr Latham said. “We calculate this by modeling the cost of the exploration well versus the value of the discovery and the cost of developing the discovery. The lower the post-tax cost of the well, the higher the return of the well can be.” If the drilling industry continues to transform itself into a leaner enterprise, he added, it could reach full-cycle returns up to 15% per well by 2020.

One of the most important ways in which well designs are contributing to better performance and lower cost is simplification. Many operators are opting to drill shallower wells. The average total depth of an offshore exploration well was approximately 11,150 ft (3,400 m) in 2016, down from an average 13,450 ft (4,100 m) in 2013.

“There’s less appetite for deepening wells in hopes of another find,” Dr Latham explained. “If the primary objective is at a certain depth, most operators will leave it at that instead of drilling down another half kilometer or so, looking for whatever may lie deeper down.”

Other examples of simplification include less coring, less sidetracking, and less sophisticated logging and data gathering programs.

The result is offshore exploration wells are now being drilled approximately three weeks faster – 55 days in 2016 compared with 75 days in 2013. The high-grading of rig fleets has also helped in this achievement, he noted, because operators are able to hire the best drilling rigs with the best equipment and the highest-performing crews. “With so much of the drilling fleet idle, operators are clearly going to be using the more capable end of the fleet,” he said.

More with less

Statoil is aggressively examining all aspects of its business to reduce costs. In drilling, the operator has been able to increase its efficiency so that it was able to drill 394 ft/day (120 m/day) in 2016, compared with 246 ft/day (75 m/day) in 2013.

“We set up a detailed plan around the drilling procedures we wanted to improve – everything from connections on the rig floor to circulating to oil cleaning – all of that has been fine-tuned,” said Per Haaland, Statoil Vice President Drilling and Well, Efficiency and Rig Management. “We set short-term goals with the crews and gave them consistent feedback. Eventually we reached our long-term goal of 50% improvement.”

This efficiency gain has allowed Statoil to drill more wells even as the company has reduced its rig capacity by 30% over the past three years. In 2016, Statoil delivered 119 wells, including multilateral wells – which is six more than the planned 113. For 2017, the company expects to deliver approximately the same number of wells – but likely on a slightly tighter drilling budget than in 2016, which was approximately $6.5 billion (NOK 56 billion).

“We are still finalizing the budget, but we don’t expect any increase in drilling spend, and it may even go down a bit,” Mr Haaland said. “Aside from the efficiency improvements, we are also designing simplified wells, and we are designing the wells to a cost target. That is our main contribution to reducing costs as an operator.”

However, in order to push efficiency even higher going forward, Mr Haaland said the industry will have to reexamine the structure of service contracts, as well as the structure of compensation for service companies. “We are moving toward more integration of services and fewer service companies onboard the rig,” he said. “Things like casing running and mud treatment services – we want drilling contractors to take responsibility for those things.”

More integration would also allow service companies to collaborate better for a more efficient drilling program, he noted. “The model of integration would allow us to tender all services together at one time, which would give the companies incentive to work together because they are all working toward a common goal.”

In fact, Statoil believes that there is potential to reduce the headcount on drilling rigs by 30%. This can be achieved by moving jobs, such as directional drilling and the operation of remotely operated vehicles (ROVs), to the shore. “In Norway, we work in an area with a very good infrastructure. We have 4G networks over the southern part of the shelf, which allows us to run our ROVs from shore. That’s something we’ve tested. So why do we need an ROV crew with six people on the rig when you can do it from shore over a 4G connection?”

In some cases, work can also be transferred from third-party service companies to drilling contractors. “We need oilfield services crews for specialty jobs, like mixing cement or fine-tuning electronics, but some things can be transferred to rig crews. For example, things that need to be moved, plugged in, screwed together, hoisted, lowered – you don’t need extra oilfield services people onboard to do those things,” Mr Haaland said.

In order to support all of these operational and logistical changes, however, the dayrate model for drilling rigs must be examined and possibly changed, he continued. “We need a compensation format that really delivers efficiency,” he said. “The dayrate is an outdated compensation format.” In fact, Statoil is now experimenting with meter rates for oilfield services contracts. “It is probably too risky for drilling contractors to go on a full meter rate at the moment, but we need to do something.”

He suggested transitioning to a combination of dayrates and a meter rate, versus using just a basic dayrate formula.

“This means that the faster you drill, the more revenue you are able to make. The good thing we see is that there is a true willingness amongst drilling contractors and service companies to improve the industry efficiency.”

