American Oil and Gas Reporter - December 2015 - 65

page 65-73_Layout 1 12/2/2015 11:31 AM Page 65

SpecialReport: Well Stimulation & Completion Technology

Downspacing Has Huge EUR Impacts
By Paolo Grossi,
Devery Neumann
and Farshad Lalehrokh

THE WOODLANDS, TX.-With low
expected recoveries and an ultimate technically recoverable resource estimated at
4.2 billion barrels of oil of 17 trillion
cubic feet of natural gas, operators in the
Eagle Ford Shale are utilizing innovative
development strategies to enhance overall
recovery factors and well performance.
Optimizing estimated ultimate recoveries
would have dramatic and profound impacts; a conservative recovery increase
of 5 percent would yield an additional
200 million barrels of oil and 1 Tcf of
gas.
As part of a systematic approach to
implementing optimized recovery methods
using multizone staggered ("chevron" pattern) lateral downspacing within its Eagle
Ford development area, Talisman Energy,
a part of Repsol, examined the effectiveness
of current hydraulic fracturing techniques
in regard to reservoir drainage limits, expected field EURs, and the implications
of staggered downspacing.
The project analyzed numerous
datasets, including public production data,
published analogue data, decline curve
analyses, reservoir modeling, wireline
logs, buried-array microseismic, and geochemical data. The study culminated in
testing multizone staggered downspacing
in six horizontal wells on two pads. The
success of the field testing is expected to

have a significant impact on future leasehold drilling inventories and subsequent
asset values, with potential field recoveries
increasing by four to seven times above
current field averages.
Fundamentally, increasing the percentage of total hydrocarbons recovered
from a given field or rock volume is tied
to inherent geological parameters, but
also to the technological capabilities of
the recovery method. In ultralow-permeability unconventional reservoirs, recovery
is largely dependent on the technical limitations and economics associated with
hydraulic fracturing. This is assumed to
hold true within different plays, and even
more so, within specific fields or development areas where reservoir properties
are similar. In other words, ultimate recovery is limited more by the recovery
method (i.e., hydraulic fracturing) than
the rock.
Operator-published EURs were reviewed along with internal metrics to
create an Eagle Ford dataset. The data
were compared to hydrocarbon in-place
(HCIP) mapping of the Eagle Ford and
Austin Chalk, and the two parameters
were used to compute a recovery factor
(RF) assuming a fixed area for in-place
volumetrics. The computed RF was
grouped by main phase (oil or gas, assuming a gas-to-oil ratio cutoff) and inplace volumetrics arranged in ascending
order.
As shown in Figure 1, RFs decrease
with increasing volumetrics in both oil

FIGURE 1
Relationship Between EUR, Volumetrics (HCIP)
And RF for Eagle Ford Shale

and gas cases (Talisman's development
area is indicated by red star). Assuming
a linear relationship between in-place
volumetrics and reservoir height, it is interpreted that hydraulic fractures reach
or nearly reach their full effective extent
in low-volumetric areas (limited reservoir
height), resulting in high calculated RFs.
Conversely, if the same fracture extent is
reached in high-volumetric areas, a larger
volume will be understimulated, resulting
in lower computed RFs. This suggests
that the assumption of a dynamic recovery
factor is fundamentally related to fracture
geometry, stimulation effectiveness, and
reservoir (net pay) height.

Multizone Vertical Downspacing
The opportunity to increase recoveries
is fueling the search for "stranded" resources as operators look to test multizone
vertical downspacing throughout the Eagle
Ford trend. The focus is on areas with
large in-place volumes achieved by thick
sections containing Lower Eagle Ford,
Upper Eagle Ford and Austin Chalk.
Within Talisman Energy's operated
area, the highest volumetrics are found
in the Lower Eagle Ford section, with
overall reservoir thickness ranging from
200 to 230 feet and average field recoveries
typically less than 15 percent. It was
within this area that the initial staggered
downspacing tests were implemented.
Reservoir HCIP, specifically reservoir
height, and EUR were related through
rate transient analysis (RTA). The contributing reservoir volume related to the
productivity index was computed and
kept constant by manipulating reservoir
height (h), fracture half length (xf) and
matrix permeability (km). This allowed
sensitivities to be conducted given three
potential drainage scenarios within a one
square-mile development area; assuming
a 200-, 100- and 75-foot effective reservoir
pay height, as shown in Figure 2. Given
these assumptions, type curve expectations
(black line) could be achieved by accessing:
* 200 feet of reservoir height with
an xf of 125 feet (blue line);
* 100 feet of reservoir height with
an xf of 168 feet (red line); or
* 75 feet of reservoir height with an
xf of 190 feet (green line).
The results are profound, suggesting
that long-held spacing assumptions of
DECEMBER 2015 65



American Oil and Gas Reporter - December 2015

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