American Oil and Gas Reporter - August 2016 - 71

SpecialReport: Hydraulic Fracturing Technology
shut in to clearly identify frac initiation
points. The time difference between the
beginning and end of shut in was
approximately five hours.
Figure 5 provides a detailed summary
of this cluster efficiency analysis across
the entire lateral for both wells. DTS
warm-back data during shut in clearly
identified fracture initiation points across
the two laterals. A 100 percent cluster
efficiency would imply that all perforation
clusters in the stage resulted in fracture

utilized to evaluate the cluster efficiency
in the wells by identifying fracture initiation points.
Figure 4 shows the results from DTS
warm-back data during shut in, identifying
the fracture initiation points across stages
1 and 2 in Well L at two different time
intervals. Although the figure shows only
stages 1 and 2, the same analysis was
performed across all stages. Basically,
the warm-back data were checked for
consistency at the beginning and end of

FIGURE 4
DTS Data Showing Cooler Frac Initiation Points in Stages 1 and 2
At Different Time Intervals
11,200
11,220
11,240
11,260
11,280
11,300
11,320

Measured Depth

11,340
11,360
11,380
11,400
11,420
11,440
11,460
11,480
11,500
11,520
11,540
11,560
11,580
11,600
222.0

222.5

223.0

223.5

224.0

224.5

225.0

225.5

226.0

226.5

Temperature

FIGURE 5
Cluster Efficiency Analysis Across All Stages in Wells K and L
(with Shut-In DTS Data)
100

L: 64 frac initiation points out of 80 perf clusters

90
80
70
60
50
40
30
20
10
0
20

Stage Count

Study Results
Both wells K and L were flowed for
~25 days after stimulating, along with
the other wells on the pad. The two wells
were then shut in for eight and five days,
respectively, prior to running the CT-deployed fiber optics tools (the difference
in shut-in times was related to weather)
to validate the effectiveness of the stimulation treatments. DTS was successfully

100.0

Percentage

nostics can be combined with regular CT
interventions such as mill-outs, cleanouts and acid treatments. CT deployment
also provides an alternative to wireline
deployment in deviated/horizontal laterals,
and the rigidity of the coiled tubing provides protection to the fiber optic cable.
The technology also can also be used
to evaluate acid treatments, observe interwell communication during treatment,
detect leaks, and log well production.
Memory mode pressure and temperature
point gauges also can be run as a part of
the coiled tubing BHA to gain a better
understanding of flowing pressure.
Whether deployed on CT or permanently installed in a wellbore, fiber optics
provides a unique method of surveying
the entire wellbore at the same time.
Temperature, acoustics and strain information can be inferred by analyzing
backscattered light from the fiber glass.
The intensity of the Raman component
of the anti-Stokes band is temperaturedependent, while the Stokes band is not
temperature-dependent. The ratio of the
two bands is used to accurately derive
the temperature of fiber at a particular
location, enabling DTS measurements
along the length of the fiber.
The DAS system utilizes Rayleigh
backscattering in a single mode fiber to
detect minute strain caused in the fiber
by external disturbances. In essence, the
entire length of fiber is turned into distributed microphones along its entire
length.
During hydraulic fracturing treatments,
near-wellbore fracture initiation points
can be identified over an extended period
by cooler temperatures (injected fracturing
fluid is typically colder than the formation).
The initial warm-back of these initiation
points are high, but as the delta temperature
(the temperature between the reservoir
and fracture initiation point) decreases,
the warm-back rate also decreases. Therefore, distributed fiber optics sensing techniques can identify fracture initiation
points post-treatment.

90.0

K: 51 frac initiation points out of 84 perf clusters

80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
20

AUGUST 2016 71

American Oil and Gas Reporter - August 2016

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