American Oil and Gas Reporter - August 2016 - 69

SpecialReport: Hydraulic Fracturing Technology

Diversion Improves Completion Results
By Kumar Ramurthy,
Mark Brown,
Joe Richardson,
Neha Sahdev,
Jack Wiener
and Mariano Garcia
DENVER-Advanced horizontal
drilling and multistage completion technologies, along with state-of-the-art 3-D
seismic and 3-D well pad/well placement
design, make the multi-bench Niobrara
formation in the Denver-Julesburg Basin
one of the most economical plays in
North America.
The Wattenberg Field in the heart of
the DJ Basin is among the largest overpressured, basin-centered fields in the
Rocky Mountain region. The field's structure is dominated by a series of northeast-trending wrench faults associated
with Precambrian basement tectonics.
Deep within the section, these faults are
vertical with strike-slip motion, but split
into an increasingly complex polygonal
system of listric normal faults within the
Cretaceous section, including Niobrara
chalks and the Codell sandstone.
This structural complexity can make
Niobrara horizontal drilling quite difficult
in regard to remaining within the zone.
Precise well designs and 3-D seismic
data are significant for imaging this complex fault pattern, accurately placing horizontal wells, managing drilling costs,
and effectively producing Niobrara targets.
In addition to the horizontal drilling
challenges, Niobrara completions are not
yet optimized. Operators continue to experiment with higher stage counts and
tighter spacing, which increases costs.
Consequently, an optimization study was
conducted on a Bayswater Exploration
& Production LLC-operated pad in the
Wattenberg Field to demonstrate that
spacing can be optimized with low-cost
and environmentally friendly diversion
technology that yields equal or better
production with fewer stages, thereby
lowering costs.
The five wells drilled on the Weld
County, Co., pad-wells I, J, K, L and M-
were oriented from north (heel) to south
(toe). Four of the wells have normal
lateral lengths of ~4,300 feet, but Well
M is an extended-reach lateral of ~9,500
feet. All wells in the pad were cut by

east-to-west faulting within the Niobrara,
which created a central graben in the
middle of each of the laterals. As shown
in Figure 1, fault throws encountered
were on the order of ~50 feet. The primary
target for all five was the Niobrara "C"
chalk bench.
Wells K and L were selected for the
optimization study. The wells are located
next to each other and both were completed
using perf-and-plug multistage fracturing
methods. Well trajectories and landing
points must be accounted for when comparing production.
Figures 2A and 2B depict the Niobrara
structural cross-sections along both wells'
directional surveys. As can be seen, Well
K landed in the middle C bench and
stayed flat in the middle of the chalk
until the graben, where it faulted into the
"B" chalk. The toe-up design then moved
back into the upper C chalk before ending
up in the lower B marl. Well L also followed a toe-up design, with the heel landing in the lower C chalk, followed by
faulting into the B chalk and then back
into the B marl before ending up in the B
chalk again.
Well K was completed with 28 stages
geometrically spaced at 153 feet, while
Well L was completed with 20 stages

geometrically spaced at 215 feet. Well L
was stimulated utilizing an intrastage diversion process and pumped 404,169
fewer pounds of proppant than Well K,
which was completed without the diversion
technology.
Following stimulation and flowback,
coiled tubing-deployed fiber optics distributed temperature survey (DTS) and
distributed acoustic survey (DAS) diagnostic tools were used in both wells to
evaluate treatment effectiveness. The results show that Well L with less dense
stage spacing and intrastage diversion
had 80 percent fracture initiation, compared with 60 percent for the limitedentry Well K. The production results are
very encouraging. The 180-day cumulative
oil production for Well L is almost similar
to Well K, with only a 3 percent difference
in the normalized barrels of oil equivalent
per foot.
Stimulation Treatment
Both wells were treated with a low
gel-loading carboxymethyl hydroxypropyl
guar (CMHPG) hybrid fluid system and
used 30/50-mesh white sand as the main
proppant. Well K's 28 stages had three
perforation clusters in each stage (84
total clusters), while Well L's 20 stages

FIGURE 1
Five-Well Pad with Central Graben in Weld County, Co.
5-Well Pad

Central Graben
Faulting

AUGUST 2016 69



American Oil and Gas Reporter - August 2016

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