Operators call on contractors to improve maintenance, vendors to simplify designs
By Linda Hsieh, managing editor
NPT, the familiar acronym for nonproductive time, is a three-letter word, but it might as well be a four-letter word to drilling contractors and operators, considering the negative connotations that come with it.
Perhaps the negativity is well deserved. NPT brings to mind money wasted, time wasted, failures, budget overruns, unreliability, breakdowns, inefficiencies, plans gone awry, and many more of the unpleasant elements of a drilling operation. But perhaps NPT is not as bad as it seems. For David Payne, Chevron VP of drilling and completions, NPT is not a performance metric of what has gone wrong but a way to identify things that can be better.
Morris Keene, a drilling manager with Occidental Petroleum (Oxy), believes that the industry should not keep the definition of NPT so narrowly focused. To him, anything that happens outside the original well plan is NPT and should be counted as such. Only then will operators and drilling contractors really know where precious rig time is going, he said.
Drilling Contractor recently spoke with Chevron and Oxy to gauge their thoughts on rig-related NPT, including top causes and potential solutions. Offshore deepwater, BOPs and top drives were cited as the most problematic, while power generation systems and fluids equipment emerged as trouble spots on land drilling rigs.
DC also spoke with Athens Group on results of an industrywide survey conducted in 2009 on nonproductive time specifically related to control systems software and hardware integration (see sidebar on Page 20). Survey results optimistically showed that parts of the drilling industry have been able to reduce this particular segment of NPT compared with responses from 2008.
IN THE CRITICAL PATH
For Chevron’s deepwater operations, efforts to reduce rig nonproductive time have zeroed in on top drives and subsea BOP stacks – two heavy hitters that sit squarely in the rig’s critical path, Mr Payne said. To a lesser extent, pipe racker and other auxiliary equipment can also be NPT culprits.
In an internal study Chevron conducted on NPT last year, two deepwater data sets found BOPs and top drives to account for 51% to 75% of all equipment-related NPT, said Jeff Swain, Chevron rig systems specialist, who spent nearly a year conducting NPT analysis from land and offshore operations. One of those two deepwater data sets covered three years worth of data from one contractor, and the other data set covered four deepwater Chevron wells drilled by two rigs.
“It’s not to say these pieces of equipment are any less reliable than any other equipment on the rig,” Mr Payne said, “but other equipment are mostly outside the critical path or there’s redundancy. If a pump fails, we’ve got other pumps. If the top drive fails, we’ve got issues,” he said.
Especially with subsea blowout preventer stacks in deepwater, Mr Payne said, NPT has reached a point where it was more cost-effective to put a second, backup BOP on two of Chevron’s new deepwater rigs. “We spent $25 million to put a second stack on each of those rigs because it saves us money. We have another rig we’re negotiating for right now where we would like to put a second stack,” he said.
If having that second BOP means the rig can continue making hole when the first stack is down or being maintained, it’s not too hard to justify that kind of investment, Mr Payne said.
Anytime the BOP is down for repairs, or even if it’s simply going through planned maintenance, progress on the well stops. However, the million-dollar deepwater spread rate won’t stop; that keeps churning regardless of the BOP’s condition, he explained. “Out in deepwater, 10% to 15% mechanical downtime on a rig is not uncommon at all. With a $1.2 million spread rate a day, that figures out to $100,000 to $200,000 a day on average that’s gone because we can’t keep drilling,” he said.
Over the past several months, Chevron and its in-house BOP team have been undertaking a focused effort to cut down NPT associated with blowout preventers. “We have a dedicated team looking at resolving the NPT in that space right now. But at the end of the day, that equipment belongs to the drilling contractor. We can’t go in and do all the analysis that determines what needs to be done to keep it running. It’s up to the drilling contractor to address those issues,” Mr Payne said.
A COMPLICATED WORLD
In recent years, as drilling – both onshore and offshore – have increased in difficulty and complexity, rig equipment has become exponentially more complicated, oftentimes involving computer programming and a multitude of software to run. It’s a new aspect to rig equipment with which the industry simply isn’t as familiar.
