I have been proud to be a member of DSATS, SPE’s Drilling Systems Automation Technical Section, for many years, currently serving as a board member. I think DSATS can be rightly proud of what it has achieved, and it is good to see drilling rig automation increasing as the industry realizes its benefits—solving problems including rigsite safety and consistency, and creating opportunities such as more efficient operations and, therefore, cheaper wells drilled more quickly.
We don’t talk so much about downhole automation of the drilling process, specifically directional drilling, even though it too is gradually progressing. What problems might it solve and what opportunities might it create? I am going to argue that the opportunity is huge, if only we look in the right place. The opportunity is not only to reduce the cost of drilling the well but also to increase its value.
A recent commentary on lifting costs from US basins published in JPT (August 2019) mentioned multiple ways of reducing drilling time and saving money (including driving down service company pricing, which may well not be a suitable solution) in order to reduce the break-even oil price. But it did not mention the other side of the equation—increasing the value of the well once drilled by maximizing ultimate recovery.
How can automation of directional drilling increase the value of the well? In my role with DSATS, and in collaboration with other SPE technical sections, I was fortunate to lead the subcommittee organizing a special session at the 2018 SPE Annual Technical Conference and Exhibition (ATCE). The theme of the session was “The Automation of Well Placement.” We heard from experts on directional drilling and surveying, and to create some tension in the ensuing panel session, we looked for an expert in production. Shauna Noonan, now SPE President, filled that role for us and gave the room valuable insight into some of the damage we can do if we ignore wellbore quality and tortuosity in our quest for speed. Many others have written about the cost of poor well quality: drilling cost in terms of torque and drag, and stuck pipe; potential issues with cementing and running completions; failures of production equipment, including rods and electrical submersible pumps; and production problems such as liquid holdup from vertical undulations in the lateral.
According to 2016 data from the US Energy Information Administration, the typical cost of a US onshore well is between $4.9 million and $8.3 million. Based on analysis of operator investor relations presentations, typical ultimate recovery from a Permian Basin well is between 500,000 and 750,000 bbl. If we increase the cost of the well slightly by drilling more carefully and not trying to drill as fast as possible, do we increase its value by a larger amount? Is it a good trade-off? I am convinced that we do, and that it is—but who knows? I do not believe that we have the numbers, or consensus, to decide.
What drilling technology do we have to increase the value of the well? Automation of downhole tools has been around for some time. First came measurement-while-drilling tools, with automated communications to surface, and then rotary steerable systems (RSS) with inner control loops to ensure accurate drilling toolface. At the same time, steerable motors were being controlled by manipulation of the rotary table, and then the topdrive, by experienced directional drillers to manage toolface.
Fast forward 25 years, and we have RSS tools automatically controlling the direction of the well, inclination, and azimuth, while there exist control systems to allow the rig to automatically control toolface of steerable motors. It looks as though automated control of steerable motors is destined to remain a generation behind that of RSS tools. For that reason, even if challenges such as rate of penetration when sliding, and “steps” caused by changes in hole size when transitioning from sliding to rotating using a motor could be overcome, my bet is on RSS to be a foundation for the future of downhole automation, at least for directional drilling.
The past few years have seen the introduction of directional drilling advisory systems telling the directional driller where to drill, with numerous options, in the same way your GPS tells you where to drive. So now we have systems that can control where they drill, and other systems that can tell them where to drill to acquire a positional target. And for years, we have had bidirectional telemetry allowing surface and downhole systems to communicate. These are the ingredients for an automated directional drilling system. The rest is easy, right?
Not quite. Our special session at ATCE also talked about geosteering. We don’t always know exactly where the reservoir is when we start to drill, so we have to include formation evaluation sensors to tell us where to steer. My vision is that one day we will be able to use those findings to control the direction of the well in real time, either through high-speed telemetry or by encoding the necessary inversions and navigation logic downhole.
It could be a decade away, but once we realize an integrated and automated geosteering system, our wells will be more productive and more valuable. They will be drilled smoothly and, therefore, more cost-effective and easy to complete and produce. They will be drilled without undesirable features such as undulations that might hold up production. They will be drilled in the right place to maximize reservoir contact and therefore recovery.
But someone must pay to develop the integrated technology, and generally people do not invest unless there is demonstrated value. Arguably, automation of the rig has been held back by contracting models that disincentivize development of technology that contributes to drilling efficiency. An analogous, possibly worse, situation could emerge when trying to automate what goes on downhole.
Earlier, I suggested that we have no good tools to help us understand the increase in value that accrues from good wellbore quality. Right now, we don’t even have agreement on how to measure the value. As John de Wardt, my DSATS colleague, pointed out recently in JPT (August 2017), “We have to have KPIs for well construction related to the longevity of the well” and not just “[default] to drilling fast.”
I imagine the early days of road transportation were uncomfortable and unpleasant; the driver’s role simply was to get you there. Now, the expectation is to get there in comfort. Currently, our drillers and directional drillers conspire to get the well drilled close to a target location as quickly as possible. Imagine a world where, using RSS tools integrated with automated geosteering, their objective was to get the well drilled as quickly and as smoothly as possible and to maximize value. It would require a new mindset, a new paradigm, a new set of KPIs. And a significant investment in technology. But given that technology, we would likely reduce the marginal cost of the well while we increased its value. Surely, that is worth shooting for, and surely as an industry we can find the KPIs that will help to drive us there.
| John Clegg, SPE, is a Weatherford Fellow, Drilling. For more than 33 years, Clegg has worked in multiple countries engaged in engineering, manufacturing, and operations with upstream technologies, particularly concentrating on drill bits, drilling motors, rotary steerable tools, measurement while drilling, logging while drilling, and managed-pressure drilling. He holds a master’s degree in engineering science from Oxford University. He is the author of 14 patents, has authored multiple technical papers, and sits on two SPE technical section boards: Drilling Systems Automation and Research and Development. |