Compact horizontal directional drilling (HDD) emerged in the s to install small utility lines with minimal disruptions. It has become the dominant method due to the global demand for high-speed data connectivity and streaming.
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To maintain its status, the industry has invested in advancements in drills. The latest generation of compact drills includes onboard technology for simplified operations and quiet performance in urban environments. Manufacturers offer a wide range of models to fit contractors’ preferences, and new HDD tooling options are available.
Here are five advancements in today’s compact directional drill market.
If you’re familiar with HDDs in the past decade, you may have heard about the benefits of HDD common controls in drill lines. These controls simplify operator training and help with productivity for HDD crews, regardless of the drill used.
The technology enabling common controls on HDDs is the controller area network communication system, or CAN bus system. This system connects the drill’s functionality to the joystick controls at the operator station through a network of wires. When the operator commands the drill, the CAN bus system relays that information to the machine’s moving parts, reducing the operator’s input.
CAN bus technology is a significant improvement over early HDD generations that relied on switches to control individual functions. It simplifies drill operations, improves machine serviceability, and allows for expansion.
Another advantage of CAN bus systems is the reduced machine wiring. Traditional machines with rocker switches require multiple wires connected to each switch to control different functions. This large number of wires can complicate troubleshooting wiring issues. The latest Vermeer HDD models have 30 percent fewer wires compared to those without a CAN bus system.
HDD common controls, powered by a CAN bus system, enhance drill functionality, and allow for telematics integration.
Modern compact drills are equipped with automated features that simplify the learning process for new operators and reduce manual input during regular drilling operations. For instance, auto drilling enables operators to execute repetitive hand control movements with less effort, even in challenging ground conditions.
Additionally, most compact drills offer semi-automated rod loading capabilities, eliminating the need for manual rod addition and removal. Carriages equipped with encoders can also automatically decelerate and halt at specified points for smooth rod handling.
Using a CAN bus system, drills can provide telematics data collection, which is crucial for proactive maintenance in the competitive compact drill market with thin project margins. Telematics gives contractors more control over planned maintenance intervals and, in some cases, allows them to gather additional productivity information from their drills.
Significant progress has been made in improving the mechanical aspects of compact drills to provide a quieter operating experience. Manufacturers have prioritized reducing noise levels due to the extensive use of drills in residential and commercial areas. Quieter drill operations help minimize the disruption caused by utility installation work and help minimize the number of complaints from individuals residing or working near the work site.
The capabilities and number of compact utility drills have increased in recent years while maintaining the same size. Previous generations of compact drills had a thrust/pullback range of 5,550 lb to 36,000 lb and spindle torque ranging from approximately 550 ft-lb to 5,000 ft-lb. Today’s compact drills, which are similar in size, offer a thrust/pullback range of 7,850 lb to 40,000 lb and spindle torque ranging from 900 ft-lb to 5,500 ft-lb.
These higher performance specifications have been achieved without increasing the machine’s footprint. Manufacturers have focused on optimizing the specifications of the machine to align with the capability of the drill rod.
The engine horsepower rating on today’s compact drills has remained relatively unchanged compared to their predecessors. This right-sizing strategy has helped control fuel consumption without sacrificing performance.
In addition to standard single-rod HDDs, manufacturers have also developed compact dual rod drills. These drills have an inner rod that provides torque to the drill bit and an outer rod that offers steering capability and rotation torque for reaming. This combination delivers powerful downhole-cutting action and the flexibility to select the appropriate tooling for different ground conditions.
Dual rod drills provide the ability to drill rock with a user experience similar to a single rod drill and do not require the additional support equipment like other methods. They also offer greater versatility when drilling in soil conditions that vary significantly along the bore path. In addition, they allow contractors to work in tight spaces without the need for a larger drill, thus maintaining a small jobsite footprint.
Over the years, the options for HDD tooling have significantly expanded as the industry gained experience working on different ground conditions. Choosing the appropriate tooling for specific ground conditions can substantially enhance a crew’s productivity and extend the lifespan of a drill bit.
Several non-torqued tooling connection systems have been introduced to the market in recent years. These systems enable crews to work more efficiently by eliminating the need for threaded connections and breakout tongs. Operators simply align the geometric features with each other and install the dowel pins or collar and bolt.
Many non-torqued tooling systems allow crews to skip the housing removal process after the pilot bore, resulting in a smaller exit pit in certain applications.
As the demand for compact directional drills continues to grow, manufacturers are dedicated to meeting the changing needs of contractors. They are actively exploring innovative ways to develop future HDD technology and ensure that upcoming generations of drills effectively address the challenges and requirements of tomorrow’s projects.
Directional drilling is a broad term used to describe any boring that doesn’t go in a straight line vertically down. In fact, even in a vertical well, it might be necessary to deviate to avoid a geological formation or a previous stuck pipe, then return to the original path. In this instance, the driller uses sidetracking techniques.