“It’s like cars. It used to be that almost anyone could work on a car when it breaks down. Now you have to plug in a computer to work on it,” said Mr Keene, who now focuses on onshore business development projects, primarily in North America.
On his land drilling operations, it’s the power systems (generators and air compressor systems) and fluids equipment (mud pumps) that are the top causes of rig-related NPT. Top drives can also be problematic, but these problems could be resolved if people just understood the machine better, he believes.
“The design of the top drive has improved dramatically over the years. Now it’s a case of understanding how that piece of equipment should work, what causes failures and what doesn’t, so we don’t have user interface problems,” he said. “Sometimes the guy pushing the buttons isn’t pushing the right buttons.”
As for the commonly seen hydraulic issues with top drives, Mr Keene believes that is a weak link in design that can be fixed by using better materials for hydraulic systems. “It would cost a bit more initially (than using cheaper materials), but it would last a lot longer in the field,” he said.
MAINTAIN THE RIGHT WAY
Whether it is BOPs and top drives offshore or power and mud systems onshore, both Mr Keene and Mr Payne point to inadequate maintenance as the major culprit of equipment NPT.
“I don’t think people are being as proactive as they should be in implementing their planned maintenance systems. Everyone has one. It’s the degree to which it’s proactively implemented that minimizes problems,” Mr Keene said.
For Mr Payne, it’s the lack of policies and procedures when it comes to maintenance that he finds troubling in today’s age of ultra-complex equipment. “Historically, our industry has gotten by on running equipment that’s fairly simple. When I first started in this business, anyone who’s mechanically inclined could open up a drawworks or mud pump, look inside, figure out what was wrong and fix it,” he said.
Times aren’t so simple anymore. Today’s equipment is much more complicated, and yet the industry is doing maintenance and repairs in the way it’s always been done before. “When we tear into something incredibly complicated like a subsea BOP stack, it’s important to have a procedure on exactly what you’re supposed to do and do it the same way every time,” Mr Payne said.
“We’re seeing multiple failures on equipment, many times because something happened during maintenance. Maybe someone forgot an O-ring. In today’s world, if you’re doing maintenance on a complex BOP stack, the chance of one subsea engineer doing that maintenance exactly the same way as another subsea engineer is practically nil,” Mr Payne added. “It’s very likely that the same guy would do it differently himself from one time to the next.”
Mr Payne encourages drilling contractors to take a close look at maintenance issues and write rig-specific procedures for the myriad of complicated tasks being performed every day. He believes a procedure that is followed with discipline will take variability, and therefore inefficiencies, out of the system. “Chevron is influencing our drilling contractors to change their approach. The idea that you’re going to wing it just isn’t going to fly anymore,” he said.
Vendors have a role to play as well, perhaps by simplifying equipment maintenance or finding ways to take maintenance off the critical path.
They also have a responsibility when it comes to the proper integration of complex equipment on modern rigs, Mr Keene believes. When there’s a failure on a modern land rig controlled by PLC logic systems, the drilling contractor must get someone who’s an expert with that particular PLC system in order to make the repairs. That kind of expert is not always readily available, Mr Keene said. “Newer rigs with multiple PLC systems are good when they’re working, but when they don’t work, it’s more difficult to trace the fault and rectify it,” he said.
He would like to see equipment manufacturers get away from proprietary signatures on the PLC systems to make maintenance and repairs easier. “You should be able to get to a generic system where people who understand PLC logic can work on it, rather than need someone who’s an absolute expert with that particular vendor’s software,” he said.
And it’s not that operators don’t appreciate the state-of-the-art functions and capabilities of today’s drilling equipment. Mr Keene commented earlier on the dramatic improvements in top drive designs over the years, and Mr Payne noted the same advances for BOPs: They’re designed to go into much deeper waters and operate faster, and modern MUX systems are significantly better than the straight hydraulic systems of the past.
“Don’t misunderstand me. The advances in BOPs are very good,” Mr Payne said. But an increase in any machine’s complexity is inherently going to make it more prone to failure. “I personally believe the issue is not necessarily in the design. It’s in the people factor and how we’re doing the maintenance. Like I said earlier, we’re doing it the same way we did when it was simple,” he said. “When you have to pull a BOP stack because somebody missed two O-rings, that’s $2 million. That’s bad news.”
