SPE/IADC 139922The Next Generation Top Drive and Lessons Learned from the TDX-1250 Jay Pickett, Justin Saski, Robert Luher, NOV; Andre Cantrell, Cherokee Offshore; Brett Wallihan, NOV Copyright 2011, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 1–3 March 2011. This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright. Abstract With all the emphasis today on the economics of improving well costs, the industry is faced with finding a way to provide marketable technology to drill more challenging wells even cheaper. The top drive stands out as one of a few key pieces of equipment in the critical path. As a result Top Drive failures have accounted for a large portion of down time, thereby increasing costs to drill a well, and the top drive is in essence “the drill” needed to reach reservoirs that are farther and deeper than once thought possible. ExxonMobil needed to upgrade its drilling platform in the Yastreb field in order to reach reservoirs with very long, extended reach. Drilling these wells necessitated a need for more torque and speed. Typically these parameters are supplemented with downhole motors. However, in extended reach wells, failure 5,000 – 6,000 feet downhole costs up to a full day to retrieve the equipment and another full day to re-deploy the tool. With performance improvements to today’s modern top drive, we have been able to increase torque and speed on the top drive and move that associated risk to the rig floor. Today’s ultra-deepwater drilling necessitates durable, maintenance friendly top drives to off-set the high day rate and spread costs associated with these wells. For that, top drives in this environment have taken a step-change to increase durability with larger main thrust bearings, larger main shaft connections, heavy-duty link tilt function, etc. In addition to this increased focus on durability, these machines also need to be repaired quickly to get them running again. This has created a new generation focused on maintainability, and modularity. Introduction The drilling industry is constantly evolving and today we are seeing a step change in the types of wells we are asked to drill and their environments. Equipment manufacturers proactively meet the challenges of changes in the drilling environment through advancements in personnel, practices, and technology. The top drive is no stranger to technical evolution and with the higher performance demands on our tools today, the top drive sits at the forefront of pushing the drilling envelope. The next cycle of drilling programs lead many to believe that we are going to push our current tools to the limit. Weight of drill pipe, depths, footage drilled, and power required to drill a well have all increased in this century. To meet this upcoming demand, equipment manufacturers redesigned the next generation top drive to handle rotating loads in excess of 1,000 tons while increasing reliability, redundancy, modularity, and ample power in reserve. In order to understand the dawning future, it is important to look to the past. In the last decade, top drives played a vital role in drilling long extended reach wells and exploiting these reserves. The top drive was initially brought to market in order to speed up the drilling process and allow drillers to drill ahead with a full stand of pipe. In the past, using a rotary table, you could only drill ahead with a single joint of pipe. The top drive blew past that requirement and now you could drill with up to 120 foot stands of pipe. Top drives added value in tripping operations because of their internal blow out preventer (IBOP) and back up clamp (or torque wrench), they could stab into the pipe at any height interval – relative to the drill floor - and quicken any well control situation. While we have seen incremental improvements in our top drives over the last decade, the next generation top drive is more than just a step change, it is a paradigm shift. Improvements in drilling motors, operator-friendly hydraulics, control parameters, and others, are common, but still fail to address some of the challenges that lie ahead. This next generation has taken the entire top drive design back to the drawing board. The heart of the machine – its load path components and 2 SPE/IADC 139922 transmission all had to be examined for potential improvements to meet the demand for deeper, longer, and more challenging wells. The industry was requiring our machines to handle heavier loads that were not considered when these machines were designed years ago. Certainly, most top drives in service today are very powerful machines, and perform satisfactorily, but the drilling community is wants the capability to drill faster, deeper, and longer by increasing speed and reliability in smaller, more operator-friendly packages. Long extended reach drilling (ERD) wells require machines that can help exploit their reserves. The power needed to push a horizontal string some 45,000 to 55,000 feet and further in a horizontal deviation is immense. But in these long horizontal sections, rocking and rotating the pipe to overcome the coefficient of friction requires a lot of energy to be applied to the top of the drill string. It is rare to have ‘too much’ power. Certainly there are other factors necessary to reach these distances that were once unheard of, but the enhancements in power of these next generation top drives are no longer the limiting factor. With the proliferation of these machines in directional drilling applications, the next generation machines are designed to understand and enhance long extended reach drilling. Finally, reliability on these machines needed to improve. Because the top drive is centered over well center, a top drive failure often creates a rig down situation. With these machines often being applied in the most challenging wells with ever increasing costs associated to drill these wells, a top drive failure can have severe economic impact. As a result, one way to improve the economics is to reduce unplanned downtime. For that, equipment manufacturers have analyzed how to supply redundant