Turbine Motors work by harnessing the energy of a continuous flow of steam which passes through them. More specifically, drilling fluid travelling down the drillstem is deflected by the blades of a stator which is connected to the housing. This deflected fluid then flows over the blades of a rotor, which causes the drive shaft itself to rotate. The blades of both the rotor and stator are configured in the same way as a standard ventilation fan, but with the blades positioned in reverse. This is because a fan is designed to propel air outwards with a motor, whereas a turbine requires an input of air or liquid to turn its motor.
Mud or drilling fluid is pumped down the drillstring from the surface, until it enters the power section of the turbine. It then comes into contact with the stator blades, which cannot move since they are fixed to the turbine housing. The fluid’s momentum is therefore redirected to the rotor blades. This then moves the drive shaft to the drill bit, causing it to rotate. When the rotor blades perform their exit turns, the liquid is then directed into the next rotor/stator stage. Each turbine may include up to 400 of these stages, although a more typical figure is 100-250. Every stage will transmit the same amount of torque to the drive shaft, and uses up an equal amount of the total energy.
Figure 1 – Components of Turbine Motors, (oilandgasproductnews.com, 2015)
Positive-Displacement Motors (PDM) make use of a power generation section which is made up of a rotor/stator combination. In order to move a rotor part, a PDM requires hydraulic power from drilling fluid flowing through the power generation part. With a PDM, the stator and rotor work in tandem in the same way that gears do. The stator acts as the outer gear, and is made from a moulded elastomer featuring at least two lobes. The OD of the elastomer is protected by a secure metal casing. The rotor is positioned within the stator, and acts as an internal gear. This rotor is made of metal, and will have one less gear or lobe than the stator. Because of this difference, a cavity is created which is filled with drilling fluid when the PDM is downhole. This cavity acts as a wedge when it is put under pressure, and because the drilling fluid itself can’t be compressed, the force applied to the top of the wedge causes the rotor to move.
Figure 1 – Mud Motor
Most modern drilling jars are hydraulic. They are also usually double acting, meaning they can deliver an extra-heavy impact should the bottom hole assembly become stuck. They are intended to work as an integral part of the drill string, and can withstand high pressures and temperatures over a long period of time, making them suitable for long-term use.
With almost the same length and diameter specifications as standard drill collars, and with a similar connection strength and slip setting area, they may be used as a component of a stand of drill collars without difficulty.
Usually, jars will be used alongside accelerators, which are run above the jar and work automatically. They serve to amplify the impact force of the jar, and can even double it in some cases. They commonly use the compression of silicon to give added stored energy and optimize jar impact and free-travel distance in both directions. They also have the added benefit of dampening the dynamic load in the drillpipe, since they transmit shock waves poorly, thus helping reduce damage to both string and surface equipment.
Drilling Jars Diagram (Slideshare, 2017)
Not only are reamers important for directional drilling, but they can also be useful in straight hole applications. Reaming assemblies can straighten out and smooth over crooked holes, restore undergauge holes to gauge, and get rid of any irregularities or keyseats. They also help to prevent excessive hole curvature in short intervals, which may be experienced when entering and exiting a section of hole which forms a sharp curve. Finally, reamers can reduce the rotational torque in a wellbore, and may therefore be used as a substitute for a conventional string or near-bit stabilizer.
Reamers are made by almost all major downhole tool manufacturers, and have the same core features: sealed or open (mud lubricated) bearings, cutter types – either “nobbly” or “smooth”, and either one (so called “3-point”) or two (“6-point”) sets of cutters in a tool.
Reamer (Courtesy of NOV, 2017)
Between the fracture pressure and the pore pressure of the formation, the hydrostatic pressure of drilling fluid will always be maintained according to conventional drilling practice. In order to control the transport cuttings to the surface as well as the formation fluids, the drilling fluid is held within the wellbore where it circulates. Furthermore, it also keeps the drill bit cool and lubricated as it acts as a stabilizing agent. For effective use, the fluid must be water- or oil-based and this leads to a maximum weight of 19 pounds for each gallon (minimum of 7.8 pounds). As an attempt at imparting fluid loss, density, and rheological properties, it also contains a mixture of liquid and solid products.
Figure 1 – Conventional Drilling
For many years, the conventional drilling has been the safest method when drilling a well but there are also some negatives to using the method. For example, fluid invasion is a common problem because the drilling fluid pressure is naturally above the pressure of the natural formation – this can cause permeability damage. Also, physical blockages and washouts are common as the solids and fluids lodge into the formation. Continue reading