American Oil and Gas Reporter - August 2016 - 44

SpecialReport: Horizontal & Innovative Drilling
CONSOL Energy launched drilling operations on the six-well Pad ACAA-2 in
late 2014. It then initiated a multidisciplinary team effort to apply lessons learned
on Pad 2 to improve drilling performance
on the eight-well Pad 1. A key part of the
team's solution was incorporating an advanced high buildup rate rotary steerable
system (HBRSS) to optimize well profiles
with high buildup rates (BURs), to efficiently drill long laterals while remaining
in zone, and to drill the vertical, tangent
and lateral sections in a single run.
The combination of HBRSS technology with a detailed data communications
workflow and effective best practices for
bit and bottom-hole assembly design,
drilling parameter optimization, and reservoir navigation techniques resulted in
optimized drilling times, reduced operational costs, financial predictability, and
consistency on Pad 1 wells. In fact, half
the wells achieved record footage rates
consistently greater than one mile within
24 hours, and the majority of the laterals
remained in the target zone 100 percent of
the time.
The team of drilling, geoscience, and
reservoir navigation experts collaborated

to address the engineering challenges on
Pad 1 and design an extensive plan that focused on two main goals:
* Achieving the best reservoir exposure for optimal production from the
Middle Devonian Marcellus as well as targeted Upper Devonian formations; and
* Maximizing drilling efficiency and
consistency, including increasing penetration rates, eliminating drilling laterals
out of zone, and drilling the vertical,
curve and lateral sections in one BHA run.
Pad Design And Spacing
As shown in Figure 1, both Pad 1 (blue)
and Pad 2 (red) were designed with negative vertical sections and long laterals, but
Pad 1 wells are characterized by longer laterals with optimized spacing to enable developing two formations from the offset
Pad 2 wells. The lateral lengths of the eight
Pad 1 wells averaged 9,700 feet, and the
curve sections had BURs up to 10 degrees
per 100 feet. HBRSS technology consistently achieved the desired BURs in the
8¾-inch curve section to land at the predetermined landing point and then drill the
lateral to total depth using near-bit inclination and gamma ray readings to stay

FIGURE 1
Spider Plot of Pad 1 (Blue) and Offset Pad 2 (Red)
At PIT Airport Project

Source: Google Earth and well surveys

44 THE AMERICAN OIL & GAS REPORTER

within the target zone.
Initially, the optimization process centered on offset data analysis from Pad 2 to
determine opportunities for improvement,
focusing on directional drilling, reservoir
navigation, bit/BHA matching, active
drilling parameters management, and best
practices.
Well trajectory design was critical to ensure a proper surface location and the best
possible lease development area. The
multidisciplinary team collaboratively
determined the best wellbore trajectory,
based on torque and drag modeling, hydraulic analysis, and tailored reservoir navigation models to minimize problems. To
mitigate torque and drag and improve lease
development, the surface location was
changed from offset Pad 2 (the two main
target zones were planned within a 500foot total-vertical-depth difference).
Figure 2 shows two views of Pad 1 and
Pad 2 well trajectories. Pad 1 had a combination of southeast- and northwest-oriented horizontal sections, while Pad 2 had
only northwest wells. The color code
represents measured depth. Figure 3
shows 2-D and 3-D views of Pad 1 well
trajectories developed for the 8¾-inch
curve section with planned BURs between
8 and 10 degrees/100 feet and horizontal
sections in the Upper Devonian
(Rhinestreet and Burkett shales) as well as
the Middle Devonian (Marcellus). BURs
were achieved up to 16 degrees/100 feet.
The length of the 8¾-inch section ranged
from 4,400 to 14,700 feet. The color
code represents dogleg severity (DLS).
Optimizing the horizontal spacing between wells in the lease area makes it possible to develop two formations from the
same surface location. The horizontal
spacing was roughly 740 feet for all the
wells at the same TVD, and the two Upper Devonian wells (1J and 1I) were
planned between the six Middle Devonian wells (1A, 1B, 1C, 1D, 1E and 1F) for
better reservoir drainage.
The multidisciplinary approach not
only defined geological challenges for
reservoir navigation, but also allowed the
team to deliver action plans designed to
implement adjusted reservoir navigation
techniques. For example, geosteering was
expected to face an updip formation in the
Upper Devonian that required dedicated
attention, based on previous Burkett Shale
experience in adjacent areas.
In the Middle Devonian, bed dip undulations were expected to cause oversteering in offset wells, creating a challenge to
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