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Measurement while drilling (MWD)
Although many measurements are taken while drilling, the term MWD refers to measurements taken downhole with an electromechanical device located in the bottomhole assembly (BHA).
- 1 Overview
- 2 Power systems
- 3 Telemetry systems
- 4 Directional sensors
- 5 Tool operating environment and tool reliability
- 6 References
- 7 Noteworthy papers in OnePetro
- 8 External links
- 9 See also
Telemetry methods had difficulty in coping with the large volumes of downhole data, so the definition of MWD was broadened to include data that were stored in tool memory and recovered when the tool was returned to the surface. All MWD systems typically have three major subcomponents:
- Power system
- Telemetry system
- Directional sensor
Power systems in MWD generally may be classified as one of two types: battery or turbine. Both types of power systems have inherent advantages and liabilities. In many MWD systems, a combination of these two types of power systems is used to provide power to the MWD tool so power will not be interrupted during intermittent drilling-fluid flow conditions. Batteries can provide this power independent of drilling-fluid circulation, and they are necessary if logging will occur during tripping in or out of the hole.
Lithium-thionyl chloride batteries are commonly used in MWD systems because of their excellent combination of high-energy density and superior performance at MWD service temperatures. They provide a stable voltage source until very near the end of their service life, and they do not require complex electronics to condition the supply. These batteries, however, have limited instantaneous energy output, and they may be unsuitable for applications that require a high current drain. Although these batteries are safe at lower temperatures, if heated above 180°C, they can undergo a violent, accelerated reaction and explode with significant force. As a result, there are restrictions on shipping lithium-thionyl chloride batteries in passenger aircraft. Even though these batteries are very efficient over their service life, they are not rechargeable, and their disposal is subject to strict environmental regulations.
The second source of abundant power generation, turbine power, uses the rig’s drilling-fluid flow. Rotational force is transmitted by a turbine rotor to an alternator through a common shaft, generating a three-phase alternating current (AC) of variable frequency. Electronic circuitry rectifies the AC into usable direct current (DC). Turbine rotors for this equipment must accept a wide range of flow rates to accommodate all possible mud-pumping conditions. Similarly, rotors must be capable of tolerating considerable debris and lost-circulation material (LCM) entrained in the drilling fluid.
Mud-pulse telemetry is the standard method in commercial MWD and logging while drilling (LWD) systems. Acoustic systems that transmit up the drillpipe suffer an attenuation of approximately 150 dB per 1000 m in drilling fluid. Several attempts have been made to construct special drillpipe with an integral hardwire. Although it offers exceptionally high data rates, the integral hardwire telemetry method requires:
- Expensive special drillpipe
- Special handling
- Hundreds of electrical connections that must all remain reliable in harsh conditions
The explosion of downhole measurements has stimulated new work in this area, and data rates in excess of 2,000,000 bits/second have been demonstrated.
Low-frequency electromagnetic transmission is in limited commercial use in MWD and LWD systems. It is sometimes used when air or foam is used as drilling fluid. The depth from which electromagnetic telemetry can be transmitted is limited by the conductivity and thickness of the overlying formations. Repeaters or signal boosters positioned in the drillstring extend the depth from which electromagnetic systems can transmit reliably.
Three mud-pulse telemetry systems are available: positive-pulse, negative-pulse, and continuous-wave systems. These systems are named for the ways in which their pulses are propagated in the mud volume. Negative-pulse systems create a pressure pulse lower than that of the mud volume by venting a small amount of high-pressure drillstring mud from the drillpipe to the annulus. Positive-pulse systems create a momentary flow restriction (higher pressure than the drilling-mud volume) in the drillpipe. Continuous-wave systems create a carrier frequency that is transmitted through the mud, and they encode data using the phase shifts of the carrier. Many different data-coding systems are used, which are often designed to optimize the life and reliability of the pulser, because it must survive direct contact with the abrasive, high-pressure mud flow.
Telemetry-signal detection is performed by one or more transducers located on the rig standpipe. Data are extracted from the signals by surface computer equipment housed either in a skid unit or on the drill floor. Successful data decoding is highly dependent on the signal-to-noise ratio.
A close correlation exists between the signal size and the telemetry data rate; the higher the data rate, the smaller the pulse size becomes. Most modern systems have the ability to reprogram the tool’s telemetry parameters and slow down data-transmission speed without tripping out of the hole; however, slowing the data rate adversely affects log-data density.
The most notable sources of signal noise are the mud pumps, which often create a relatively high-frequency noise. Interference among pump frequencies leads to harmonics, but these background noises can be filtered out with analog techniques. Pump-speed sensors can be a very effective method of identifying and removing pump noise from the raw telemetry signal. Lower-frequency noise in the mud volume is often generated by drilling motors. Well depth and mud type also affect the received-signal amplitude and width. In general, oil-based muds (OBMs) and pseudo-oil-based muds are more compressible than water-based muds; therefore, they result in the greatest signal losses. Nevertheless, signals have been retrieved without significant problems from depths of almost 9144 m (30,000 ft) in compressible fluids.
