Today's substantially lower oil prices and the respective decrease in active rig counts have inadvertently resulted in the industry collectively rethinking, improving and optimizing operations across the board. This is particularly significant for companies in unconventional drilling. High-cost shale plays often take the biggest hits when oil prices fall. To survive in this challenging market, companies must achieve increased daily drilling footage, decreased run numbers and tool longevity. For operators, this means doing everything possible to optimize drilling productivity from spud to total depth while staying within given budget parameters. In response, equipment manufacturers must ensure that their downhole products offer maximum added value to effectively maintain market share and profitability.
Controlling Wellbore Direction
Directional and/or horizontal drilling methods are typically used in major oil and gas plays, including regions such as the Eagle Ford Shale, Bakken Shale and Permian Basin. For most wells, wellbore direction is navigated using downhole drilling motors with adjustable or fixed bend housings. Specifically, the motor's bent housing preferentially forces its bit toward one side of the hole, pushing it along the curved trajectory stipulated by the well plan. The drill pipe remains immobile during this sliding process. Once the required wellbore direction is achieved, the entire drill string is rotated to arrest the curvature and continue on a linear trajectory. The rate at which the hole may deviate is based on the bend angle (normally provided in eight increments from 0 to 2.5 degrees), the bit-to-bend distance and the overall motor length. For a given bit-to-bend and motor length, the larger the bend angle, the faster the hole can be turned.
Precise control of the wellbore's direction also relies on measurement-while-drilling technology. Residing in non-magnetic collars immediately above the motor, high-tech electronics are used to monitor the hole's direction (inclination and azimuth) and the angular orientation of the bend high side. Additionally, a gamma tool is typically used to assist in keeping the wellbore within the desired pay zone based on the differences in gamma counts between the zone of interest and adjacent beds. The downhole data is then sent to the surface using either a series of timed pressure pulses in the drilling fluid or modulated electromagnetic waves.
Drilling Motor Evolution
Manufacturers were assessing drilling methods and improving their downhole drilling motors long before the recent decrease in oil prices. With progressively deeper wells and the advent of directional drilling for horizontal laterals, downhole tools were required to withstand harsher environments while maintaining high performance. Manufacturers were faced with the challenge of not only ensuring maximum tool longevity in tough conditions, but also achieving increasingly higher power outputs. Development of these improved tools occurred in direct response to operator demands for reduced days between spud and well completion. Drilling motors are comprised of the following:
- Top sub (bored to accept a float valve)
- Power section
- Bent housing
- Bearing assembly with bit box
High penetration rates must be combined with extremely reliable drive train components to achieve prolonged downhole service. Consisting of a fluted rotor and a rubber-lined stator, the power section converts a portion of the drilling fluid's hydraulic energy into mechanical power in the form of rotation and torque. Currently, most motors operating in the North American market employ hard rubber elastomers that yield approximately 40 percent more horsepower than standard rubber elastomers. The higher horsepower produced by these later generation power sections greatly increased demands on the bearing pack and drive members, which rotate the drill bit. Therefore, these components had to be assessed and improved accordingly.
Case Study: A Purpose-Built Drilling Motor
With these conditions in mind, a mud motor manufacturer developed purpose-built drilling motors to address the industry's demanding downhole conditions (see Image 1). For example, motors recently helped drill multiple S-type wells for a large U.S. independent oil company. The company's typical eight-day wells were reduced in a four-well program—first to four days, then to three. The last two days were completed in single mud motor runs consisting of less than 40 hours each. This was possible because of the manufacturer's research and development process prior to market release.
Prolonged Bearing Life
Abrasive drilling fluids wear mud lube bearings, triggering high manufacturing and maintenance costs. The purpose-built mud motors feature sealed, pressure-compensated bearing packs. Because the bearing elements operate in clean oil instead of abrasive drilling mud, friction is reduced and the bit receives increased power. Rotary seals are included at each end of the bearing section to seal in the lubricating oil and prevent drilling mud from entering the bearing housing. The upper and lower seals have equivalent sealing diameters to ensure pressure balance. Furthermore, the pressure compensation system prevents high differential pressure across the rotary seals to maximize service life. It also compensates for the change in oil volume when high bottom-hole temperatures cause thermal expansion. Additionally, the pressure compensation system further discourages mud invasion by creating controlled, positive pressure inside the bearing housing.
Evenly Distributed Thrust Loads
Conventional mud lube bearing packs rely on sequential bearing wear to distribute thrust load across the stack. The bearing packs that are standard in the purpose-built motors are specifically designed to distribute the load evenly in the stack, resulting in minimal wear on individual bearings. Each bearing section uses high-capacity, roller thrust and radial bearings. Roller elements surpass sliding bushings in efficient energy transfer. To further optimize load-carrying capacities for the weight on bit and over pull, operators can easily rearrange the bearings and alter the load configurations as necessary. The thrust bearings can be stacked in either a 4:2 or a 3:3 arrangement. Either arrangement allows for improved versatility during drilling operations when load conditions change. The patent-pending thrust stack evenly distributes the operating loads among all the bearing elements. This produces balanced wear on the bearings and cushions against shock impact. All stationary bearing races are secured using compression, and the overall design minimizes diametric step changes along the mandrel, reducing stress concentrations produced by shoulders and grooves.
Drilling motor transmissions typically include either the jaw-type or constant-velocity (CV) type coupling to internally connect the rotor head and bearing pack mandrel. As the name suggests, the jaw-type coupling features its interlocking jaws, ball catch and seat arrangement. The CV-type coupling runs smoother because of its ball and socket arrangement. The purpose-built design includes an improved transmission that incorporates strengths from both coupling types while eliminating their major weaknesses. The slide block coupling is engineered to operate smoothly without compromising strength (see Figure 3). The improved transmission design allows for identical degrees of freedom as conventional transmissions. However, the load-bearing components use area contact when transmitting torque instead of the point or line contact associated with jaw couplings and conventional CV-type transmissions. This results in significantly higher load-carrying capacity and reduced fatigue stress on transmission components, preventing premature motor failures. The load-bearing areas are designed to maintain constant contact with one another, effectively mitigating impact damage caused by stop-and-start loading conditions that are unavoidable during downhole drilling.