Nomac deconstructs rig mobilizations to improve efficiency, looks to preventive maintenance for key equipment being pushed to their limits
By Linda Hsieh, managing editor
Operators continue to look for improvements in rig technology and equipment above and beyond the mobile, high-horsepower and mechanized rigs that contractors have today in order to help them to reduce spud-to-spud time and improve performance. Are there any specific areas of rig technology/equipment in which Nomac is working to push past the limits of today’s rigs?
Nomac, like many other contractors, has adopted a simple fleet upgrade strategy: newbuilds at the top, upgrades in the middle and divestiture at the bottom. We are currently in the midst of a 12-rig, all-AC newbuild program, with four already delivered and eight more to be delivered between January and June of 2013. We will continue upgrading our SCR rigs, investing approximately $25 million this year to improve these rigs to modern shale-suitable specifications.
In addition, we’re also disposing of several low-tier mechanical rigs.
Virtually all of today’s newer tier 1 rigs and recently upgraded tier 2 rigs address the three key areas needed to develop the resource plays: 1) higher-horsepower mud pumps, 2) higher-torque top drives and 3) fast moving capabilities. Additionally, land rigs will continue to be populated with ancillary mechanized equipment like iron roughnecks, hydraulic catwalks, BOP handling systems and pipe-handling machines.
For these tier 1 rigs and properly upgraded tier 2s, I don’t necessarily see another equipment step-change in the near future. Rather, the next cycle of innovation will either be in downhole tools, control systems or the way those two interact.
Do you see operators significantly preferring the tier 1 advanced-technology rigs over the older rigs?
The answer is yes and no. Many operators don’t care to discuss anything but an AC rig, which is fine. However, there’s a large segment of operators who will pick up, perhaps even prefer, an SCR rig that has been upgraded to tier-1 specifications. Some would argue that if a rig has a big top drive, big mud pumps, a walking system and fast-moving capabilities, its performance will depend primarily on crew strength, not whether it is an AC or SCR rig.
Reducing rig mobilization time has become increasingly important to operators as drilling times become shorter and shorter. How is Nomac working to ensure rig mobilizations are as quick and efficient as possible?
For years the industry has focused on the time between spud and release. Rigs got better, mud got better, bits have gotten a lot better, directional tools have gotten more reliable, and when you put all that together, we’re drilling Eagle Ford wells, as an example, in half the time we were two years ago. Yet, we have not imposed the same type of systematic review and analysis of the rig-move process.
So Nomac sat down and deconstructed the entire move process. We did a process map from the time you bump the plug until the time you’re ready to spud the next well. We utilized special time-lapse cameras during rig moves. We saw, for example, packages that were handled four or five different times.
Based on our observations, we significantly improved our pre-job planning. We now start at least two days before rig release with a pre-move planning meeting, ensuring all parties are aware of the plan and their respective roles. We stopped breaking tour on rig moves, continuing round-the-clock operations just like while drilling. And we’ve added extra crews to augment the move process. It’s really not rocket science, but by doing this, we’ve cut mobilization times in half for many of our rigs.
Rigs whose best move in the previous six months had been six days are now moving in three days, with no negative HSE impacts.
In earlier years when industry talked about automation, it used to be more about mechanization. Now, increasingly, discussions are focused on true drilling automation. From the operator’s perspective, there are big potential gains, especially in unconventional plays where large numbers of identical wells need to be drilled. Where do you stand on automation, and what role do you think drilling contractors should play in its evolution?
Because of Nomac’s unique relationship with Chesapeake, we are very focused on innovation throughout the well construction process, not just as it pertains to the rig itself. We are currently partnering with Chesapeake and National Oilwell Varco on a drilling automation project using one of our new PeakeRigs. Field testing is under way with the objective of demonstrating a fully integrated drilling automation system in the near future.
One challenge the industry faces in advancing automation is human resistance and a lack of trust that computers can safely carry out complex drilling operations. Do you see that type of resistance at Nomac, and how are you addressing that?