Driving out waste

Offshore drilling contractors have made substantial efforts to drive out operational waste in the past two years, but there is still work left to do. “Over the course of this downturn, tremendous strides have been made to get rid of the fat that had been added to the system after one of the longest up-cycles the industry has ever seen,” said Simon Johnson, Senior Vice President – Marketing and Contracts at Noble Corp. “The management of operating costs will remain an intense focus for the foreseeable future for most of the major players in the offshore drilling space.”

In 2017, Noble launched OneSite – a wellsite integration initiative under which the company takes responsibility for services that have traditionally been completed by oilfield service companies. These services may include drilled cuttings treatment, mud logging and data transmission.

“We are essentially looking across the full range of service companies that operate at the well site and seeing where we can effectively contribute to a reduction in total personnel headcount, as well as reduction of the total number of third-party companies working onboard our drilling rigs,” Mr Johnson said. “We are reducing these numbers by bundling services on top of what we ordinarily provide day to day without exposing ourselves to excessive commercial risk.”

Noble is currently looking for an operator partner and hopes to implement this initiative on a rig within six months. “There’s a myriad of companies that work at a modern well site, and a lot of those people are doing tasks on a callout basis that we could easily provide within our work scope by simply adding a few bits of equipment or utilizing new, emergent technologies,” he said.

“OneSite, together with our Digital Rig Solution – which applies predictive analytics to our maintenance program and operational performance – is another example of Noble leveraging disruptive business models to improve efficiency and deliver value to our clients. Potentially, we may redraw some of the traditional fault lines of responsibility and, ultimately, increase our competitiveness in the drilling contractor space.”

Driving out inefficiency is increasingly important for offshore drilling contractors, as new fixtures on rigs around the world approach operating cost levels. Dayrates for all rig types were halved between 2014 to 2016, and Mr Johnson said he expects no improvements in 2017. Dayrates in 2016 averaged $124,470 for Noble’s 14 jackups, $166,253 for its six semisubmersibles and $474,462 for its eight drillships.

“Dayrates have flattened out, and I don’t expect any appreciable movement until you see utilization rates moving back up toward the 80% range,” he said. “Most industry participants are currently experiencing utilization in the 50% to 60% range.”

In terms of fleet utilization, semis and drillships have both taken significant hits, although jackup utilization has actually improved for the company, rising slightly from 82% in 2015 to 86% in 2017. “The semisubmersible segment, particularly conventionally moored rigs, has proven to be a very challenging part of the market. The jackup segment will be the segment to improve faster and earlier than the floating segment for the same kinds of reasons that onshore drilling has rebounded quicker than the offshore industry,” Mr Johnson said. “Every day is going to be a challenge until we experience a higher and sustainable oil price and investment patterns improve among our key customers.”

While higher oil prices remain the single most important factor for boosting rig utilization rates, Mr Johnson said operators can also help by reaffirming their commitment to working with the offshore supply chain to improve cycle times. “Offshore needs to be more competitive relative to alternative investment onshore. There’s certainly been a flow of capital on a preferential basis in the near term toward the Permian and unconventional onshore plays in the US. However, we believe that is only a short-term response. Longer term, the only way that operators – and the IOCs, in particular – can find the volumes they require is going to be through offshore reservoirs.”

Another key factor will be continued retirement of older rigs. Since the start of 2015, Noble has retired five semisubmersibles, one jackup and one drillship. “We need to see a broader commitment amongst industry participants to examining fleets and taking those rigs out of service that don’t have a role to play in the medium to long term. People also need to make harder decisions about cold-stacking units sooner rather than later.”

Unconventional competition

In the current energy landscape, offshore drillers recognize that they are no longer competing only with other offshore drillers. They’re now competing with onshore unconventional shale, and they must find ways to sustainably increase offshore drilling efficiency. “If we can do that, it will encourage our customers to provide funding and investment into more offshore opportunities,” said Terry Bonno, Senior Vice President, Industry and Community Relations at Transocean. She estimates that the offshore industry will need to push breakeven levels well below $50/bbl to compete with shale projects.

Transocean estimates that approximately half of offshore cost reductions that have been realized since 2014 are sustainable. To address the other half, the company is undertaking various strategies aimed at retaining higher levels of efficiency through all cycles.

One such strategy is using data analytics to enable condition-based monitoring (CBM). “We’re working with our original equipment manufacturers to further improve uptime by leveraging core competencies, condition-based monitoring and maintenance services,” Ms Bonno said.

In December, Transocean signed two 10-year service contracts, with Cameron and Schlumberger, for the management of risers in the Gulf of Mexico and of pressure-control equipment on nine Transocean rigs. These contracts were followed in January by the announcement of a contractual service agreement, under which GE Oil & Gas will provide condition-based monitoring and other maintenance services for pressure-control equipment on seven Transocean rigs.