The state of the art in directional-sensor technology is an array of three orthogonal fluxgate magnetometers and three accelerometers. Although in normal circumstances, standard directional sensors provide acceptable surveys, any application in which uncertainty in the bottomhole location exists can be troublesome. Recent trends to drill longer and more complex wells focused attention on the need for a standard error model.
Work carried out by the Industry Steering Committee on Wellbore Accuracy (ISCWA) aimed to provide a standard method of quantifying positional uncertainties with associated confidence levels. The key sources of error were classified:
- Sensor errors
- Magnetic interference from the BHA
- Tool misalignment
- Magnetic-field uncertainty
Along with uncertainties in the measured depth, bottomhole survey uncertainties are one contributor to errors in the absolute depth. Note that all methods of real-time azimuth correction require raw data to be transmitted to the surface, which imposes load on the telemetry channel.
The development of gyroscope (gyro)-navigated MWD offers significant benefits over existing navigation sensors. In addition to greater accuracy, gyros are not susceptible to interference from magnetic fields. Current gyro technology centers upon incorporating mechanical robustness, minimizing external diameter, and overcoming temperature sensitivity. The main application of the technology is in saving the rig time used by wireline gyros when carrying out kickoffs from areas affected by magnetic interference.
Tool operating environment and tool reliability
MWD systems are used in the harshest operating environments. Obvious conditions such as high pressure and temperature are all too familiar to engineers and designers. The wireline industry has a long history of successfully overcoming these conditions.
Most MWD tools can operate continuously at temperatures up to 150°C, with some sensors available with ratings up to 175°C. MWD-tool temperatures may be 20°C lower than formation temperatures measured by wireline logs, owing to the cooling effect of mud circulation, so the highest temperatures encountered by MWD tools are those measured while running into a hole in which the drilling-fluid volume has not been circulated for an extended period. In such cases, it is advisable to break circulation periodically while running in the hole. Using a Dewar flask to protect sensors and electronics from high temperatures is common in wireline, where downhole exposure times are usually short, but using flasks for temperature protection is not practical in MWD because of the long exposure times at high temperatures that must be endured.
Downhole pressure is less a problem than temperature for MWD systems. Most tools are designed to withstand up to 20,000 psi, with specialist tools rated to 25,000 psi. The combination of hydrostatic pressure and system backpressure rarely approaches this limit.
Downhole shock and vibration
Downhole shock and vibration present MWD systems with their most severe challenges. Contrary to expectation, early tests using instrumented downhole systems showed that the magnitudes of lateral (side-to-side) shocks are dramatically greater than axial shocks during normal drilling. Modem MWD tools are generally designed to withstand shocks of approximately 500 G for 0.5 ms over a life of 100,000 cycles. Torsional shock, produced by stick/slip torsional accelerations, may also be significant. If subjected to repeated stick/slip, tools can be expected to fail.
Tool reliability statistics
Early work done to standardize the measurement and reporting of MWD-tool reliability statistics focused on defining a failure and dividing the aggregate number of successful circulating hours by the aggregate number of failures. This work resulted in a mean-time-between-failure (MTBF) number. If the data were accumulated over a statistically significant period (typically 2,000 hours), meaningful failure-analysis trends could be derived. As downhole tools became more complex, however, the International Association of Drilling Contractors (IADC) published recommendations on the acquisition and calculation of MTBF statistics.
- Spinnler, R.F. and Stone, F.A. 1978. Mud Pulse Logging While Drilling Telemetry System: Design, Development and Demonstrations. Presented at the IADC Drilling Technology Conference, Houston, Texas, USA, 7 March.
- Jellison, M.J., Hall, D.R., Howard, D.C. et al. 2003. Telemetry Drill Pipe: Enabling Technology for the Downhole Internet. Presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 19-21 February. SPE-79885-MS. http://dx.doi.org/10.2118/79885-MS.
- Ng, F. 1989. Recommendations for MWD Tool Reliability Statistics. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October. SPE-19862-MS. http://dx.doi.org/10.2118/19862-MS.
Noteworthy papers in OnePetro
Tanguy, D.R., Zoeller, W.A. 1981. APPLICATIONS OF MEASUREMENTS WHILE DRILLING, SPE Annual Technical Conference and Exhibition, 4-7 October. 10324-MS. http://dx.doi.org/10.2118/10324-MS
John E. Fontenot 1986. Measurement While Drilling - A New Tool (includes associated papers 15328 and 15343), Journal of Petroleum Technology Volume 38, Number 2. 15276-PA. http://dx.doi.org/10.2118/15276-PA