We’re not quite far enough into it yet, but I do expect some concern on the part of drillers, rig managers and even companymen. While I’m sensitive to the possibility that automation can be perceived as a threat, I think about the reaction of airline pilots when autopilot technology was first developed. I’m sure there were many of them who initially thought, “I have no desire to fly a plane that flies itself.” But ultimately, most realized the benefits of automation – that it was simply a tool to improve efficiency and safety and in no way minimized their role as captain of the ship.
I’m sure there will be bumps on the road to automation, but we’re going to get to the point where drillers will appreciate the advantages of automation, particularly the elimination of what is now repetitive tasking.
How is the Chesapeake real-time operating center being used, and what value do you see for Nomac or Chesapeake operations?
The Drilling Operations Center at the Chesapeake Oklahoma City facility was fully implemented in 2012. It houses 25 to 30 people, including drilling engineers, rig managers, directional drillers and geosteerers. There’s a great cross-functional team watching all the rigs that Chesapeake is running, close to 100 total, 63 of which are Nomac rigs.
Clearly, a primary objective of a real-time operating center is to observe best practices and implement them quickly across the fleet. This ongoing process is already delivering incremental performance improvement. However, one of the earliest wins we saw was a sharp reduction in nonproductive time and the associated cost savings.
As an example, over the course of a year, let’s say 30 have to be sidetracked for some reason – directional issues, stuck pipe, couldn’t get casing down, etc – and let’s also assume half of those were preventable. If additional monitoring and oversight eliminates those mistakes, then that represents substantial savings.
With operators continuing to push the limits of well designs in unconventional assets, with high angles and extremely long lateral sections, what stresses is that putting on rig equipment, and how are contractors dealing with that challenge?
Hookload isn’t as important as it used to be because a 16,000-ft well may only be 8,000-ft TVD. Early in my career, we used to see a fair amount of wear and tear on hoisting equipment. Now we hardly ever have trouble with it. It’s top drives that are really being pushed to the limit. Operators are requesting maximum torque and circulating pressures from these tools and, as a result, they’ve become our most common point of failure.
For many years, contractors did mostly failure maintenance rather than preventive maintenance, but we’ve come to the realization that that’s not enough anymore. Like most contractors, Nomac has a large technical support staff for all of our capital equipment and, in particular, our top drives. Our technicians go out to the rigs on a regular basis, inspecting the equipment and conducting preventive maintenance rather than just responding to breakdowns.
We’re also very diligent with inspections and recertifications. Besides the typical annual inspections, we remove every top drive from service and do a full shop recertification before five years of service. We’ve learned from experience that this equipment requires more oversight than, say, an engine or mud pump.
Do operators nowadays expect preemptive maintenance from their contractors?
I don’t think operators will tolerate breakdown maintenance anymore. At today’s high spread costs, running something until it breaks is disruptive to the process and prohibitively expensive.
I would not want to be a contractor these days without a demonstrable and quantifiable preventive maintenance program. Besides minimizing downtime events, we are in a much better position to show the operator that we’ve been responsible with our preventive maintenance when we do have an equipment failure.
As you mentioned, Nomac is a subsidiary of Chesapeake. Do you have any challenges that are different from other drilling contractors?
In terms of the way we operate the rigs, I assure you there’s little difference in Chesapeake’s expectations for a Nomac rig versus an outside contractor rig. We are held accountable for our performance just like anyone else. What is unique here is we are able to partner with Chesapeake in a much more integrated fashion. A good example is our personnel development program, where we provide rig managers to Chesapeake to become companymen or drilling foremen. This provides a unique career path for Nomac employees, but it also creates a unique challenge for Nomac.
Because of this program, our rig manager turnover is higher than normal, which means we have to develop rig managers faster than most other contractors. Tactically speaking, we have to turn drillers into rig mangers very quickly. Traditionally, it may take two to five years to progress from driller to rig manager. We can’t wait that long.
