American Oil and Gas Reporter - September 2018 - 52

SpecialReport: Horizontal Wellbore Construction

Project Demonstrates DCTD's Beneﬁts
By Peter Hatgelakas,
Toni Miszewski
and Adam Miszewski
PITTSBURGH, PA.-An underbalanced
directional coiled tubing drilling (DCTD)
project in the Appalachian Basin demonstrates the potential for using CTD technology to realize the economic potential
of marginal oil wells in shallow conventional plays.
The objective was to drill a lateral
sidetrack to access target zones identified
adjacent to a recently drilled vertical dry
hole. The target thickness was 15 feet,
making accurate depth control critical. It
also was considered essential to drill the
entire reservoir underbalanced using nitrified fluids to minimize formation damage. The offset wells surrounding the
sidetrack location produce 10-100 barrels
of oil a day with up to 80 percent water
cuts. Given the typical low daily production
rates in the field, the challenge was to
deliver a productive horizontal sidetrack
in a cost-efficient manner.
There are two ways to alter the economics of a well: reduce costs or increase production. For an individual
marginal well with a low production,
there comes a point below which costs
cannot be reduced sufficiently to make
a material difference to the economics.
Therefore, the focus of this project was
on applying a specialized DCTD bottom-hole assembly and engineering
software package as the enabling technologies to increase production while
containing the drilling costs to make
the extra production more profitable.

Drilling efficiency often is measured
in terms of cost per foot, and while this
is an important measure, the target of
this DCTD project was to define drilling
efficiency in terms of cost per production
rate. This measure takes the initial production into account, and in the process,
ties together the ability of the driller to
make hole in the direction required with
the ability of the geologist and reservoir
engineer to select a productive part of
the formation.
Recognizing that each stage of well
construction can affect another, a multidisciplinary approach was adopted to include inputs from geology, geophysics,
reservoir engineering, drilling and completions engineering. Local experience
with offset wells also was an important
input, allowing for the fact that all offsets
were vertical wells drilled with air or in
an overbalanced condition.
The overall objective was to increase
cash flow from the well by accessing
more of the reservoir using a horizontal
wellbore. A horizontal trajectory also
allows for natural fractures to be easily
intercepted for increased production. Ultimately, successful horizontal wells
could reduce the total number of wells
that need to be drilled to fully exploit
the reservoir. Potentially, one horizontal
well with a second lateral branch could
replace four wells with an associated
cost reduction.
Drilling horizontally in an underbalanced condition using nitrified fluids to
avoid formation damage required more
sophisticated equipment than what is used
traditionally on shallow low-volume wells,

FIGURE 1
Original Processed versus Reprocessed 3-D Data
Before Processing

After Processing

Trenton top
Trenton top

0.60

0.40
Knox top

Knox top

Rome top

p top

52 THE AMERICAN OIL & GAS REPORTER

0.60

Travel TIme (seconds)

0.40

but at the same time, the extra capability
was required to realize the reservoir's
potential. The field is sufficiently depleted
for the wells not to produce to surface
and the reservoir has low permeability,
making it susceptible to damage from
drilling fines being forced into the formation. Underbalanced drilling also typically increases the rate of penetration to
shorten the required drilling time.
Planning Process
As noted, the DCTD project was
conducted in a field with numerous vertical offset wells and a good understanding of the local geology. Vertical
well depths in the field typically do not
exceed 2,500 feet. Four vertical wells
had been drilled by Chuck Henry Energy
LLC and its partner, Hocking Hills Energy, in the immediate vicinity in the
previous year, three of which were on
production yielding rates of 10-25 bbl/d
with varying levels of associated water.
Although the fourth well had shown
production promise based on electric
logs, it turned out to be dry. Consequently, a planned 41⁄2-inch production
casing string was not run in the well
and it had not been completed.
Any of the wells could have been chosen as a candidate for DCTD, but after
analyzing the different options, the uncased
well was chosen because a value analysis
indicated that it had the shortest payback
period if it could produce at a similar
rate to neighboring wells. The sidetrack
was planned to access a different volume
of the reservoir than the vertical borehole, and the fact that the vertical well
had not been completed had the added
benefit of avoiding losing existing production to drill the sidetrack.
The development strategy for this field
was based on the results of a 3-D seismic
data acquisition and analysis program.
In an effort to get full value from the
available 3-D seismic, the data was reprocessed, and significant differences
were found as a result of geometry errors,
unresolved surface and weathering velocity
issues, and other velocity choices that
impacted the quality of the representation
of subsurface structures. Reprocessing
the 3-D data was instrumental in identifying previously hidden faults and the
right target zones (Figure 1).
The reprocessed 3-D seismic survey

American Oil and Gas Reporter - September 2018

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