components that can keep the system drilling until you reach a planned maintenance point. This increased reliability coupled with this redundancy has reduced unplanned downtime and positively affected the economics of these high dollar wells. The paper will discuss where form and function were desired then supplied and the lessons learned that aid in the development of the machines of tomorrow. Drilling Deeper in the New Millennium In the last decade and to start this new millennium, we have seen a significant increase in the drilling depths of our offshore programs. Fig. 1-1 shows the progressive increase in drilling depth in the US Gulf of Mexico over the last 10 years. In that geography we have seen the drilling depth increase from an average depth of 10,008 to 11,737 feet (Fig. 1-1). While this average total depth still does not necessitate a change in machines, we clearly see the 12% increase over the last decade to illustrate the need for longer drilling strings, casing loads, and landing strings. Certainly for shallow water drilling, legacy machines will remain the norm and perform without issue. However if similar increases continue to occur, we can expect that these machines will be put under more load even if all other variables remain constant. And as a window into our future we are seeing a dramatic increase in the number of leases in deeper water. Although the industry is aware of the outlier success stories heard round the world, we will remain in the realms of overall drilling activity averages at this time. It is noted that in the past five years world record well depths have been reached in excess of 30,000 feet by notable operators and drilling contractors. All of these records were made possible by the use of a top drive in addition to the other critical factors of successful ERD wells. In comparing the number of wells spudded worldwide (Fig. 1-2) there is a correlation between growth in larger reaching wells versus overall wells for that same year indicating the demand for manufacturers to design and manufacture drilling machines that are capable to take us to the next frontier. While deepwater applications still represent a smaller portion of current global drilling, the data suggests this is the rapidly approaching future and the driver for equipment manufacturers to bring this technology to the market today. When these reservoirs become more common place, use of today’s tools will create a history and lessons learned to share with the industry in how to exploit these obtainable reserves. In the historical drilling plan, these loads can certainly be sufficient for these legacy tools. For those programs, we have the next generation top drive. These systems are specifically designed to handle these demands. Historically, top drive systems have been regarded primarily on performance. While this is certainly imperative, load capacities have become an added focus in the industry. Traditionally, top drives are designed to handle most of their weight at the elevators. In most machines today, the static load path from the drill pipe comes to the elevators, to the elevator links, linkhanger, landing grooves on the bottom of the main shaft, main thrust bearing, motor housing, and then out the top drive through the bails. This is where we typically derive our tonnage rating. However, if you intend to rotate or drill with this load, the load path changes, as does the dynamic rating of some of the load path components - primarily the main thrust bearing and thread connections on the main shaft. Whereas before the load going through the main shaft was not placed into the grooves, a ‘screwed in’ connection on the drill string would represent the weakest portion and where separation is likely to occur. This new load path is much different and simply goes from the drill pipe, to the saver subs, IBOPs, main shaft, main thrust bearing, motor housing, and again out the top drive through the bails. Simply put, this newer application for rotating heavier loads has created a new requirement in top drive design. Using the top drive to place these heavy loads through the main shaft was once thought to never occur and is now becoming more frequent. To solve this we redesigned the load path components. It is with this need in mind that the main shaft connection SPE/IADC 139922 3 on the TDX-1250 has an impressive NC84 connection. Additionally, when you view the connection plots in Fig. 1-3 connection strength is calculated at 1,254 tons. “P1” as noted on the graph of 2,821 tons represents its maximum strength, and if you apply a 2.25 safety factor strength is generated. While it is still unlikely that connections will be made to that torque in today’s drilling world, the design philosophy was to over engineer the tool so much that it would likely never see a need beyond its capacity in that tool’s service life. The next focus for these machines was enhancing the main thrust bearings. The API 8C main thrust bearing calculation uses a simple formula derived from bearing manufacturers C90 number, there are other factors that can impact bearing life; gearbox design, deflection, lubrication factor, misalignment, contamination, etc. all of which factor into the L10 life of the bearing. When discussing bearings, it is also important to note that the L10 only states that at that time 10% of bearings have statistically failed, 90% will not. Since the main thrust bearing is such a critical component and requires days of downtime to inspect, replace, or repair as a measuring factor bearing life still remains paramount. What we are seeing is as these loads exponentially increase, the wear on the bearing accelerates. To further illustrate this we have two charts taken from a drilling profile given to the manufacturer (Fig. 1-4). In the historical drilling profile the weights do not dictate the need for a larger bearing. However, when you compare that to the more modern drilling profile, the need becomes more apparent. The TDX was designed with an improved main thrust bearing to handle these loads. Super clean, carburizing grade, alloy geometry