With well costs escalating to consume up to half of a project’s funding, operators are seeking ways to trim costs. During IADC’s Deepwater Drilling conference in Rio de Janeiro in March, operators discussed some of their strategies to trim costs and highlighted some of the other challenges of drilling in salty environments. Jennifer Pallanich listened in.
Rig rates remain too high now that oil prices have come down, Petrobras general manager Braulio Bastos told IADC Deepwater Drilling conference attendees. ‘We are looking at getting rid of the rigs, I’m sorry to say,’ he said, adding that one possibility is rigless drilling with a torpedo drilling base.
The well construction industry has increased its prices more than the rest of the industry, he said, having grown from 25-30% of a project’s budget to gobble up to half.
‘I’ve never personally felt so much pressure because of well construction costs as I have now,’ Bastos said.
When it comes to drilling, completions, and subsea work, he explained, Petrobras is ‘shifting our metrics from NPT to actual construction time’. NPT has remained steady at 25-30% over time, he noted. Because of the way learning curves work, it’s very difficult for the industry to improve much on the current NPT rates, he said, describing this as ‘a lot of effort for a small gain’.
Kevin Carey, general manager for deepwater and complex wells at Chevron, cited his company’s Jack discovery as an example of the learning curve for drilling in the Gulf of Mexico’s subsalt in the Lower Tertiary. The discovery well in 2004 took 160 days to drill, while similar wells now take about 80 days.
Some of those leaps in halving the drilling time include a focus on rock mechanics, an integrated drilling team, and relying on proven processes, Carey said.
With the Jack discovery well: ‘We spent 81 days in salt . . . it was quite a revelation, spending that much time in salt.’
The supermajor’s deepwater Gulf of Mexico portfolio is heavy on subsalt acreage. ‘When we first started, our philosophy was “salt is our friend”, like casing. Which was a good philosophy for a little while,’ Carey noted. But drilling through salt poses some problems, he added, describing salt as ‘a real nemesis’. Above the salt, concerns revolve around wellbore stability and shallow water flow sands, seeps, and expulsion events. In the salt, concerns include vibration and shock, salt creep, flow, lost circulation, wellbore instability in sedimentary inclusions and sutures. Subsalt, concerns are well flow in high-pressure sands, lost returns, wellbore instability, and flowing tar.
‘The problem that is probably the most annoying is tar,’ Carey said. ‘Tar is a challenge in that we can’t really see it in the seismic.’
He noted a Miocene success rate of 33%, compared to a Lower Tertiary success rate of 43%, when initial expectations were a success rate of one in eight, adding that 43% ‘is actually a pretty good ratio, considering you’re somewhat blind’ because of the salt.
Gulf of Mexico salt differs from that offshore Brazil. As Petrobras petroleum engineer Augusto Hougaz explained it, subsalt is allochthonous or the reservoir located below the salt after the salt moves, while pre-salt is autochthonous or the reservoir deposited before the salt’s deposition. That translates to a few differences in dealing with salt between the two regions. The Gulf has seen instances of lost circulation in the rubble zone, something not yet encountered offshore Brazil. Drilling in the Gulf of Mexico subsalt play is vertical or on a slant while offshore Brazil, the drilling needs to be built on in the salt.
Petrobras is ‘very concerned about the technical challenges in the pre-salt’, Bastos said. One solution the company is considering is liner drilling, at least through problematic areas if not for the entire hole. Other drilling areas of focus include bit design, the BHA and vibration mitigation.
When it comes to automation, ‘you guys from a drilling perspective are living with the nightmares of the past’, declared NOV vice president for E&P business and technology, David Reid. He suggested the industry is sending mixed messages about its views on automation on rigs by relying on DP systems but avoiding automating other tasks. ‘Why do we fear technology?’, he asked. ‘Ego? Experience?’
Dual activity dilemma
Logistics remains a core issue when it comes to deepwater drilling activity, Bastos said. ‘Logistics plays a big role in operating well costs,’ he said, adding that one way to reduce drilling costs is through the use of dual activity drilling. Carey noted some early problems with this effort, which was expected to slice 25% off drilling times. In the first couple of years Chevron used dual activity, he said, the company only realized time savings of about 10-15%. This was, he said, largely due to the turnaround time on the stack, which took longer than drilling operations took. The solution for this, he added, lay in having two stacks on the later generation of dual activity rigs.
‘It’s a phenomenal machine for batch drilling,’ Carey said, adding that was the good news. The bad news, he said, is the operator has to pay for dual activity every day, but it’s only used some days. The activity is personnel- and planning intensive and runs through consumables, requiring a fleet of boats to supply.
Increasing production rates and ultimate recovery while reducing development costs are the three chief needs operators have in deepwater scenarios, according to Henry Bergeron, Chevron’s focus area manager for well systems. ‘We’ve been going into ever deeper depths,’ which is putting pressure on the industry to create technologies to meet the demands of those water depths, he said.
Dual gradient drilling is one technology he views as a way to meet the drive to increase production and recovery while reducing costs. With this technology, he said, the biggest time savings comes with reduced tripping. Additional time savings are expected in drilling, rig repair, BOP and well testing and logging, among others. Dual gradient drilling will increase annular clearance to improve cementing for better well control, he explained.
A further benefit, Bergeron said, is that dual gradient drilling will make side tracks easier because there will be larger casing sizes to start from. The technology has not yet been deployed in the Gulf of Mexico; Chevron is still ‘studying it’, Bergeron added.
Petrobras well technology manager Antonio Lage said using underbalanced drilling (UBD) from a floater requires a concentric riser. New BOP seals that can resist at least 2000psi differential pressure are necessary to carry out UBD operations, he said, adding: ‘We need more resistant rubbers.’
Seismic-guided drilling is a solution Schlumberger is working on, said Graham Riley, the company’s drilling technology manager. Seismicguided drilling will provide more information about the rock the wellbore runs through. Combine that with huge computing ability, he said, and it will be possible to reprocess seismic for the area in ‘near real-time’ and use that information to guide the drill bit.
Deepwater E&P work requires tremendous HPHT technology. Riley noted 25,000psi requirements in some parts of the Gulf of Mexico. ‘We’re heading toward 40,000psi in the future,’ he said.
One refrain was repeated time and again at the conference: the need to hire, train and retain experienced personnel. ‘I wish the industry would stop feeding on itself,’ Chevron’s Carey said, noting that rig crew poaching activity simply increased the industry’s costs, lowered morale and created a constant recruitment merry-go-round. OE