In conventional drilling for oil and gas, the drill bit, drillstring, pipe and casing all go down in a straight line. If a driller aims away from the 180-degrees down, that’s technically directional drilling. Nowadays, however, it’s more likely that there’ll be a series of one or more carefully planned directional changes along the wellbore.
Directional drilling techniques have been employed for almost 100 years now. Over the past few decades, technological improvements have meant that angles, turns and underground distances covered are amazing feats of engineering.
Techniques such as multilateral, horizontal and extended reach drilling (ERD) are enhanced oil recovery (EOR) methods that can increase the yield of a downhole dramatically. It’s possible for ERD specialists to drill for more than 10 kilometers/6.2 miles. Students of petroleum engineering often get shown illustrations and diagrams that look like tree roots. If we imagine the rig as the trunk of the tree, the directional possibilities of the roots are endless. Even the branches of the roots are comparable to multilateral drilling.
Multiple down holes can be drilled from the same rig, minimising surface disturbance and environmental impact. Also, these boreholes can extend up to a mile down, and for more than five miles at shallower angles. In an oilfield with dispersed deposits, a large radius can be tapped, maximising the expensive asset which is the rig. Rigs and crews have day rates that run into the hundreds of thousands of dollars, one rig working up to five or ten square miles is very cost-effective in comparison to having a dozen or more vertical rigs, which may or may not be tapping into the same accessible reservoir deposits.
Geologists and engineers use terms such as an ‘oil reservoir’ or a ‘hydrocarbon reservoir’ to describe underground pockets of resources. Scientific terms give a label to help everyone understand each other, but Mother Nature has different ideas about the way she organises things.
People who perform well plans such as seismic geologists, geoscientists, exploration engineers and CAD experts join together to give the best idea of where oil and gas deposits may lie. Their estimates are based on different types of surveys, and past experience. What they’re unlikely to do is pinpoint the exact place where they’d access the maximum amount of resources.
When we see reservoirs of water, we can imagine dropping a giant straw into the middle and sucking up the entire lake. The flat surface area of the water and the likelihood of human-made dams and walls might give us a false idea of the topography of an underground reservoir. The bottom of the lake would provide a better insight into the random geometry of the dispersed resource. For example, if your imaginary straw happened to touch a shallow gravel bar in the middle of the lake, you might only extract a small percentage of the water.
On top of this randomness related to upper, lower and outer dimensions, there are plenty of other possibilities:
In fact, these ‘irregular’ reservoirs are very common. Now that relatively fewer elephant reservoirs are being discovered, and technology improves, directional drilling becomes more critical each year.
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Another use for directional drilling is in the event of an uncontrolled, or ‘wild well’. If you imagine a well that has broken through the blowout preventer and is gushing, how can you cap it?
This depends on the amount of underground pressure. In some instances, a second control well is drilled so that it intercepts the same point where the original wellbore meets the reservoir. Once the new directional well is completed, it can be pumped with kill fluid.
If the well pressure isn’t too severe a relief well can help to release gas so that the original gusher reduces in intensity, allowing it to be controlled. Mud and water are pumped in from a different angle, to get the first well under control and back to proper working order.
It’s not possible to see hundreds of metres underground, in fact, the drillers and engineers rely entirely on technology to ‘see’ where they are going. A directional driller has a guide that has been created by the engineers and geologists. Every 10-150 metres, (with 30-40 being typical), survey data is sent back to make sure that the original ‘blue line’ well path is being followed.
Directional drilling software receives input from multiple measurements while drilling (MWD) sensors in the drill bit, and at any branches or junctions. (Other measurement tools include Electromagnetic MWD and Global Positioning Sensors (GPS)). In addition to MWD technology, mud loggers use logging while drilling (LWD) sensors and software. The drill bit has vibration sensors that can detect the type of formation being drilled at any point. Collars can be added along the length of the well, sending back information to the surface regarding torque, weight and bending.
From the surface, electromagnetic sensors can also track the progress of the drill bit. When all of the data from the drill bit, collars, motors and the surface equipment enter the control panel, a complete representation occurs.
As well as being able to know what is going on, even a mile along the drill bore, drilling engineers can make adjustments in real-time that ensure that everything is going to plan. This is especially relevant when unexpected things occur concerning geology or severe equipment stress.
If you were to imagine the mechanics of directional drilling without seeing the technology, you might wonder how the drill could suddenly change direction. Since the motor that turns the drill is at the surface, how can the drill string continue to rotate at 360 degrees while going around a corner?
We now have downhole drilling motors, that can drive the drill bit in a completely different direction to the usual 180-degree downhole starting point. Turbodrills and rotary steering drills are employed in directional situations where they’re best suited.
The rotational speed of the drill and the weight and stiffness of the drillstring can also be used to influence direction. One of the original methods was jetting, a high-pressure nozzle shot water or drilling fluid from one edge to the drill bit, creating a weaker side in the formation.