WHAT IS NPT?
In 2008, Athens Group carried out its first industrywide survey of operators and drilling contractors on rig NPT. Although the survey focused specifically on drilling control systems-related nonproductive time, it nevertheless underlined a weakness in NPT as a useful metric, especially one to be used for benchmarking purposes.
“We asked people how they calculated NPT, and it was all over the board. Different people include different components and exclude different components. There was a lot of discrepancy,” said Christine Lowry, chief marketing officer for Athens.
So what does that lack of standard definition mean?
For Mr Keene, it means that companies are not capturing all the NPT that is really happening. “We’re very good at capturing what I call hard NPT, where it’s related to a specific piece of equipment or breakdown. But the not-so-easily-identified NPT is not readily recognized,” he said. “When they have to trip for a bit that didn’t perform as well as it should have, or we have to trip because hole conditions require something else to go in the hole, that’s NPT.”
Under his broader definition, anything that occurs outside of the well’s original plan should count as NPT. “Some companies like to keep it very narrowly focused, but if you’re going to improve your operations, you need to look at things with a much broader view to identify where you’re spending all your time,” he said.
Chevron also uses NPT as a means to identify trouble areas that need work. To do that, the company does something that might go against the grain of the industry approach.
“We try really hard to put more things into NPT,” Mr Payne said. “Because that flags the event. Now it’s in our NPT analysis, and we have people looking at that and trying to figure out how to make it go away.”
Mr Payne also doesn’t believe in using NPT as a performance metric, pointing to Chevron’s Thailand operations as an example of a highly efficient operation with a relatively high NPT percentage. “We use Rushmore external benchmarking data that shows there’s nobody anywhere in Southeast Asia that comes close to what we’re doing there, and they run about 15% NPT,” he said.
Rather than having a lower NPT percentage, Mr Payne explained, he would prefer to have a lower overall time per well, as they do in Thailand. So they put as much as they can into the category of NPT so they can focus on making the overall operations better.
“If I have a 100-day well and 20% NPT, and I attack only the NPT, I only have a chance of reducing 20% of the time on the well. I’m looking for bigger chunks to take off,” Mr Payne said.
He added: “To set a target for NPT and say, I want an NPT of 10%, that drives the wrong behavior in my business because I want people to report NPT. To me, NPT is not a performance number.”
WHAT CAN BE DONE?
Looking at ways to reduce NPT, one of the more obvious solutions is to conduct root cause analysis. “That’s definitely one of the things we need to do to get to the root causes, not just get to a symptomatic problem. That would alleviate a lot of problems,” Mr Keene said.
Problem is, root cause analysis is not something this industry does diligently. Often, companies want to get back to drilling the well, so they just fix the initial symptomatic problem and move on. An internal study conducted by Chevron’s Mr Swain of one drilling contractor’s NPT statistics over a two-year period found that up to 94% of all NPT incidents did not have a root cause analysis performed because they didn’t meet the 12-hour minimum downtime requirement.
Even when root cause analysis is done, it may not be thorough enough to get down to the real problem. “Humans are naturally a little bit lazy. Sometimes they stop at the first thing they think caused a problem, rather than really digging down to the root cause. It takes a little more work to get there,” Mr Keene said.
For Oxy, the company not only urges its drilling contractors to conduct more thorough root cause analysis on NPT, but “we’re typically right in there with them trying to figure it out because if we can help them figure it out, we know it’s not going to happen again,” Mr Keene said.
Operators know they can’t get to true root causes without their drilling contractors, and it’s not a matter of pointing to mistakes and ordering contractors to fix them. Mr Payne stresses that partnership between the two segments is critical.
“We need to have conversations where I can tell you the good, the bad, the ugly about my business, and you can tell me the good, the bad, the ugly about yours. How will we work together to allow us to be more efficient?”
Mr Payne says that Chevron has started this process with one of its drilling contractors, primarily around BOP stacks. “It’s been very effective in the small space where we’ve been able to get it done. It’s a lot of work,” he said.
