American Oil and Gas Reporter - January 2016 - 58

Unconventional Resource Science
FIGURE 6
Individual Hydraulic Fracture Stage Pressure Pumping Profiles
For Modern Marble Falls Wells in Relation to Natural LBF Orientations
5,000

100
8

3,750

75
6

2,500

50
4

1,250

25
2

0
0

0

0

10

20

30

40

50

60

70

80

90

100

5,000

100
8

3,750

75
6

2,500

50
4

1,250

25
2

0
0

0

0

10

Pump Rate (bpm)

20

30

40

50

Treating Pressure (psi)

underlying Ellenberger Group, differential
compaction over karst features or Mississippian pinnacle reefs, and natural hydraulic fracturing associated with gas
generation in the Barnett.
Understanding Well Performance
There is a strong empirical correlation
between the dominant natural fracture orientations, well stimulation characteristics,
and ultimate well performance. In the majority of wells where relevant data are available, the Marble Falls contains LBF that
are oriented dominantly north-northwest
or north-south, at relatively high angles to
sHmax . These wells tend to yield better
hydrocarbon production and stimulation
treatments are generally characterized by
increasing pressures, lower average pumping rates, and an inability to place all of the
58 THE AMERICAN OIL & GAS REPORTER

60

Proppant Concentration (psa)

designed proppant volume (top panel in
Figure 6).
In a minority of wells, the Marble Falls
contains LBF that are predominantly at low
angles to sHmax. These wells tend to be
less productive, and stimulations are characterized by decreasing treating pressures, increased pumping rates, and successful placement of designed proppant
volumes without adjusting pump schedules
(bottom panel in Figure 6).
These results can be explained by the
significant impacts natural fractures have
on hydraulic fracturing and well production. Where the angle between natural
fractures and sHmax is high, more hydraulic fractures are induced, which in
turn, intersect a greater number of natural fractures, creating a complex and interconnected permeability pathway to

the wellbore. Higher tortuosity associated with a complex fracture network can
resist proppant placement and require
ever-increasing pumping pressures, which
may require altering pump schedules and
culminate in the inability to place designed
proppant volumes.
Although it may seem counterintuitive,
this scenario allows for more effective Marble Falls completions, leads to better
overall well performance, and increases the
probability that wells initially will flow
without the need for artificial lift, thus reducing operating costs. Ultimately, because
of reservoir pressure and gas drive, we also
attribute artesian behavior in Marble Falls
wells to greater reservoir contact and enhanced conductivity in more complex
fractures networks. Propped conductivity
is inferred to be maintained in induced and
natural fractures even with comparatively low proppant concentrations because of
the formation's low closure stress.
Where the angle between natural fractures and induced fractures is low, stimulation tends to be less effective because the
hydraulically induced stresses on the formation are more likely to be resolved by
propagating pre-existing fractures rather
than initiating new ones. Therefore, fewer hydraulic fractures are induced with less
fracture network complexity. Also, natural fractures at low angles to sHmax experience greater dilation and can accommodate high proppant volumes, requiring lower treating pressures. Ironically, this means
that Marble Falls wells that treat as designed can be predicted to be less productive.
New Type Of Reservoir
Without intimate knowledge of formation characteristics, the Marble Falls
might be classified as a Type I fractured
reservoir in which fractures provide the essential primary storage capacity and permeability with minimal contribution from
the matrix. Such reservoirs are characterized by high initial production rates and
rapid subsequent production declines,
early infiltration of water, and require few
wells to deplete because of large per-well
drainage areas.
However, the Mable Falls does not exhibit Type I characteristics, despite the fact
that fractures appear to dominate the
porosity and permeability system. In
sharp contrast to Type I reservoirs such
as the Austin Chalk (Pearsall Field),
American Oil and Gas Reporter - January 2016

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