MWD - Measurement While Drilling

Monday, September 21, 2009 by ShoXee

Measurement-While-Drilling (MWD)

Although many measurements are taken while drilling, the term MWD is
more commonly used to refer to measurements taken downhole with an
electromechanical device located in the bottomhole assembly (BHA).
Normally, the capability of sending the acquired information to the surface
while drilling continues is included in the broad definition of MWD. Telemetry
methods had difficulty in coping with the large volumes of downhole data, so
the definition of MWD was again broadened to include data that was stored
in tool memory and recovered when the tool was returned to the surface. All
MWD systems typically have three major subcomponents of varying
configurations: a power system, a directional sensor, and a telemetry
system.

Power Systems

Power systems in MWD may be generally classified as two types: battery
and 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 toolstring with or without drilling
fluid flow or during intermittent drilling fluid flow conditions.
Batteries can provide tool power without 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 LWD 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 a 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 what
is available in the rig's drilling-fluid flow. A rotor is placed in the fluid stream,
and circulating drilling fluid is directed onto the rotor blades by a stator.
Rotational force is transmitted from the rotor to an alternator through a
common shaft. The power generated by the alternator is not normally in an
immediately usable form, since it is a three-phase alternating current of
variable frequency. Electronic circuitry is required to rectify the alternating
current (AC) to usable direct current (DC). Turbine rotors for this equipment

must accept a wide range of flow rates so that multiple sets of equipment
will not be required 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. Surface screens are
often recommended to filter the incoming fluid.

Telemetry Systems

Although several different approaches have been taken to transmit data to
the surface, mud-pulse telemetry is the standard method in commercial
MWD and LWD systems. Acoustic systems that transmit up the drillpipe
suffer an attenuation of approximately 150 dB per 1000 m in drilling fluid
(Spinnler and Stone, 1978). Advances in coiled tubing promise new
development opportunities for acoustic or electric-line telemetry. 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
Low-frequency electromagnetic transmission is in limited commercial use in
MWD and LWD systems. It is sometimes used when air or foam are used as
drilling fluid. The depth from which electromagnetic telemetry can be
transmitted is limited by the conductivity and thickness of the overlying
formations. Some authorities suggest that repeaters or signal boosters
positioned in the drillstring extend the depth from which electromagnetic
systems can reliably transmit.
Three mud-pulse telemetry systems are available: positive-pulse, negative-
pulse, and continuous-wave systems. These systems are named for the way
their pulse is 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 encode data using phase shifts of the carrier. Positive-
pulse systems are more commonly used in current MWD and LWD systems.
This may be because the generation of a significant-sized negative pulse
requires a significant pressure drop across the BHA, which reduces the hole-
cleaning capacity of the drilling fluid system. Drilling engineers can find this
pressure drop difficult to deliver, particularly in the extended-reach wells for
which the technology is best suited. Many different data coding systems are
used, which are often designed to optimize the life and reliability of the
pulser, since it must survive direct contact from the abrasive, high-pressure
mud flow.
Telemetry signal detection is performed by one or more transducers located
on the rig standpipe, and data is extracted from the signals by surface
computer equipment housed either in a skid unit or on the drill floor. Real-
time detection of data while drilling is crucial to the successful application of
MWD in most circumstances. Successful data decoding is highly dependent
on the signal-to-noise ratio.

A close correlation exists between the signal size and 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 data rate adversely affects log-data density.
The sources of noise in the drilling-fluid pressure trace are numerous. Most
notable 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 using 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. As the driller applies weight to the bit, standpipe pressure increases;
as the weight is drilled off, standpipe pressure is reduced. The problem is
exacerbated when a polycrystalline diamond-compact (PDC) bit is being
used. Sometimes, the noise becomes so great that even at the lowest data
rates, successful transmission can only occur when bit contact is halted and
mud flow is circulated off-bottom. Well depth and mud type also affect the
received signal amplitude and width. In general, oil-based muds (OBMs) and
pseudo-oil-based muds (POBM) are more compressible than water-based
muds; therefore they result in the greatest signal losses. This effect can be
particularly severe in long-reach wells where OBM and POBM are commonly
used for their improved lubricity. Nevertheless, signals have been retrieved
without significant problems from depths of almost 9144 m (30,000 ft) in
compressible fluids.

handling, and hundreds of electrical connections that must all remain reliable
in harsh conditions