In April 2012 we created the Rig Crew Development Program (RCDP), which includes defined competency blocks that are required to move from floorman to motorman, motorman to derrickman, derrickman to driller, and driller to rig manager. High-potential candidates are identified at each level and are afforded extra training opportunities, as well as hands-on competency assessments by a dedicated team of trainers.
The program is designed to take someone with no rig experience and create a competent driller in as little as 24 months. A particularly sharp individual could then make the transition to rig manager in as little as one more year. That’s arguably half, maybe a third the time that it has traditionally taken.
You started this program in April 2012, and since then the industry has experienced a significant lull in drilling activity. Are you committed to continuing this program even during downturns?
Once you start a program like this, you can’t stop. By identifying high-potential candidates and placing them into the program, you create expectations. Fortunately, our relationship with Chesapeake creates opportunity even when activity is flat. Even though our rig count went down in 2012, we continued to create rig manager positions because Chesapeake continued to request rig managers for company men.
And note that every rig manager transfer yields four promotions: a driller moves up, a derrickman moves up, a motorman moves up, a floorman moves up, and it creates a job for a new floorman. This creates what we call the career opportunity pipeline.
Over the next few years, in what specific areas would you like to see rig and equipment designers focus their efforts as they try to improve on existing designs?
Number one is higher reliability. Referring again to the top drive issue, perhaps some of the design criteria are no longer valid considering what we’re asking from these tools. Today’s top drives are far more reliable than a few years back, but tomorrow’s need to be even better.
Second is more automation. I believe that a properly designed autodriller/control system can drill a well faster than a human acting alone. As with any new technology, there will be a bit of a hand-off, but I’m convinced that there’s an “autopilot” drilling rig in our future. Now, I’m not sure that we will end up with a two-man crew like some vendors are promising, but I do see the benefits of automation.
Third is lower cost. We pay a little too much for some of this equipment – control systems, driller’s cabins, hydraulic catwalks, etc. We are likely entering a flat rig count environment in 2013, but, of course, operators will continue to expect new equipment and innovation. We must find ways to cut costs. Some of that will have to come from our equipment vendors.
Five or 10 years down the road, how do you think land rigs are going to be different from today’s rigs?
The retooling of the industry that’s been under way for the last 10 years will continue, meaning more tier 1s and less tier 3s. I don’t see significant differences between today’s tier 1s and how they’ll look in 10 years. However, the way we use them will evolve.
Since the onset of the shale revolution, the industry has been primarily conducting location-to-location drilling for delineation or held-by-production purposes – first in the dry plays, and then after natural gas prices weakened, in the wet plays.
But now we’re finally beginning the transition into manufacturing mode. There are huge economies associated with drilling multiple wells on a single pad, and I’m optimistic we’ll spend much more time adding value for our customers by staying in one place rather than spending up to a third of our time moving.
If so, this will create a whole different thought process. If you’re starting a 12-well pad, do you drill each well to TD sequentially or batch set intervals? Could the resulting efficiencies materially change the way we call out third-party services? The way we allocate other resources? We will have to revisit all our processes.
Industry continues to put a strong focus on improving safety, with a heavier emphasis on process safety nowadays while not losing sight of personal safety. What more can contractors do on this front to enhance performance?
As an industry, we’ve made remarkable progress on personal safety, and while there will always be room for improvement, we should heighten our focus on asset integrity.
Presently, there is a great deal of variability among contractors with respect to inspection and recertification intervals for critical equipment. I see an obligation on the part of both contractors and operators to improve in this regard. Yes, the costs of increased inspections/recertifications are high, but I’d suggest the costs of not doing so – in terms of personnel risk, industry reputation and regulatory oversight – are even greater.
Does IADC have a role herein? Perhaps. IADC has an industry-recognized process for assuring well control competency with WellCAP, and while I don’t think IADC should get into the equipment certification business, maybe IADC should step in with appropriate equipment standards inclusive of minimum inspection/recertification intervals.
PeakeRig is a trademark of Chesapeake.