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Multispinner, Multiprobe Production Logging Tool is Key to
Water Shutoff Success
For years the West Coast Region
has worked to relay technology insights about controlling
water production since excess water production is a
prevalent problem in California reservoirs. In this vein,
readers are directed to a recent article published in The
American Oil & Gas Reporter ("Technology Key to Workover
Success,” Jan. 2008, pp. 160-167). The article describes how
Venoco put new production logging technology to good use in
the South Ellwood Field.
Production at South Ellwood is
from the naturally-fractured Monterey formation. Over time,
the oil/water contact has risen, causing increasing water
production. Water shutoff work has had mixed results. Most
wells in the field are highly deviated with numerous
perforated intervals and produce by gas lift. Four wells
were identified as good candidates for water shutoff because
of their high water cuts and productivity indexes. Goal was
to shut off water zones and increase drawdown on the
remaining oil-producing perforations. Previous workovers had
shown variable results using older-generation (single
spinner) production logging technology.
The new production logging tool
that Venoco employed has multiple (5) spinners and probes
(6), distributed vertically in the casing. Each probe
consists of an optical and electric probe with the optical
probe distinguishing between gas and liquid, and the
electrical probe distinguishing oil and water.
Particularly in deviated or
horizontal wells, the multiple spinner/multiple probe
capability provides a “picture” of what is flowing/where it
is flowing that is just not possible with older-generation
tools. Three of the four wells were logged with the new
tool. The fourth well had tubing
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problems and could not be logged.
Experience in two of the wells is described below.
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Well 9-1: Production prior
to logging was 20 Bopd/940 Bwpd (98% water cut), plus
630 Mcfd from 10 perforated zones within a 1,260-ft
interval. A single spinner production logging tool run
in 2001 indicated that 76% of the water and no oil came
from the bottom zones. In 2002 a plug was set to isolate
these zones; water production decreased by 50% but oil
production also decreased 30%. The plug had been removed
to regain the oil production, but the need for water
shutoff remained. Final analysis of data with the new
tool revealed seven water entries, four oil entries and
six gas entries. Coupling results with the 3-D
geological model, it was evident that by far the largest
water entry correlated with a major fault intersection
with the fault plane penetrating the water contact in
the reservoir. Any perfs that could communicate with the
fault zone were cement squeezed, then oil-producing
zones were reperfed. Oil increased from 20 to 400 Bopd
and water decreased from 940 to 200 Bwpd and a year
after reperfing the well was still making 230 Bopd.
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Well 16: Production prior
to logging was 225 Bopd/1,890 Bwpd (89% water cut), plus 815
Mcfd from nine perforated zones within a 1,415-ft interval.
Analysis of data from the new tool indicated the lower four
intervals were contributing 50% of the water, 2% of the oil
and 20% of the gas. Coupling results with the 3-D geological
model, it was clear once again that water entry was related
to the wellbore intersecting a fault. A bridge plug was set
to isolate the lower water-bearing zones and an electrical
submersible pump (ESP) with downhole
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California Well Represented
in Awards Within RPSEA Unconventional Resources
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A
Self-Teaching Expert System for the Analysis, Design and
Prediction of Gas Production from Shales (Lawrence
Berkeley National Laboratory)
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Petrophysical
Studies of Unconventional Gas Reservoirs Using
High-Resolution Rock Imaging (Lawrence Berkeley National
Laboratory)
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Gas Condensate
Productivity in Tight Gas Sands (Stanford University)
See page 7 of this newsletter for
full listing of RPSEA awards. |
West
Coast
Region