Further, Transocean has developed what it calls performance dashboards, which take a data-driven approach to improving processes in order to improve efficiency. “We can now sensor our rig equipment and break down tasks that we spend most of our time doing – like tripping and connecting – on a second-by-second basis,” Ms Bonno explained.

“We can also compare the performance of each crew on every operating rig and break that information down into such small tasks. We can learn from each crew team and further identify efficient ways of working, thereby improving well performance and efficiency for our customers. This process also inspires healthy competition amongst the rig teams in the fleet. We can then implement further training for our crews in order to make similar performance enhancements across the entire fleet.”

• Exploration drilling costs have fallen by 50% and development drilling costs have fallen by 30% over the last 2 years.
• The number of offshore exploration wells drilled is expected to increase by about 14% this year, going from 215 drilled in 2016 to 250 in 2017.
• Many floaters and jackups are earning less than 50% of what they were making pre-downturn.
• Full-cycle returns on exploration wells are expected to reach an average of 11% per well, up from 3% in 2014.
• If the drilling industry continues to transform itself into a leaner enterprise, it could reach full-cycle returns up to 15% per well by 2020.
• The average total depth of offshore exploration wells fell from 13,450 ft in 2013 to 11,150 ft in 2016.

So far, results have been encouraging. In Q2 2016, when the performance dashboards were still in the process of being implemented, the company’s total revenue efficiency was 97.8%. In the second half of the year, Transocean recorded over 100% of revenue efficiency, Ms Bonno said.

While innovative and data-driven initiatives, such as these, signal positive impacts for the future, Transocean, like its peers, recognizes that market conditions will remain challenged in the near term. The market remains highly competitive, and the only new contract opportunities are smaller, well-by-well programs. Transocean’s total fleet utilization fell from 65% in December 2015 to 45% in December 2016, and no meaningful improvements are expected until 2018 at the earliest.

“There’s no doubt that 2017 is going to be very challenging for offshore rig contractors,” Ms Bonno said. “We’re already formally tendering for opportunities in 2018 and 2019, so that’s when we see the market beginning to improve.”

Market insulation

For smaller drilling contractors like Atlantica Tender Drilling, finding a niche in long-term development drilling can be a way to shelter itself from the pains of the downturn. The company has a fleet of three tender-assist rigs, consisting of one barge tender and two semisubmersible tenders, that were built specifically for development drilling programs in South America and West Africa. Two of the semi-tenders, which remain under long-term contracts through 2018 and 2020, were built to work on tension leg platforms in benign weather environments. They were also designed drill wells in deep waters where operators prefer to have a dry tree design rather than opting for a subsea tree development, Atlantica COO Mike Cadigan said.

“Because our rigs were built specifically for long-term development drilling programs, we’ve managed to maintain our rates. Our contracts are intact, which supports our debt and equity structure,” he explained. “The duration of our contracts should keep us contracted through the downturn.”

Atlantica’s Beta semi-tender assist rig is on a 1,500-day contract with Petrobras that began in March 2014. The rig is currently warm-stacked in Brazil because Petrobras has paused drilling to complete geological evaluation work, but the rig is still on contract and is set to begin development drilling again mid-year. “These are long, 180-day wells. We’ve drilled three of them in Brazil so far, and there are plans to drill at least two more,” Mr Cadigan said.

The company’s other semi-tender assist rig – the Delta – was delivered in mid-2016 and began working for Total in the Congo in September of that year. It was designed specifically for development drilling on the Moho Nord project in the Moho-Bilondo license, approximately 75 km off the coast of Pointe Noire. The contract duration is 3 ½ years.

Atlantica’s third rig, the Alpha, is a barge tender assist that’s suited for shallow-water drilling and low-cost workover drilling. It is currently warm-stacked in the Congo. “There are already some indications that several operators from West Africa in Cameroon, Gabon, the Congo and Angola need to go back and work over some wells. We are hopeful that we can put the Alpha back to work within a year or so,” Mr Cadigan said. “Many operators can bring extra production on stream by doing some quick workovers on the existing brownfield developments in those countries.”

Atlantica doesn’t expect changes to its fleet this year, although the company has a long-term goal of managing other assets such as jackups. “If we have a good joint venture established with different investors or with yards, we’d look at something that doesn’t necessarily have a contract attached,” Mr Cadigan said. “You just have to look at the economics of the deal. If a rig is cheap enough and you can factor in a certain amount of stacking costs with a lead-up to putting a rig to work, then we’ll look at it.” DC

OneSite and Digital Rig Solution are registered terms of Noble Corp.