American Oil and Gas Reporter - September 2018 - 49

FIGURE 3A
RA Tracer Log (Stage 3 in Well B)

FIGURE 3B
Treating Plot (Stage 3 in Well B)
10.00
10.00
10.00
150.0

Hydr.Pressure (psi)
Meas'd Btmh Press (psi)
Treating Pressure (psi)

2,000
13,000
11,000

6,000
9,000
7,000

4.00
4.00
4.00
60.0

8,000
7,000
5,000

2.00
2.00
2.00
30.0

10,000
5,000
3,000

0.00
0.00
0.00
0.0

2,000
13,000
11,000

06

/2
21 3/16
:3
0

06

/2
21 3/16
:0
5

06

06

/2
20 3/16
:1
5

06

/2
21 3/16
:5
5

6.00
6.00
6.00
90.0

/2
20 3/16
:4
0

4,000
11,000
9,000

/2
19 3/16
:5
0

8.00
8.00
8.00
120.0

FIGURE 4
Frac Fluid Allocation Based on Post-Frac DTS Warm-Back Analysis
(Middle Bakken Well)
238
Shut-In

Stage 13

Stage 12

Stage 11

Stage 10

Stage 09

Stage 08

Stage 07

Stage 06 Stage 05

Stage 04 Stage 03

600
300
400

1,300

1,400

1,400

1,300

1,400

1,100

1,100

1,400

1,300

1,300

1,500

Original Geothermal Temperature

1,500

236

1,700

237

Production Results

2.7

2.9

2.9

1,700

1,700

1,700

2.0

2.5

2.3

2.3

2.7

2.7

2.7

1.9

2.0

2.9

2.5

2.9

1.6

2.2

2.3

2.0

2.0

1.7

1.7

2.3

1.8

2.0

2.05

234

2.4

235
Temperature (F)

To date, production results for Wells
A, B and C have exceeded pre-drill expectations. Well A is exceeding expectations by 9 percent and outperforming the
next-best offset well in similar geologic
properties and structure by a 1.7 multiple
based on 180-day cumulative oil production per foot of lateral. Well B is exceeding
expectations by 13 percent and outpro-

Btm Prop Conc (ppg)
Inline 1 Con (ppg)
Screw Conc (ppg)
Slurry Rate (bpm)

06

friction was 1,400 psi. The 800-psi drop
in perforating friction may be attributable
to eroding perforation diameters, but is
more likely from the leaking plug exposing
clusters from the stage below.
Post-frac fiber optic diagnostics were
performed in mid-2017 in two wells, one
in the Middle Bakken and the other in
the Three Forks (not the A, B or C wells).
A composite carbon rod with fiber optic
strands was deployed to log both distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) data during producing and shut-in conditions. A
warm-back analysis was performed using
DTS data to analyze frac fluid distribution
within each stage, and the analysis demonstrated consistent fluid distribution as
binned by thirds within each stage.
Figure 4 shows the results from the
Middle Bakken well. It had either 12 or
15 clusters per stage, with each intrastage
bin containing four or five clusters. The
same proppant volume was pumped in
each stage, so the stages with 12 clusters
had 25 percent more proppant per cluster.
Production log analysis was performed
after the shut-in period required for the
warm-back, and a DAS ranking system
was implemented as a constraint into the
temperature model to converge on a more
probable solution, mitigating uncertainty
in interpreting DTS results in a horizontal
wellbore. Higher-frequency noise was
aggregated over time, creating a qualitative
production allocation for each cluster.
DAS obtained with DTS provides a unique
description of the wellbore flow profile.
The production log analysis in Figure
5 is for Stage 10 in the same Middle
Bakken well shown in Figure 4. The twowell average for producing cluster efficiency was 80 percent for the 20 stages
logged and analyzed. The data indicate
that 14 of 15 clusters were producing in
this stage for a single stage producing
PCE of 93 percent.

bbl/ft/cluster

233
232
231

Shut-in Temperature

230
229
10,000

10,500

11,000

11,500

12,000
Depth (ft)

12,500

13,000

13,500

14,000

SEPTEMBER 2018 49
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