OFFSHORE AUTOMATION SOLUTIONS
MWD tools, fber optic sensors improve downhole monitoring
As the industry continues to develop reservoirs in more extreme environments – deeper water, higher sour gas concentrations,
greater concentration of wells per pad, longer
horizontal depths – the need to understand
what is happening not only while drilling the
hole but also during production continues to
increase in importance.
The industry uses gyroscopes, magnetometers and accelerometers, as well as
traditional well logging measurements, to
determine formation properties (resistivity,
natural gamma ray, porosity), wellbore geometry (inclination, azimuth), drilling system orientation (tool face), and mechanical
properties of the drilling process. As these
measurement tools are part of the drillstring
and must provide the data in real time so
they can be used to control the steering and
direction of the drill bit (hence the name
measurement-while-drilling, MWD), the
data needs to be transmitted to the surface.
The two most commonly used ways are via
pulses through the mud column (mud pulse)
and electromagnetic telemetry. Technically,
the formation property measurements are
referred to as logging-while-drilling (LWD)
tools; however, many of the communication
techniques are the same.
With day rates for offshore drilling near
$500,000, minimizing “time on hole” while
maintaining a safe operation becomes critical. MWD helps both these criteria by reducing drilling problems as well as risk. Reductions in risk are possible because wear
and fatigue on drillstring components will be
minimized and downtime caused by bottom-hole assembly (BHA) components failures
(bits, mud motors, and MWD tools) can
be eliminated. It is also possible to improve
the actual drilling process with improved
rates of penetration by reducing drillstring
friction against the side of the wellbore.
This results in the right amount of drilling
energy being transferred to the bit while
also helping the driller appropriately adjust
both weight-on-bit and rotation speed as the
lithology changes, thus optimizing the performance of bits and mud motors.
Due to the limited “bandwidth” available
with pulse communication and the risk that
this communication could be lost, these tools
will also have on-board memory to store the
same information at a higher update rate.
This provides increased granularity of measurement, and the data can also be recovered
once the tool is removed from the hole.
Due to the limited bandwidth available
of approximately 40 bits/second with pulse
communication, and the risk that this com-
munication is lost, these sensors also have
on-board memory to store the same infor-
mation at a higher update rate than it is
possible to transmit. Increased update rate
equates to more and hence better measure-
ments which can be recovered once the tool
is removed from the hole.
Automation and sensing technology
continues to rise to the challenge by
providing hardware and software solutions
to continue to “push the envelope.”
data using the phase shifts of the carrier. In
general, oil-based muds (OBMs) and pseudo-oil-based muds are more compressible than
water-based muds, and this compressibility
leads to greater signal losses. Attenuation
in mud-pulse systems is approximately 150
dB per 1,000 m ( 3,280 ft) in drilling fuid;
though signals can still be detected in wells
with depths in excess of 9,000 m ( 29,520 ft).
When air or foam is used as drilling fuid,
low-frequency electromagnetic transmission
is starting to gain traction.
With the increasing number of horizontal
wells being drilled, once a well angle exceeds 60°, the logging tools can no longer
be pushed through the well to retrieve information. This provides another incentive to
incorporate the above basic measurements
into the drilling process.
Though an important part of the process,
drilling and completion is only the start of
a well’s lifecycle. Once the well has been
drilled, it is important to confrm that the
reservoir has not been damaged to help ensure best return on investment by optimizing the well’s production.
In addition to “traditional” wired sensors, f-
ber optic sensors are well suited for downhole
applications because of the high resolution of
both measurement and location of sensing ele-
ment, immunity to EMI, small size, and mul-
tiple kilometer sensing capability. Fiber optic
sensors are able to achieve 0.1% accuracy with
a 0-8,000 psi working range for the pressure
glass sensing fber-a phenomenon known as
hydrogen darkening. Fortunately, modern
pure-silica fbers with virtually no darkening
and improved hermetic coatings and pack-
aging techniques can allow fber operation
at temperatures up to 700°C. Just as the
challenge of fber optic darkening is being
addressed, the sensing systems themselves
are also continuing to evolve. These systems
can now be multiplexed in a variety of con-
fgurations on a single quarter-inch cable,
offering permanent deployment of multi-
parameter sensors in multiple zones in the
harshest of conditions.
Ian Verhappen, P.Eng. is an ISA Fellow, ISA Certifed
Automation Professional (CAP), Automation Hall of
Fame member, and an authority on process analyzer
sample systems and industrial communications technologies. Verhappen provides consulting services in the
areas of feld level industrial communications, process
analytics, and hydrocarbon facility automation. He can
be reached at email@example.com.