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Measurement while drilling
From Wikipedia, the free encyclopedia
MWD stands for Measurement While Drilling in the oil & gas industry.
The simplest way to describe MWD is to relate it to the measurements a pilot
takes. A pilot needs to know the direction they are flying (North, South, East,
or West), the angle they are flying at (up, down, or horizontal), and what type
of skies they will be flying through (rough, choppy, cloudy, rainy, etc.). Like a
pilot a directional driller needs to know these items about the ground
formations that they are drilling through. MWD provides this information.
Previous to MWD measurements were taken at various parts of the drilling
process, but MWD has allowed these measurements to be sent to the surface
continuously while the hole is being drilled. This allows for faster drilling, more
accurate drilling, and safer drilling.
Well logging
Gamma ray logging
Spontaneous potential
logging
Resistivity logging
Density logging
Sonic logging
Caliper logging
Mud logging
LWD/MWD
Beyond the basic concept MWD is a system developed to perform drilling
related measurements downhole that are transmit to the surface while drilling a
NMR Logging
well. MWD tools are installed as part of the bottom hole assembly (BHA)
near the drill bit. The tools are either contained inside a thick walled, drill collar (drill collars are typically used to
add weight for drilling) or they are built directly into the collars at a factory prior to arriving on the drilling
location.
MWD systems can take several measurements such as Gamma Ray, compass direction (shown as azimuth),
tool face (the direction that your bit is pointing), borehole pressure, temperature, vibration, shock, torque, etc.
The MWD also provides the means of communication for operating rotary steering tools (RSTs).
The measured results are stored in MWD tools and some of the results can be transmitted digitally to surface
using mud pulser telemetry through the mud or other advanced technology such as electromagnetic(EM)
frequency communications or wired drill pipe.
Contents
1 Types of information transmitted
1.1 Directional information
1.2 Drilling mechanics information
1.3 Formation properties
2 Data transmission methods
2.1 Mud pulse telemetry
2.2 Electromagnetic telemetry (EM Tool)
2.3 Wired Drill Pipe
3 Retrievable tools
3.1 Limitations
4 References
5 See also
Types of information transmitted
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Directional information
MWD tools are generally capable of taking directional surveys in real time. The tool uses accelerometers and
magnetometers to measure the inclination and azimuth of the wellbore at that location, and they then transmit that
information to the surface. With a series of surveys; measurements of inclination, azimuth, and tool face, at
appropriate intervals (anywhere from every 30 ft (i.e. 10m) to every 500 ft), the location of the wellbore can be
calculated.
By itself, this information allows operators to prove that their well does not cross into areas that they are not
authorized to drill. However, due to the cost of MWD systems, they are not generally used on wells intended to
be vertical. Instead, the wells are surveyed after drilling through the use of Multishot Surveying Tools lowered
into the drillstring on slickline or wireline.
The primary use of real-time surveys is in Directional Drilling. For the Directional Driller to steer the well
towards a target zone, he must know where the well is going, and what the effects of his steering efforts are.
MWD tools also generally provide toolface measurements to aid in directional drilling using downhole mud
motors with bent subs or bent housings. For more information on the use of toolface measurements, see
Directional Drilling.
Drilling mechanics information
MWD tools can also provide information about the conditions at the drill bit. This may include:
Rotational speed of the drillstring
Smoothness of that rotation
Type and severity of any vibration downhole
Downhole temperature
Torque and Weight on Bit, measured near the drill bit
Mud flow volume
Use of these information can allow the operator to drill the well more efficiently, and to ensure that the MWD
tool and any other downhole tools, such as Mud Motors, Rotary Steerable Systems, and LWD tools, are
operated within their technical specifications to prevent tool failure. This information also is valuable to
Geologists responsible for the well information about the formation which is being drilled.
Formation properties
Many MWD tools, either on their own, or in conjunction with separate Logging While Drilling tools, can take
measurements of formation properties. At the surface, these measurements are assembled into a log, similar to
one obtained by wireline logging.
LWD Logging While Drilling tools are able to measure a suite of geological characteristics including- density,
porosity, resistivity, acoustic-caliper, inclination at the drill bit (NBI), magnetic resonance and formation
pressure.
The MWD tool allows these measurements to be taken and evaluated while the well is being drilled. This makes
it possible to perform Geosteering, or Directional Drilling based on measured formation properties, rather than
simply drilling into a preset target.
