American Oil and Gas Reporter - September 2017 - 74

SpecialReport: Horizontal Wellbore Construction
Optimizing well spacing is always
most challenging in new play areas because data are scarce. A case in point is
the deep, dry gas Utica/Point Pleasant
Shale in the Appalachian Basin. While
deep, dry Utica wells have demonstrated
tremendous productivity and the play has
the potential to be a game changer, it is a
relatively new resource with limited data.
CONSOL Energy drilled its first deep
Utica well in Westmoreland County, Pa.,
in late 2015 to determine the area's potential
and net asset value. In addition, the primary
objective was to economically complete
and produce the well while gaining as
much scientific knowledge as possible in
the area's previously unexplored deep
Utica trend. In addition, CONSOL developed a methodical minimal pressure drawdown plan for the well to prevent longterm productivity loss. Since then, CONSOL has drilled more successful highproductivity wells in the deep, dry gas
Utica play in both Pennsylvania and Ohio.
FIGURE 1
Utica Type Log with
Sequence Stratigraphy

74 THE AMERICAN OIL & GAS REPORTER

A practical workflow was used to estimate the optimum well spacing in CONSOL's deep Utica development area based
on various forecasts obtained from halflength, permeability and dimensionless
fracture conductivity assumptions according to hybrid or numerical models.
In addition, a sensitivity analysis was
performed on the impact of gas pricing,
capital expenditure, operating expenses,
permeability and conductivity on the optimum spacing design selection. Well
spacing must be selected based on net
present value. Production volumes can
be important to strategic development,
but the single economic parameter that
creates long-term value for shareholders
is NPV. Therefore, the analysis used
NPV to optimize well spacing.
Geological Overview

The dry gas Utica is an Ordovicianaged, overpressured unconventional reservoir that consists of three members in
two depositional sequences that make up
the Utica formation. The Lower Utica
sequence consists of the Lexington marlstone and overlying Point Pleasant organic
mudstone members. The top of the Point
Pleasant is a sequence boundary that is
overlain by the Upper Utica sequence.
Also an organic rich mudstone with minor
interbedded marls and limestones, the
Utica is unconformable and overlain by
the Reedsville formation.
Rock properties derived from a regional
deep, dry Utica earth model based on
multiple well inputs show a slightly higher
average porosity in the Utica (7.96 percent)
than in the Point Pleasant (7.44 percent).
The Utica is the thickest of the three
members, averaging 152 feet. The Point
Pleasant averages 71 feet and the Lexington 60 feet in thickness. Figure 1
shows a Utica formation type log with
sequence stratigraphy.
Another important aspect of well spacing is the area of investigation. Well
spacing potentially could be different in
each area depending on reservoir characteristics. The area of investigation in
Westmoreland County has excellent porosity, low water saturation and reservoir
pressure was expected to exceed 0.85
psi/foot. Because of timeline constraints
on the subject well, a diagnostic fracture

injection test was not pumped. However,
very high closure pressure from the surrounding area dictated completing the
well with ceramic proppants.
Flow-after-flow testing was conducted
on the well with a sequence of increasing
rates. The flowing and shut-in periods
were of equal duration (48 hours). Pressure
did not build to initial starting pressure
after each flow and buildup period. Flow
rates varied between 10 million cubic
feet a day and 25 MMcf/d. A final stabilization rate also was performed at the
end of flow-after-flow testing. Every
effort was made to maintain constant
rates for each flow period using automatic
adjustable chokes. Pressures were recorded
electronically at the wellhead continuously.
Rates also were designed to ensure unloading of fluids from the wellbore during
the test. Figure 2 shows the flow and
shut-in sequence.
Extended drawdown was run to determine the drainage volumes from the
semi-steady state pressure drawdown.
The well was produced at a constant rate
of 20 MMcf/d for 21 days. Initial surface
pressure at the start of flow testing was
9,937 psia, declining to 9,137 psia at the
end of the extended drawdown. The well
remained shut in for 28 days for buildup
before it was placed on production. The
buildup data were analyzed after identifying the flow regimes using a diagnostic
log-log plot of pressure changes and pressure derivatives versus time.
Pressure transient tests in horizontal
wells can exhibit four or more distinct
flow regimes, so accurately identifying
the flow regime is of primary importance
in determining permeability, drainage
area, fracture half-length and other reservoir parameters. For detailed analysis,
two commercial well test analytical models
were used to evaluate the data and enhance
confidence in the interpreted results.
Overall results were fairly close.
Rate Transient Analysis

The first step of finding well spacing
was analyzing the area's sole completed
well to gain a basic understanding of its
flow regime, flow capacity, half-length
and permeability. CONSOL has developed
a standard rate transient analysis (RTA)
workflow it applies to every producing

American Oil and Gas Reporter - September 2017

Table of Contents for the Digital Edition of American Oil and Gas Reporter - September 2017