The process started in response to a high incident of BOP downtime on a particular rig. Through partnership and a focus on policies and procedures, that rig has been able to turn its NPT performance completely around, and “they’re running spectacularly well,” Mr Payne said. “It’s hard work to get there. To expand this through our whole fleet will take time and a lot of focused effort.”
Aside from partnership, Mr Payne also went on to suggest a couple of unconventional ways to address NPT.
For one, just as Chevron recently put backup subsea BOP stacks on two deepwater rigs, perhaps putting a backup top drive on a rig could be a future technology development. With BOPs, the first stack gets pulled and pushed over on the rails, and the second stack goes down. Maintenance and repairs can then be made on the first BOP while the rig continues drilling. Could the same concept work with top drives?
“(Top drives are) expensive, but if we have to shut down a million-dollar a day operation because the top drive’s broken, it doesn’t take very long to pay for another top drive,” Mr Payne said.
This wouldn’t be an off-the-shelf solution and wouldn’t work for every rig, of course. There must be enough room on the rig to store a second top drive, and it would have to be rigged up in a way that it could be moved into the derrick efficiently. Today’s derrick designs clearly won’t work.
When asked if he would be willing to contract a rig with a second top drive but at a premium dayrate, Mr Payne replied: “We paid for a second BOP on two rigs. That should answer your question… But the trade-off is, if both top drives don’t work, we want zero dayrate.”
And this brings us to Mr Payne’s second unconventional idea, the “No Paid Downtime” contract. “If I’m not able to progress my well forward because there’s something broken on the rig, it’s downtime and I’m on zero dayrate,” he described.
Certainly, he acknowledges that this is never a popular idea with drilling contractors, yet it’s one that he supports and one that he says he will continue to bring up with his contractors.
“I want the contractor to have skin in the game to keep that rig running all the time. If he needs to raise his dayrate because he needs to do more maintenance, I’m fine with that.”
Rig equipment NPT: Is software the hidden culprit?
By Linda Hsieh, managing editor
Nonproductive time (NPT) related to the integration of control systems software and hardware is a major pain point for many operators and drilling contractors, yet it’s a category of NPT that hasn’t been – and may still not be – properly recognized or addressed. “You see the pipes drop and hit somebody, and you blame the pipe handler. Not everybody realizes it was the software that gave the command at the wrong time,” said Christine Lowry, chief marketing officer for software consulting firm Athens Group.
“Or there was an alarm that went off to tell them that the equipment wasn’t doing the right thing, but they didn’t see it either because it was missing on the console or it was buried under a bunch of nuisance alarms because some other piece of equipment wasn’t calibrated correctly.”
For a high-specification drilling rig, there will be a multitude of different vendors supplying the equipment – all doing their own thing. Under the current builder furnished equipment (BFE) scenario, integration is the shipyard’s responsibility. No single vendor can or should have to take the responsibility for making sure that the system as a whole works properly when everything’s hooked up into the driller’s chair and interacting together, Ms Lowry said.
The fact that vendors can be protective of the proprietary technologies in their systems is another barrier to smooth integration.
The result is that software interfaces become the weakest link in a drilling control system, Ms Lowry said.
To create industry awareness of this issue, Athens Group conducted its first survey in 2008 of operators and drilling contractors on software-related NPT. Results were released in a white paper published in 2009, which Ms Lowry says generated strong interest. A second study was carried out in 2009, and results were released via two white papers this year.
Some encouraging results did come out of the first of the two 2010 papers, which focused on software/hardware integration, Ms Lowry said. In the first year’s survey, across the board everyone said they experienced 20% to 30% of drilling control systems NPT. “This year we found there was a dichotomy. Some people were experiencing less than 20%, and some were experiencing more than 30%. Obviously some people have addressed the problem in some way… We’re definitely seeing some improvements,” she said. The survey also found strong support for the standardization of equipment interfaces and standardizing NPT calculation methods as ways to reduce commissioning delays and NPT.
The second white paper this year focused on commissioning and human resources, and it was born out of client comments on how they’re struggling with a lack of qualified software experts everywhere – in shipyards and with vendors, drilling contractors and operators, Ms Lowry explained.
