American Oil and Gas Reporter - November 2015 - 103

SpecialReport: Marcellus/Utica Activity

Completion Design
Before the staging exercise, some requirements had to be defined, and cluster
locations and groupings had to stay within
certain constraints. First, no section of
the wellbore was to be left unstimulated.
Other studies suggested not completing
parts of the lateral that were not in good
reservoir-quality rock. However, the tools
used to derive this reservoir quality criterion only investigated a few feet into
the reservoir. Hydraulic fractures are expected to extend several hundred feet,
and therefore are capable of contacting
high-quality rock even when only lowquality rock is evident at the wellbore.
Second, all clusters were to be spaced

FIGURE 2
Closure Stress (Red and Blue) from Sonic Data
And Fracture Density (Green) from Image Log

Log
Depth (ft)
5,000 -

Log
Depth (ft)
- 5,000

5,100 -

- 5,100

5,200 -

- 5,200

5,300 -

- 5,300

5,400 -

- 5,400

5,500 -

- 5,500
- 5,600

5,600 -
5,700 -

Marcellus

- 5,700
- 5,800

5,800 -

- 5,900

5,900 -
6,000 -

Cherry Valley

- 6,000
- 6,100

6,200 -
6,300 -
6,400 -

On
Tra ond
ns aga
itio
n

6,100 -

On
Tra ond
ns aga
itio
n

properties, primarily associated with Marcellus facies variations. The image log
data clearly identified more than 200 natural
fractures along the logged portion of the
wellbore. All fractures were in a northeast-to-southwest orientation and were distributed throughout the wellbore. Although
some parts were more heavily fractured
than others, all stratigraphic intervals and
facies included a number of fractures.
Figure 1 is a section of the dual oilbased mud imaging interpretation showing
natural fractures in light blue and bedding
planes as green sinusoids. Figure 2 shows
the closure stress interpretation (red and
blue) derived from the sonic data, along
with fracture density (green) from the
image log. Combined, the interpreted
wireline log data allowed stage boundaries
in the A1 well to be identified based on a
number of rock properties.
For B1, a three-step process was used
to project the vertical logs onto the
geosteered horizontal lateral. First, geosteering data were used to give the entire borehole a value in relation to the target line
within the vertical reference well. The
second step was to find the values that
corresponded to the value above and
below the target line that the borehole
encountered. Finally, the value of the
other log was associated with each point.
Some assumptions were made during
this process of creating the extrapolated
log. To check on lateral homogeneity,
thickness variations and vertical logs, the
A1 well's stress log was estimated and
compared with the measured log to verify
the methodology (Figure 3). The extrapolated stress log on A1 showed that the
methodology produced a smoothed, but
useful log for determining completion
zones.

- 6,200
- 6,300
- 6,400

FIGURE 3
Actual versus Projected Logs

around 40 feet. Tighter spacing implies a
higher cost, but larger spacing was not
recommended since boundary-dominated-flow was not observed after a long
period in offset wells. Also, the number
of clusters per stage was not to exceed
eight to eliminate any potential fluid diversion issues. In addition, for economic
reasons, the number of clusters per stage
was limited to no fewer than four.
In order of importance, the three parameters used for the staging exercise
were closure stress, natural fracture frequency, and petrophysical properties. After
populating these parameters along the lateral, each property was used independently
to define intervals of similar rock. These
intervals were reconciled and defined as
to how the well should be broken down.
Further slicing depended only on the predefined staging requirements.

Figure 4 shows the boundaries obtained
between zones of similar properties using
each parameter for well A1. It is common
to see similar defined boundaries from
multiple parameters. These can be associated with a change of petrophysical
properties resulting from a different landing horizon.
Final Staging

There were a total of 16 engineered
stages in the A1 well, ranging from five
to eight clusters per stage spaced at 40
feet, with 103 total clusters for the lateral.
Table 1 summarizes the stage average of
each parameter normalized to the maximum stage average (where 1.0 is the
highest value). As noted, the wellbore
crossed rock intervals of varying quality
in terms of gas-filled porosity, clay volume
and total organic content.
NOVEMBER 2015 103



American Oil and Gas Reporter - November 2015

Table of Contents for the Digital Edition of American Oil and Gas Reporter - November 2015

Contents
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