technologies, including water hammer tools or lubricants – pumping
fluids into the wellbore could have affected well production and hence
would not provide a noninvasive production survey.
As predicted by the tubing force analysis, the coiled tubing friction
locked about 139 m short of the target depth. The DTS survey was
conducted despite not making it to the toe of the well, only two frack
ports were below the DTS string. Flow from ports one, two, and three
would be considered ‘from below’ and not be evaluated in the survey.
DTSsurveyoperationsummary–36hoursstart tofinish
Ì
Day 1
23:20: Shut in well, run in hole with coiled tubing.
Ì
Day 2
03:50: Coil frictioned out at 3450 mKB (target depth was 3589
m), Begin DTS survey.
Ì
07:00 Start producing well.
16:10: Shut in well (14 hour warm back survey begins).
Ì
Day 3
06:10: DTS survey complete, pull out of hole.
12:30: Job complete, well put back on production.
The flow rate during the DTS survey varied from140 - 195 e
3
m/d.
during the production portion of the DTS survey as displayed in Figure 5.
Rawdata
The rawDTS data shown on the right side of Figure 6 reveals some
interesting trends. It was clear that some frack intervals were producing
considerablymore than the others. Like other wells that have been
production profiled with DTS, the well did not have homogenous
production along the lateral.
Dataprocessing
The DTS data was processed using PLATO software. The software
utilises a thermal mass flowmodel to evaluate production
based on temperature changes resulting from the JT effect while
flowing the well. Plato model inputs include total well production,
reservoir temperature, fluid properties, and the thermal and
physical properties of the tubulars present in the well.
Productionprofile
The production profile calculated by PLATO (Figures 7 and 8)
showed that the top 11 of the 26 zones produced nearly 70% of
the well’s production. Five zones; Stage 24, 23, 21, 17, and 16
produced nearly 50% of the well’s net production as shown in
Table 2.
Conclusions
Fibre-optic cable deployed inside coiled tubing can be used as
a sensor for distributed temperature sensing when deployed
temporarily into a wellbore. Distributed temperature sensing can
be used to determine the production profile of a horizontal well.
On this particular well, nearly 50%of the production came from
five of the 26 frack stages. The upper 11 frack stages accounted for
nearly 70%of the well’s production despite little expected reservoir
heterogeneity or changes to fracture design.
The packer between stages 22 and 21 appears to be the site
of much of the production from these intervals. The production
within stage 17 appears to be skewed towards stage 16.
There are no clear correlation between expected reservoir
quality indicators and production results. DTS is cost-effective; a
typical survey costs about the same as a PL survey.
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