One interesting finding in this report was that 100% of those surveyed said they planned to take more control of the commissioning phase and quality of their newbuilds as a way to reduce NPT in 2010. “Shipyards are struggling. They’re great at building hulls and marine vessels, but they don’t have personnel who have a lot of experience building topsides,” Ms Lowry said. Moreover, software is often the piece that gets delivered at the last minute, yet it’s the piece that lets the shipyard test for integration. “You end up having to continue testing en route. That’s hugely expensive because you have to keep all the vendors onboard.”
In the survey, 71% of people said they preferred to rent space in the shipyard after the rig’s been delivered so they an finish integration testing and commissioning, over completing the commissioning in transit or at the first drilling location.
To reduce these integration problems and delays, Ms Lowry suggests that companies start with the end in mind. “You have to build the requirements into the contract from the very beginning so it’s clear to everybody in the supply chain what they need to deliver in order to meet expectations.”
If the contract doesn’t specify that the factory acceptance test (FAT) needs to exercise the software functionality, then the FAT ends up being simply a demo, she said. “Does the pipe handler move up or down? Sure. That’s what it does maybe 80% of the time, but on the other 20% where other things could be interrelated and create a problem, that needs to be tested too. You have to spell everything out and make sure everyone knows what ‘done’ is.”
Requirements from the design phase also must be tracked so they can be tested at FAT and commissioning. This will let the drilling contractor know at the end that comprehensive testing has been done. “If you do that part right, then all the other parts should fall in line,” Ms Lowry said. “The testing will be more comprehensive, you will know problems beforehand, and you can really speed up the project.”
IADC ART subcommittee efforts focus on collecting downtime statistics
The Reliability & Guidelines Subcommittee of the IADC Advanced Rig Technology (ART) Committee is pushing ahead with efforts to help the industry address the sticky issue of equipment downtime. The Top Drive Reliability Statistics Program began in late 2009 as a way to collect downtime data that can be used to help manufacturers pinpoint trouble areas for the top drive. The goal is to improve their design, maintenance and training and ultimately reduce nonproductive time (NPT), said Robert Urbanowski, manager, US operations engineering, Precision Drilling Oilfield Services Corp and vice chairman of the Reliability & Guidelines Subcommittee.
In 2009, the group decided to focus on the top drive first because it is such a critical-path component on a majority of rigs in operation today. Mr Urbanowski urges the industry to improve participation by filling out the IADC Advanced Rig Technology Committee’s Top Drive Reliability Statistics Program for as many unplanned downtime events as possible.
For its next project, the subcommittee had been looking at implementing a similar statistics program for PLC-based pipehandling systems, or MUX systems for subsea BOPs. A new idea raised at a recent subcommittee meeting may change those plans, however. “Rather than looking at every specific piece of equipment and developing separate statistics programs, maybe we should look at downtime in general. We would implement a statistics program for all unplanned equipment downtime, similar to the IADC Incident Statistics Program (ISP),” Mr Urbanowski said.
The ISP has tracked safety and accident information for the drilling industry since 1962. It helps to record data reflecting accident experience, which can be compared with other industries; to identify causes and trends of industry injuries; and to provide a means of recognizing rig crews for outstanding safety performance. A downtime statistics program has the potential to provide similar benefits for the industry.
Like the top drive program, all data collected would go straight to IADC and be kept confidential. Information will be presented in generic form only, never in association with specific companies, rigs or vendors. “Look at the ISP program – it has been going on for years and years. When IADC says they will keep the data confidential, they keep it confidential,” Mr Urbanowski said.
For companies that are concerned that they don’t have the time or resources to participate in such a program, maybe they can look to the ISP again to see how they’re collecting data on HSE incidents internally and submitting it to IADC. “Maybe companies can use that as a model for submitting downtime information to IADC,” he suggested.
Mr Urbanowski added that this concept of a downtime statistics program is still very early in the discussion stage within the subcommittee. It is still undetermined, but ideally this system could be implemented jointly with the IADC Maintenance Committee.