control, contact surface finish enhancement, and analysis tools for thrust tapered roller bearing design can be used to facilitate load rating improvement. Deepwater wells with depths less than 25,000 feet can often be drilled with a full string of 5-inch or 5 7/8-inch drill pipe. However, smaller pipes simply will not reach the deeper depths. Heavier walled 6 5/8-inch pipe has become the norm for deepwater drilling at these depths, which adds significant torque and tensile loads to the machine. Simply changing pipe to a larger diameter like a 6 5/8-inch pipe may seem innocuous to some, especially the production audience, “We do it all the time”, but for the machine, it can double the weight of that section. Below are some estimates of approximate lb/ft of pipe ranges. Type lb/ft 5" 25 5‐7/8" 28 6‐5/8" (.913" wall thickness) 43 6‐5/8" (.625" wall thickness) 60 Estimated weights of Drill Pipe Reliability, Redundancy, and Downtime A factor most often associated with top drives is the economic impact associated during top drive failure. The top drive is in the critical path and it holds a place in the small minority of drilling equipment that can singularly halt the drilling process. However, the fact that it is at (or near) the top of the list of critical assets that effect downtime, even the 96% to 99% uptime is not acceptable to most customers. Considering the harsh environment it performs in and with a 10 year, sometimes 20 year service life, that uptime is quite remarkable but not good enough. It is important to note that the economics of drilling cannot bear the cost impact of top drive downtime. During this development an extraordinary effort was placed on creating systems that are first reliable, durable, and then redundant. As we mentioned in the preceding paragraphs, much of the design was taken back to the proverbial drawing board to over engineer components that can cause failure. Once maximum reliability was ensured, the engineering did not stop. An incredibly robust failure analysis took place with the focus to create redundancy on those critical components that can cause downtime. In viewing a variety of top drive faults that create downtime (Fig. 2-1), the TDX development focused on providing a backup for those components. (Please note, the failures captured in this graph do not account for downtime with controls or drives.) For the purposes of this paper, top drive downtime will be limited to the drilling unit, dolly, IBOPs, onboard electronics (J-boxes, connectors, etc.) and the other components. It is also important to note that not all the incidences reported resulted in rig-down situations or had financial consequences. They are recorded incidents that required maintenance. As seen in the chart, the pipe handler on the top drive represents the largest portion of top drive downtime. While this is not always intuitively obvious, a closer inspection reveals the conclusion. The top drive will always be in the critical path even if is not always drilling. In fact, most of the time, it is not drilling. Sources vary, but for the purposes of this paper, we will state the top drive is only drilling approximately one third of the time. The rest of the time, the tool may be in use, but it may be operating in a tripping-in or tripping-out function. As it stands directly over well center, it is also used to land the BOP, run riser, and is a pathway to the bottom. 4 SPE/IADC 139922 One of the issues we started to encounter was another change in the way top drives were being used. In an effort to become more efficient, drillers were continually placing longer heavier links on the top drive traditionally used to run casing. Now, it is not uncommon to leave these longer links on the top drive during drilling operations. This weight accompanied with heavier BX elevators started to create too much load on the pipe handler design. To combat these downtime issues, the TDX was designed with an incredibly heavy duty link tilt. Its design no longer uses a shot pin assembly to lock in the pipe handler when making or breaking a connection. Further, it has extremely large actuator pistons to allow for 96-inch extension of up to 1,600 lbs of load. Equipment manufacturers also noticed large amounts of downtime for IBOPs. As a well control device, IBOP failure results in rig downtime. While even the most robust components can and will statistically fail, we can keep systems from failing by creating redundancy in those components. The dual ball IBOP is an example. The lesson we took from previous designs was to include a backup ball valve IBOP below the remote IBOP. This one acts purely in reserve and independent from the lower IBOP. If the upper valve in the upper IBOP fails pressure test, what used to takes hours to replace the upper IBOP, can now be switched to the lower ball valve in seconds and allow one to continue to drill. Then when you reach that planned maintenance point, you can replace the upper IBOP and not force unplanned stoppages in the drilling process. This same principle holds true with regard to the motors. As previously stated, not all recorded failures involved downtime as various forms of maintenance also qualify as “downtime”. Motor failure is catastrophic and the new evolution and next generation tools are designed with redundant motors that can operate independent of each other if motor failure occurs. With the two 1,340 hp motors, the top drive can operate uninterrupted in most drilling operations with only one motor. As we mentioned with the IBOPs, you can operate the machine until that planned maintenance point which was a design goal for our newer machines. Lastly, the quick change modular motor design has greatly simplified the change out. Historically changing out a motor could take up to a day but now the task can be completed in as quickly as four hours. Distance and Power These features have provided confidence that the tool can drill some of the most extended reach applications. As the drilling continues to evolve, longer horizontal sections are also becoming more common place. Just as wells are