American Oil and Gas Reporter - January 2020 - 52

Unconventional Resource Science
SRV is usually estimated from microseismic mapping. It is a rough estimate
of the volume of rock that is hydraulically
fractured and sometimes is defined as
the product of gross stimulated area and
pay zone thickness. This estimate typically
is made by inferring the size of the microseismic cloud that is recorded during
stimulation. Propped SRV, or effective
propped volume (EPV), is a fraction of
the total SRV that is supported by proppant
and capable of flowing during depletion.
From a production perspective, the surface
area contact of the fractional propped
SRV is more important than the gross
SRV estimate. Diagnostic tools to estimate
propped SRV are critical to optimizing
completion design and will be invaluable
in the future of shale development.
A study conducted by Crimson Exploration Inc., a wholly owned subsidiary
of Contango Oil & Gas Co., involved
pumping multiple, unique chemical tracers
into a single Wolfcamp B fracture stage.
The goal of the tracer test was to shed
light on the flowback characteristics of
individually tagged fluid and sand segments by adding another layer of granularity to a typical tracer flowback report.
Chemical tracer data has been applied
extensively to offer stage-level insights

into load recovery and hydrocarbon contribution, but this dataset provides new
insights by looking at individual fluid
segment data within a single frac stage.
This added intra-stage level of detail
can provide insights into fracture behavior
when stimulating shale reservoirs by
looking at individual fluid segment tracer
recoveries. This dataset may aid in identifying fluid segments placed outside of
the propped SRV and interpreting fracture
complexity.
A total of 12 water-phase tracers and
12 oil-phase tracers were injected sequentially from pad to flush within a
single heel stage. After pumping the pad
stage, unique tracers were used to tag the
proppant-laden fluid from the 0.2 pounds
of proppant added per gallon of fluid
(ppa) of 100-mesh sand stage to the 2.0
ppa of 40/70-mesh sand stage before
going to flush. The flush volume was not
traced. Upon flowback, fluids were analyzed for the concentration of each tracer
within the produced fluid samples.
Frac Stage Characterization
The first goal of the study was to determine whether any traced fluid would
be placed within the "unpropped" SRV.
The second goal was to determine the

order of load fluid returns to verify the
"first-in, last-out" phenomenon and ascertain any degree of fluid mixing, which
could be an indication of increased fracture complexity.
The results illustrate the average tracer
concentrations and arrival times of each
traced fluid segment, which then was
used to characterize the fracture stage.
All tracers were detected in the produced
fluid samples, indicating that no traced
segment was placed outside of the propped
fracture network. The results also indicate
significant tracer mixing within the fracture
network, a potential indicator of fracture
complexity. All individually traced segments flowed back simultaneously, albeit
at varying tracer concentrations. The residence time calculation for each tracer
showed that frac fluid injected into the
later proppant segments generally flowed
back faster than the earlier segments.
A few of the questions posed before
initiating this study were:
· Do certain fluid segments exhibit
poor tracer recovery by being placed
within an unpropped fraction of the SRV?
· Does the order of injected frac fluid
correspond with the order at which tracer
is produced (i.e., first in, last out)?
· Can the residence time calculation

TABLE 1
Tracer Injection Layout for Heel Stage (Tracers in Blue and Green)
Stage 48
Segment #

Fluid Type

Stage Desc.

Estimated Time, mins

PPA

Frac Fluid, bbl

WPT

OPT

Numbering

1

Slickwater

Load Hole

5

100

2

15% HCL

Acid

6

24

-

-

-

3

Slickwater

Pad

12

0.0

476

WPT1001

OPT2001

48A

4

Slickwater

100 Mesh

20

5

Slickwater

100 Mesh

28

0.2

714

WPT1002

OPT2002

48B

0.4

714

WPT1003

OPT2003

48C

6

Slickwater

100 Mesh

7

Slickwater

100 Mesh

37

0.6

714

WPT1004

OPT2004

48D

45

0.8

714

WPT1005

OPT2005

8

Slickwater

48E

100 Mesh

70

1.0

3,950

WPT1006

OPT2006

48F

9

Slickwater

40/70

110

1.0

1,550

WPT1007

OPT2007

48G

10

10# Linear

40/70

115

1.2

476

WPT1008

OPT2008

48H

11

10# Linear

40/70

121

1.4

476

WPT1009

OPT2009

48I

12

10# Linear

40/70

127

1.6

476

WPT1010

OPT2010

48J

13

10# Linear

40/70

132

1.8

476

WPT1011

OPT2011

48K

14

10# Linear

40/70

138

2.0

476

WPT1012

OPT2012

48L

15

Slickwater

Flush

143

476

-

-

-

52 THE AMERICAN OIL & GAS REPORTER
American Oil and Gas Reporter - January 2020

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