Another traditional method was to use a whipstock. A whipstock is a type of wedge that can redirect the drill. At the desired depth the drill is withdrawn to the surface, a whipstock gets put in place, then the drill goes back down and gets redirected by the whipstock. Next, the drill is brought to the surface again, the whipstock pulled out and then drilling resumes and the bore changes path.
Drill bit sensors can tell the driller about external weight, and rotary speed that can also be used to influence the trajectory. Mud motors can also be used to change direction. With a steerable drill pipe, there’s a bend near the bit. The drillstring stops turning, and then there is plenty of time to use chosen directional techniques to reposition the bit to the desired trajectory. When it starts spinning again, it’ll start going in the direction that it’s now pointing towards. (More about steerable mud motors in the next section).
Specialised drillbits are used to improve performance and reduce the chance of failure. Schlumberger supply directional PDC drill bits for both push- and point-the-bit rotary steerable systems. Horizontal Technology, Inc. provides ‘Varel High Energy Series bits’ designed for the unique, rigorous conditions of horizontal directional drilling.
Mud Motors. Downhole steerable mud motors get positioned near the drill bit, which has a bend in it. What happens is that at the correct depth the drillstring stops rotating, then drilling fluid is pumped through the mud motor so that the drill bit starts to turn just due to the force of the liquid. This mud pressure pushes the drill bit into a different angle, and also begins to bite into the formation at a different angle to the central well trajectory. Once the sensors verify that the drill bit is pointing in the right direction, the drillstring starts to turn again.
Rotary Steerable Systems (RSS). Directional drilling by using the mud motor means that often the drill pipe needs to be slid forward while the drill is motionless. A rotary steerable system can drill and steer at the same time. This means that previously inaccessible formations can be accessed.
Bottom Hole Assembly (BHA) configurations are often bent in shape so that they can make turns by using physical manipulations. The video further up the page clearly shows the bend in the drill pipe.
Multi-Shot cameras are fitted inside the drillstring. They’re set to take regular pictures on a time-lapse setting. Then these images are sent to the surface control.
Custom whipstocks that work with downhole motors don’t need removing in between drilling. These are a significant advance on the old fashioned ones previously mentioned. More time can be spent drilling, and less time removing the drill bit and conventional whipstock.
Networked or wired pipe. The Intelliserve system from National Oilwell Varco is a broadband networked drilling string system. It can transmit data from the sensors back to the surface.
These are most of the specialist directional equipment used. Plus there is the three-dimensional measuring equipment mentioned previously in this article (MWD, LWD, etc.)
Well integrity is perhaps the most crucial aspect of directional drilling. Drilling at deeper, or extended distances, and especially changing direction causes a number of additional engineering challenges and stresses on the equipment.
For example, a downhole drilling motor will always be far smaller and less powerful than one connected to a robust drilling rig above ground. It’s more likely to fail, or have insufficient torque or speed to get through challenging geological formations.
The drillstring itself will be less stressed when going in a straight line, every degree of turn add extra friction and unbalanced pressure. If drillstring integrity isn’t maintained, the drillstring can snap or get jammed. It could mean that a brand new set of equipment is needed, and a new well might need to be drilled again in a slightly different direction.
Maintaining hydraulic pressure, and wellbore cleaning is much more challenging with these types of wells. Modern directional drilling equipment is so advanced, it can cope with high pressure/high-temperature HP/HT conditions, a mile away, after the wellbore has changed direction.
Computer simulation programmes are used to simulate the well plan. 2D and more recently 3D modelling programmes give the geoscientists and engineers a visualisation of the planned path. This software is created based on previous knowledge, current seismic and magnetic data, supplemented with real-time data from the MWD instruments.
There are a few different types of directional drilling. Multilateral drilling is where a downhole bore has multiple lateral (90 degrees) offshoots. For example, a well might be metres in depth but have numerous lateral wells connected to it. Extended reach drilling (ERD) is categorised by ever longer wellbores drilled from the rig.
Perhaps the most interesting type is horizontal directional drilling because it was the first type, and perhaps the most controversial.
Land tenders offer the right to explore and extract resources from a particular square meterage of land. It’s possible to purchase a lease for an oil patch, then drill horizontally into neighbouring territory. Close to a national border, it’s been known for drillers to drill into another country.
This is different from straightforward situations, where two territories happen to tap into the same reservoir. The industry has guidelines and regulations. Simultaneous operations (SIMOPS) and combined operations (COMOPS) have strict procedures for situations where well interference can occur.
The oil industry is aware of the ability to horizontally tap deposits under other peoples leases, lawsuits related to this started way back in the s.
Of course, the majority of horizontal drilling is done for good reason, not to cross borders of ownership or sovereignty. Sometimes horizontal directional drilling is the only possible way to tap a reservoir, such as the case of dilling under a town or nature reserve. Other times it’s a cost-saving exercise, to drill under a salt dome or mountain. Lastly, drilling horizontally can be the best way of maximising extraction by reaching more sections of a reservoir.
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