getting increasingly deep, further deviated wells are transitioning from a niche application to the standard. While this application has some similarities with regard to stretching the drilling limit, the application on the top drive is entirely different. In these cases, drilling loads are not a factor. In long ERD wells, you are more likely to see loads reduced the further the deviation gets. In these cases, it is about power and the limiting factor in the drilling process. It is not new for top drives typically classified in offshore applications to find work on land because of their better performance curves (Fig. 3-1). Interestingly enough, it was this land-based application that first put the TDX in use in Exxon Mobil’s 262 rig in December 2008. Exxon Mobil chose this particular tool not because it’s dynamic rating and increased load path components. They needed a tool with the durability and performance to drill a well with a horizontal deviation of up to seven miles. These extended reach applications validated the need for maximum performance tool. In drilling these wells availability of additional power is no longer a luxury but a necessity. With a true vertical depth beyond 7,500 feet, the weight of the drill pipe also plays into effect. As noted earlier, we still see an increased need for larger drill pipe. The challenge in this application is the larger heavier pipe does not put a physical load on the top drive as we described in offshore use, but when trying to move the pipe horizontally, we rock the pipe to overcome the coefficient of friction to move it easier. Trying to rotate this pipe puts a huge load on the drilling motor. For this use, the high horsepower motors and massive amounts of power became a necessity and will be a staple on ERD rigs of the future. For long reach applications, historically the top drive was the limiting factor. While they could use downhole hydraulic motors to generate torque or speed at the bit, they still needed a machine to rotate the pipe at the top of the drill stem. With smaller horsepower machines, the top drives were run at their maximum performance and have a dramatically shortened life. With the next generation machines, there is power in reserve. The TDX can provide from 90,000 up to 105,000 ft/lbs of drilling torque, depending on its configuration. While again this is meant to suggest that all wells, even in the future, will need this kind of performance it does provide ample reserve power and allow for huge safety factors when drilling. The use and its successes have generated lessons learned for our industry and wells of future. Still Looking Ahead While much can still be said about the advances and engineering in place in the TDX to meet the change in the drilling conditions, there is still an unrealized future. Top drives, as they function in regard to downtime, are still reactive to their performance. Our industry has just begun to commercialize technology that allows our machines to detect early signs of failure so we can change, adjust, or warn the operator. There are a great number of parallels between the drilling and automotive industries. Diagnostic systems on rigs are becoming more predictive andcontrol systems can have Check Top- Drive alarms like we see in the automotive industry. Maintenance systems are being developed that can reduce unplanned SPE/IADC 139922 5 downtime even more once they are deployed on our machines. The forefathers of this technology in other industries have provided us a window into that possibility. While we must be cautious to ensure these adaptations are applied correctly, the possibility exists. Equipment manufacturers are now adopting technologies from other industries and certifying them for use in our industry. Additionally, we must ensure any kind of added monitoring features are intrinsic. Finally, we must also be mindful of false alarms or nuisance alarms. Any device that routinely y displays incorrect faults will be ignored over time which could result in drillers disregarding a true fault. So the robustness of the sensors to monitor top drive conditions becomes a stringent criterion to ensure success. The end game for this next horizon is not only a system that tells you early signs of failure, but can help predict failure. Once we have historical data, we can use data loggers to trend failure analysis and to key-in the most critical factors to monitor. At this condition monitoring is greatly reduced. The number of tags needed to monitor reduces and indicators and alarms have more value. Conclusion The exploration, development, and production of hydrocarbons continues to evolve. What we are seeing in this new millennium is a paradigm shift toward deeper water and further deviated wells. The economics of these new platforms to develop these reserves has grown exponentially. Non- productive time is becoming ever more present. To address these new shifts, the next generation top drive is designed to bring a new technology to market to handle the very different way we have begun to drill. What was once thought as niche and perhaps too challenging or expensive to drill is rapidly moving into the main stream. The learning’s from TDX represents a way to fill that need in its own respect and the smaller lighter versions of the future. A more economical way to enhance the drilling program is to simply change the top drive without having to design a new vessel or derrick. At that, designing a tool that is economical and has minimal impact on the existing platforms is imperative. In the first two installations of the TDX-1250, both were retrofitted into existing systems. This allowed for a major performance step change in the drilling process while reducing the economic impact that a new rig would result in. We are also seeing an increased push for machines that can be installed and tooled up in a minimal amount of time and that interface well with existing systems. All of these factors and more are necessary when building the machines that will drill the wells of tomorrow. 6 SPE/IADC 139922 SPE/IADC 139922 7 8 SPE/IADC 139922