Most MWD tools contain an internal Gamma Ray sensor to measure natural Gamma Ray values. This is
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because these sensors are compact, inexpensive, reliable, and can take measurements through unmodified drill
collars. Other measurements often require separate Logging While Drilling tools, which communicate with the
MWD tools downhole through internal wires.
Measurement while drilling can be cost-effective in exploration wells, particularly in areas of the Gulf of Mexico
where wells are drilled in areas of salt diapirs. The resistivity log will detect penetration into salt, and early
detection prevents salt damage to bentonite drilling mud.
Data transmission methods
Mud pulse telemetry
This is the most common method of data transmission used by MWD (Measurement While Drilling) tools.
Downhole a valve is operated to restrict the flow of the drilling mud (slurry) according to the digital information
to be transmitted. This creates pressure fluctuations representing the information. The pressure fluctuations
propagate within the drilling fluid towards the surface where they are received from pressure sensors. On the
surface, the received pressure signals are processed by computers to reconstruct the information. The
technology is available in three varieties - positive pulse, negative pulse, and continuous wave.
Positive Pulse
Positive Pulse tools briefly close and open the valve to restrict the mud flow within the drill pipe. This
produces an increase in pressure that can be seen at surface. Line codes are used to represent the digital
information in form of pulses.
Negative Pulse
Negative pulse tools briefly open and close the valve to release mud from inside the drillpipe out to the
annulus. This produces a decrease in pressure that can be seen at surface. Line codes are used to
represent the digital information in form of pulses.
Continuous Wave
Continuous wave tools gradually close and open the valve to generate sinusoidal pressure fluctuations
within the drilling fluid. Any digital modulation scheme with a continuous phase can be used to impose the
information on a carrier signal. The most widely used modulation scheme is continuous phase modulation.
When underbalanced drilling is used, mud pulse telemetry can become unusable. This is because usually in order
to reduce the equivalent density of the drilling mud a compressible gas is injected into the mud. This causes high
signal attenuation which drastically reduces the ability of the mud to transmit pulsed data. In this case it is
necessary to use methods different from mud pulse telemetry, such as electromagnetic waves propagating
through the formation or wired drill pipe telemetry.
Current mud pulse telemetry technology offers a bandwidths of up to 40 bit/s.[1] The data rate drops with
increasing length of the wellbore and is typically as low as 1.5 bit/s[2] - 3.0 bit/s.[1] (bits per second) at a depth
of 35,000 ft - 40,000 ft (10668 m - 12192 m).
Surface to down hole communication is typically done via changes to drilling parameters, i.e. change of the
rotation speed of the drill string or change of the mud flow rate. Making changes to the drilling parameters in
order to send information can require interruption of the drilling process, which is unfavorable due to the fact that
it causes non-productive time.
Electromagnetic telemetry (EM Tool)
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These tools incorporate an electrical insulator in the drillstring. To transmit data the tool generates an altered
voltage difference between the top part (the main drillstring, above the insulator), and the bottom part (the drill
bit, and other tools located below the insulator of the MWD tool). On surface a wire is attached to the
wellhead, which makes contact with the drillpipe at the surface. A second wire is attached to a rod driven into
the ground some distance away. The wellhead and the ground rod form the two electrodes of a dipole antenna.
The voltage difference between the two electrodes is the receive signal that is decoded by a computer.
The EM tool generates voltage differences between the drillstring sections in the pattern of very low frequency
(2–12 Hz) waves. The data is imposed on the waves through digital modulation.
This system generally offers data rates of up to 10 bits per second. In addition, many of these tools are also
capable of receiving data from the surface in the same way, while mud pulse-based tools rely on changes in the
drilling parameters, such as rotation speed of the drillstring or the mud flow rate, to send information from the
surface to downhole tools. Making changes to the drilling parameters in order to send information to the tools
generally interrupts the drilling process, causing lost time.
Compared to mud pulse telemetry, electronic pulse telemetry is more effective in certain specialized situations,
such as underbalanced drilling or when using air as drilling fluid. However, it generally falls short when drilling
exceptionally deep wells, and the signal can lose strength rapidly in certain types of formations, becoming
undetectable at only a few thousand feet of depth.
