Very hard and abrasive formations are often drilled with impregnated bits and high speed turbines. Typical application areas include the Middle East, onshore Germany, the North Sea, West Venezuela, and Italy. As opposed to positive displacement motors, turbines do not need elastomers in the power section, which can result in better durability in high temperature environments. Due to its hydrodynamic function principle the power output of a turbine is not linear with the flow rate. A 20% reduction in mud flow reduces the power output by 50%, which drastically reduces ROP in all deep wells, slim holes or lost circulation situations, where it is not possible to operate the BHA with the full flow rate. Furthermore, the use of hydrodynamic power sections does not allow a clear indication of the bit RPM for the optimum operating point or bit stalling via standpipe pressure readings. In order to overcome these operational difficulties a special high speed positive displacement motor (PDM) was developed. Due to the new design and manufacturing processes this motor combines the advantages of turbines (high bit speed, low sensitivity with regards to temperature) with the advantages of PDMs (RPM proportional to flow rate and nearly independent of the loading). With the superior torque capability the power output of this new downhole motor is more than double as compared to turbines, resulting in the possibility of using more aggressive bits and increasing ROP. The paper discusses case histories from Oman, Germany and Italy and directly compares the performance of turbines with the latest design high speed PDMs. The case histories also demonstrate that the use of additional performance tools (i.e. downhole thrusters) can not only significantly improve the steering behaviour of the drilling assembly, but also extend the maximum possible horizontal displacement of a well, and minimizes BHA failures. Introduction It is considered that PDC bits can be used in formations of compressive strengths up to 25,000 to 30,000 PSI. In harder formations roller cone bits or impregnated bits are used. Steering with impregnated bits is nearly as easy as with roller cone bits, but as impregnated bits do not have bearings or moving parts they can be kept in the hole much longer. Impregnated bits drill sand, shales and some limestones with same or higher ROPs than roller cone bits. Due to their low cutting depth impregnated bits require very high bit RPM to achieve good penetration rates. For many years turbines have been able to generate much greater bit speeds compared to mud motors and have been the preferred drive mechanism for impregnated bits. However, already in the early Eighties high speed positive displacement motors have been developed which operate at rotational speeds comparable to turbines 1. These motors have now been introduced into the market utilizing the reliable components especially developed for modern extended length drilling motors 2. Performance Characteristic Comparison Turbine/Mud Motor Certain application areas require high RPM at the bit and a certain bit technology for optimized drilling as indicated above. It is a common practice to use a hydraulic downhole motor to generate the mechanical power at high speeds by conversion of hydraulic energy from the mud system. The advantage is that the drill string itself can be rotated at moderate speed and depending of the motor system technology directional drilling is possible without drill string rotation. Two system are commonly used:the "hydrodynamic" turbine based on the impact of the fluid on the turbine wheels and3the "hydrostatic" positive displacement motor also known as a progressive cavity system, or Moineau motor2.
A new workover motor, incorporating equidistant power section technology, has demonstrated that it can produce more torque for milling/workover operations and can operate at higher temperatures than previous positive displacement motor (PDM) designs. This paper discusses the operating principles of PDM tools to show how the equidistant technology increases efficiency and improves performance. In addition, the paper presents laboratory and operational test examples that verify the performance improvements. Three case histories demonstrate how this technology has reduced the cost of well intervention through higher Rates of Penetration, reduced milling times, fewer trips to surface and increased equipment reliability. The new technology incorporates a unique and innovative "equidistant" power section design. The power section is made with a proprietary, contoured stator manufacturing process that reduces the motor's rubber content considerably for higher efficiency, lower friction and less distortion. The case histories presented here discuss applications that previously would have been considered too risky or impractical for standard PDM motors. The case histories also substantiate that this power section technology is more tolerant when exposed to higher temperatures, pressures and fluid solids. Introduction Over the last decade, the growth of coiled tubing workover operations has increased the demand for reliable workover motor technology to provide rotary power for cleanout and milling procedures. Positive Displacement Motor (PDM) technology has proven to be the most reliable for workover motor applications. The PDM is a hydraulically driven motor, based on the Moineau principle. The output torque is proportional to the differential pressure across the power section and the speed is proportional to the flow rate. Because the differential pressure and flow rate can be monitored and controlled from the surface, the PDM is easy to operate. The motor consists of a top sub, power section, transmission assembly, a bearing assembly and a drive sub. In the power section of a PDM, a helical rotor with one or more lobes is placed eccentrically inside a stator having one more lobe than the rotor. This difference between the rotor /stator lobe configuration creates a cavity which, when pumped through, is filled with fluid (see Figure 1). Under pressure, the fluid drives the rotor in an eccentric rotation. The transmission assembly translates this into concentric rotation and transfers the power to the drill bit. Drilling motors and workover motors vary somewhat in design. To provide directional capabilities, a drilling motor contains a deflection device, typically an adjustable bent housing, between the power section and bearing assembly. The drilling motor also must allow for higher bending stress and cyclic loading than a workover motor, so its components require higher tensile strength. Workover motors are used in a cased hole environment and on deployment strings (i. e. coiled tubing, small threaded pipe) that allow for considerably less weight on bit. PDM Operating Principle A PDM works with the reverse principle of a Moineau pump, converting hydraulic energy into mechanical energy. This conversion is not completely efficient because of leakage and other energy losses. Basic physical formulas apply to the operation of a PDM as shown in the explanation below.
Uncertainty in predicting formation integrity as well as pressure regimes poses significant risks to drilling operations. Several technologies can predict downhole environments in terms of formation strength, kick detection etc., but no solution currently exists for kick isolation. This paper presents an innovative well control and risk mitigation technology that is deployed while drilling and the result of a field test offshore Italy. The new system is integrated in the bottom hole assembly (BHA), and in case of a kick can shut-in the annulus and the drillstring on demand to confine the influx at the well bottom below the sealing elements. A bypass port that establishes communication with the drillstring and annulus can be opened above the sealing elements to allow adjusting of the mud weight. Downhole pressure above and below the annular seal and inside the string can be monitored in real time. The system is deployed in combination with Wired Drill Pipe to ensure activation and bi-directional communication that is independent of any fluid flow. The system was run on top of the directional rotary steerable BHA while drilling an 8½-in. hole section. The field test was conducted after drilling more than 500 m of new formation and 90 hours in hole. Prior to the test, the system was pulled to surface for visual inspection. No irregularities were observed. The system was then run back in open hole, activated according to operating procedures and tested by applying pressure into the annulus. The well was monitored and no leakage was observed concluding a successful test. Finally, the bypass was opened, circulation was re-established, and the system was deactivated and then pulled out of hole. This paper describes the technology features and summarizes the first field test results of a new risk mitigation technology for well control situations. This document also shows how deploying new solutions can help E&P operators improve well control through a cost-effective solution and reduce operational risk in case of formation fluid influx into a wellbore.
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