American Oil and Gas Reporter - September 2022 - 77

SpecialReport: Extended Reach Tech
collation, " he comments. " Having that information
will help company men and
others on the rig make better choices. "
Meaningful Automation
As lateral lengths have grown, so has
the importance of holistic drilling approaches,
suggests Wayne Symons,
global product line director for directional
drilling at Baker Hughes. " We all
love setting ROP records, but minimizing
tortuosity can be critical in long laterals
to successfully running completion and
production equipment, " he notes.
To minimize tortuosity, Symons recommends
rotary steerable systems. " We
have published several SPE papers documenting
that rotary steerable systems
with proportional steering deliver
smooth, high-quality wellbores, " he reports.
" Today, we are improving these
systems' performance by using downhole
sensors to automate decisions and provide
directional drillers with more accurate
information.
" We still have a long way to go to
fully automate the end to end well construction
drilling process, " Symons
muses. " However, we have made great
strides on automating key areas such as
reservoir navigation and wellbore hydraulics.
By pairing automated systems
with real-time monitoring, we can do an
excellent job of managing hole cleaning
and avoiding stuck pipe events and
drilling dysfunctions. In many applications,
this approach reduces overall
spending by shortening trip times and increasing
ROP. "
For efficient and reliable monitoring,
Symons says the data from the rig and
downhole sensors needs to be aggregated
and shown in a way people can leverage
it. " Clear visualizations can help data tell
a story, but there is so much information
coming from the rig that we also need to
direct attention to the right data at the
right time, " Symons says.
" In other words, we have the ability
for various levels of automation, including
managing by exception, " he says.
" Today's drilling software can monitor
key indicators, such as torque and drag,
equivalent circulating density and trip
speeds. If the well starts to deviate from
expectations, the system alerts the appropriate
people and provides actionable information
that will help them respond
quickly. When running in automated
mode, parameters can even be updated in
closed loop. "
Thanks to improvements in cellular
networks and drilling software, Symons
says many aspects of drilling can be managed
remotely. " Close to 90% of the
wells Baker Hughes helps drill in North
America involve some aspect of remote
operations, " he reports. " On some, we
have no employee on site. Other jobs are
hybrids, with someone on site but many
tasks handled remotely.
" While remote operations can reduce
transportation and living costs, the true
benefit is centralized expertise, " Symons
stresses. " Instead of relying entirely on
personal knowledge and experience, the
engineers at the remote center can draw
on a vast support network for any challenge.
For example, if they are having
trouble decoding a signal from a downhole
tool, they can lean across a desk and
ask a peer to double-check their interpretation.
This, combined with automating
numerous processes, is helping us continuously
drive down the risk of lost-time
incidents resulting from human error. "
The remote monitoring centers accelerate
employee learning by giving them access
to several mentors and exposing them
to a variety of rigs and situations, Symons
adds. " The employees there also appreciate
that they can go home to their families
when their shifts end, " he comments.
Vibrating Casing
To help operators get casing to bottom
quickly and reliably, Thru Tubing Solutions
offers a tool that vibrates the casing
to reduce friction between it and the wellbore,
notes Daniel Steelman, one of the
company's regional managers. He says
the improvement to casing running speed
can be striking.
Chemical Treatment
" In a run earlier this year, we had a
customer that managed to float the casing
to 900 feet above total depth. At that
point, even after filling the pipe with fluid
and rotating it, progress slowed to two
feet an hour, " Steelman relates. " Once the
operator began pumping fluid through
our tool at rates high enough to activate
it, the speed jumped to 22 feet an hour.
By end of the run, it hit 36 feet, which
helped the casing get to bottom at a reasonable
cost. "
In many applications, vibrating casing
eliminates the need to rotate it, which exacts
a toll on both the rig and casing.
" When casing rotates, collars can get
overtorqued, which can deform the casing
and make it hard to set plugs or get
mills through the collars, " he warns. " Operators
often reduce that risk by buying
premium collars with higher torque ratings,
but that extra cost may be unnecessary
if the casing can land without
rotation. "
Past runs suggest the vibration tool
frequently increases wells' production,
says Jared Clifton, Thru Tubing's international
operations manager. " In the
United States and abroad, we have run
more than 400 tools and often see a production
uplift, " he says. " We think this
uplift occurs because the vibration improves
the cement job's quality and therefore
zonal isolation during the frac. "
Clifton explains that the tool generates
pulses within the cement that break down
the surface tension between the casing
and the drilling mud, dislodging the mud
and allowing the cement to take its place.
" We liken the tool to the formwork vibration
machines that concrete companies
use as they pour sidewalk to get rid
Control Well
Casing Vibration
These cement bond logs from three wells on the same pad compare different casing
running options. The rightmost log shows dense cement and better zonal isolation than
the middle, which has low-side channeling, or the left, which has unconsolidated
cement, Thru Tubing Solutions describes. The company attributes the rightmost well's
high-quality cement partly to its casing vibration tool and notes that better zonal
isolation can improve hydraulic fracturing effectiveness.
SEPTEMBER 2022 77
American Oil and Gas Reporter - September 2022

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