Drilling advances

Another installment of “you know you’re getting older when:”

You leaf through the Sports Illustrated swimsuit edition, all the while complaining that there’s not a bona fide sports story in the entire issue.

The main topic of conversation between you and your buddies is how many polyps the doctor found.

You remember when actual human beings operated a drilling rig.

OK, the last one is far from being the stuff of nostalgia, but there are those who firmly believe that in the not-too-distant future, we will be speaking of manually operated rigs in the past tense. For operators, automating the drilling process has long been the Holy Grail, particularly for the high-cost, high-risk offshore environment. Companies have responded in kind with Norway’s Robotic Drilling Systems, going so far in late 2012 as to ink an agreement with NASA, hoping to learn a thing or two from the U.S. space agency’s experience with the Curiosity Mars rover. After all, it reasoned, if folks in Houston can control an autonomous vehicle on another planet, why can’t some of the same technologies be incorporated into drilling a remote well?

While the myriad new-age innovations afoot show promise, Apache’s Jim Rogers and Jason Norman believe it’s time that everyone takes a deep breath and realizes that automating the drilling process will only make sense when placed in the right economic context.

“Let’s do something low-cost with the low-hanging fruit that’s available to us, where we can get a big return for a small investment,” says Rogers, the operator’s automation advisor. “Once we start going up that ROI (return-on-investment) curve, there’s a point where you’re going to stop, because it doesn’t make sense to keep spending that kind of money. The big question is, ‘where is that point?’ How far can you take automation, before you reach the point of diminishing returns?”

Both came to Apache from Shell, where they were among a small core group that investigated ways to reduce the drilling costs of mass-quantity onshore shale assets. There, they focused on transferring off-the-shelf products and techniques employed in the refining, chemical, auto manufacturing and other process industries to the drilling operation. “Those industries are highly automated, so we looked at the techniques and products to see which ones we can fit into the drilling process that make sense, and would reduce costs and deliver better quality, repeatability and safety,” said Rogers.

Rogers, who brings extensive experience from the downstream sector, and Norman, a senior drilling engineer, are following a similar strategy at Apache. “We’re focusing on land and the tight-oil, tight-gas, low-cost environments, with low-hanging fruit technologies (that) we can apply there and generate value. If you make money there, you can scale it up for offshore,” Rogers said.

They emphasize that a key learning point from refineries and similar process industries that must be incorporated into drilling, is integrating mechanization with process control. In other words, developing an automated tool is fine and dandy, but Rogers says the true value comes when it automatically knows what to do and exactly when to do it. “We’re looking for technologies that allow for measurements in real time, like we do now with standpipe pressure. Why can’t we measure mud properties like we measure pressure, rpm and temperature?”

And, that does not mean simply placing a lab instrument on a rig and calling it automation. “It has to fit seamlessly and be integrated into your rig,” said Norman, who focuses on automation methodologies for the drilling fluids cycle. “Automation does not work properly, if it’s a bolt-on.”

Changing the mindset. The predominant barrier to incorporating automation technologies from downstream into the upstream environment, they say, is the long-held culture that drilling is poles apart from a controlled operation, in that every well is different with a different set of problems. “I push back on that argument and say, wells are different, yes, but we’re not seeing any problems we haven’t seen before. The key is to identify those problems that we can respond to. We just have to capture the knowledge and best practices of our best drillers and best engineers; put those in algorithms and apply those algorithms, to take some of the load off the driller,” Rogers said. “In my view, drilling is like a batch process. It’s a repeatable step-by-step sequence of operations that lends itself very well to automation.”

Norman adds that incorporating instrumentation and process control that measure, in real-time circumstances at the rig site, including mud properties going in and out of the well, could put the kibosh on profit-draining downhole problems and inefficiencies. A truly optimized process would feed through the entire cycle, from mud mixing, to solids control efficiency to dilution economics.

“With a totally optimized process, you could have a flat line that says every well is going to cost you this much per foot. It will be spelled out that if you drill 50 wells, they’ll be exactly the same, because you’ve mitigated every problem. You don’t have stuck pipe, and you don’t have lost circulation, because you’ve engineered them out,” he said.

The underlying point: While technology may be available to put a Curiosity Mars-like vehicle in your neighborhood auto dealership, the bottom line literally must be grounded in economic reality.

 “To say that in the future, we’ll push a button and it will rig itself up, drill a hole, rig itself down and move on, I think that will cost more than it’s worth. Realistically, what you want is functionality and capabilities built into a rig and supervised by a human,” says Rogers.