American Oil and Gas Reporter - August 2016 - 47

SpecialReport: Horizontal & Innovative Drilling

Communications Workflow
The workflow implemented on Pad 1
wells included real-time data streaming between the rig and office personnel. Using
well-site information transfer standard
markup language, data from the rig
(weight on bit, torque, flow rate, rpm,
standpipe pressure, differential pressure,
etc.) and from the HBRSS system itself
(surveys, bulk and up/down gamma, vibrations, steering commands, etc.) could be
viewed by off-site personnel 30 seconds
after they were recorded in the database.
This allowed geologists, reservoir navigation specialists, and other personnel to
quickly observe trends between parameters, predict apparent formation bed dips
before a survey post, and make changes to
stay in the assigned drilling window.
In addition, drilling coordinators could
closely monitor overall performance and
key performance indicators (KPIs) such as
the amount of build in the curve section
and the effects of drilling parameters on
BUR or ROP.
Although the PIT project was a new development area for CONSOL Energy,
the company had drilled hundreds of
Marcellus wells with HBRSS technology.
This helped build a trust level between the
operator's geology team and the service
provider's reservoir navigation team, and
gave reservoir navigation experts the freedom to make steering changes without prior approval under certain circumstances.
The reservoir navigation team could make
inclination changes of less than 0.5 degree/stand, which enabled quicker changes

FIGURE 4
HBRSS Average Footage Drilled in Marcellus and Utica
(CONSOL Energy = CNX)
12,000
10,000
Avg. Footage Drilled

and premature cutter wear on the bit.
The landing and lateral sections are
characterized by clean shale and minimal
risk of bit damage. Once the well enters
the Burkett, this section is mostly easy
drilling the rest of the way through the
Marcellus with the exception of the Tully, where controlled drilling may be necessary. Should the BHA fall out of zone,
the lower boundary below the Marcellus,
represented by the Onondaga Limestone,
can cause abnormal bit damage because
of its harder lithological characteristics.
The one-run goal meant the HBRSScustomized PDC bit design had to encompass durability, stability, consistent BURs,
fine-tuned steering capabilities, endurance,
and fast penetration rates while delivering
long and reliable laterals. These key features were integrated into a five-bladed
PDC bit with 16-millimeter cutters customized for the Marcellus Shale.

8,000
6,000
4,000
2,000
0

2011

2012

All Operators, All Counties (Marcellus & Utica)

2013

CNX Operators, All Counties (Marcellus & Utica)

2014

2015
CNX Operators, Allegheny County (Marcellus)

FIGURE 5
Pad 1 Optimized Bit/BHA Design
And Finite Element Analysis Lateral Deflection Results
Min

Lateral Deflection

Max

Mud Motor
Flex Area
+ Flex Stab
HBRSS

Optimized BHA/Bit Design
PDC bit AT505
HBRSS
Nonmagnetic flex 83⁄8-inch stabilizer
30-foot nonmagnetic drill pipe (NMCSDP)
High-performance motor M1XL/RS (0.21 rev/gal)
30-foot NMCSDP
Filter and float subs

for overall better drilling performance.
The workflow usually consisted of
the reservoir navigation team contacting
the directional driller with an inclination
setting. The change often was made at the
start of the stand, so the driller could pair
it with any other needed changes to minimize overall downlinks.
Communication between these two
parties was not limited to drilling plan adjustments, however. If the directional
driller saw an unexpected change in azimuth or inclination, he discussed it with
reservoir navigation personnel to formulate a plan to get into a better drilling zone
within the target window.
This communication enabled the
drilling, reservoir navigation, and geology groups to combine goals into the singular task of drilling the smoothest and
fastest well possible while staying in

zone 100 percent of the time.
The reservoir navigation group provided constant e-mail updates to all pertinent
operator and service company personnel
from the start of the curve to TD. Updates
were sent at every stand in the curve and
every two-three stands in the lateral to
show the wellbore's actual position in relation to formations of interest and the target window. The updates also provided apparent bed dips and comments about any
stratigraphic movements or drilling issues
that had occurred since the last update.
Crucial Capabilities
There were several best practices
agreed on for each on- and off-bottom situation. Most importantly, these best practices were identified by on-site personnel
working with the optimization team's
off-site personnel to provide a sense of
AUGUST 2016 47
American Oil and Gas Reporter - August 2016

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