Wired Drill Pipe
Several oilfield service companies are currently developing wired drill pipe systems. These systems use electrical
wires built into every component of the drillstring, which carry electrical signals directly to the surface. These
systems promise data transmission rates orders of magnitude greater than anything possible with mud pulse or
electromagnetic telemetry, both from the downhole tool to the surface, and from the surface to the downhole
tool. The IntelliServ [3] wired pipe network, offering data rates upwards of 1 megabit per second, became
commercial in 2006. Representatives from BP America, StatoilHydro, Baker Hughes INTEQ, and
Schlumberger presented three success stories using this system, both onshore and offshore, at the March, 2008
SPE/IADC Drilling Conference in Orlando, Florida.[4]
Retrievable tools
MWD tools may be semi-permanently mounted in a drill collar (only removable at servicing facilities), or they
may be self-contained and wireline retrievable.
Retrievable tools, sometimes known as Slim Tools, can be retrieved and replaced using wireline through the drill
string. This generally allows the tool to be replaced much faster in case of failure, and it allows the tool to be
recovered if the drillstring becomes stuck. Retrievable tools must be much smaller, usually about 2 inches or less
in diameter, though their length may be 20 feet or more. The small size is necessary for the tool to fit through the
drillstring, however, it also limits the tool's capabilities. For example, slim tools are not capable of sending data
at the same rates as collar mounted tools, and they are also more limited in their ability to communicate with and
supply electrical power to other LWD tools.
Collar-mounted tools, also known as Fat Tools, cannot generally be removed from their drill collar at the
wellsite. If the tool fails, the entire drillstring must be pulled out of the hole to replace it. However, without the
need to fit through the drillstring, the tool can be larger and more capable.
The ability to retrieve the tool via wireline is often useful. For example, if the drillstring becomes stuck in the
hole, then retrieving the tool via wireline will save a substantial amount of money compared to leaving it in the
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hole with the stuck portion of the drillstring. However, there are some limitations on the process.
Limitations
Retrieving a tool using wireline is not necessarily faster than pulling the tool out of the hole. For example, if the
tool fails at 1,500 ft (460 m) while drilling with a triple rig (able to trip 3 joints of pipe, or about 90 ft (30 m)
feet, at a time), then it would generally be faster to pull the tool out of the hole than it would be to rig up wireline
and retrieve the tool, especially if the wireline unit must be transported to the rig.
Wireline retrievals also introduce additional risk. If the tool becomes detached from the wireline, then it will fall
back down the drillstring. This will generally cause severe damage to the tool and the drillstring components in
which it seats, and will require the drillstring to be pulled out of the hole to replace the failed components, thus
resulting in a greater total cost than pulling out of the hole in the first place. The wireline gear might also fail to
latch onto the tool, or in the case of a severe failure, might bring only a portion of the tool to the surface. This
would require the drillstring to be pulled out of the hole to replace the failed components, thus making the
wireline operation a waste of time.
References
1. ^ a b "Mud-pulse telemetry sees step-change improvement with oscillating shear valves"
(http://www.ogj.com/articles/save_screen.cfm?ARTICLE_ID=332411) . 2008.
http://www.ogj.com/articles/save_screen.cfm?ARTICLE_ID=332411. Retrieved 2009-03-23.
2. ^ "Orion II MWD System" (http://www.slb.com/content/services/drilling/telemetry/orion_II_mwd.asp?
entry=orion2&) . 2009. http://www.slb.com/content/services/drilling/telemetry/orion_II_mwd.asp?
entry=orion2&. Retrieved 2009-03-23.
3. ^ "Intelliserv Network" (http://intelliserv.com/) . 2008. http://intelliserv.com/. Retrieved 2008-03-13.
4. ^ "T.H. Ali, et al., SPE/IADC 112636: High Speed Telemetry Drill Pipe Network Optimizes Drilling Dynamics
and Wellbore Placement; T.S. Olberg et al., SPE/IADC 112702: The Utilization of the Massive Amount of RealTime Data Acquired in Wired-Drillpipe Operations; V. Nygard et al., SPE/IADC 112742: A Step Change in
Total System Approach Through Wired-Drillpipe Technology" (http://www.aboutoilandgas.com/speapp/spe/meetings/DC/2008/tech_prog_THURS.htm) . 2008. http://www.aboutoilandgas.com/speapp/spe/meetings/DC/2008/tech_prog_THURS.htm. Retrieved 2008-03-13.
See also
Directional drilling
Geosteering
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