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Case Histories
The first of these systems was installed for
Petro-Canada Oil & Gas at their Bellshill Lake field in east
central Alberta in April 1997. This field was predominately equipped
with 228 jacks, ¾" rod strings, and 2" bore insert
pumps. All parts of the production system were at there maximum
operational limits but many of the wells still carried high fluid
levels. Water handling costs were only $0.11/m3 but infrastructure
was approaching capacity limits. Various other methods of downhole
water control had been investigated but discarded as either too
costly or not technically feasible for that area.
A candidate well selection process was gone through similar to
the one presented above. The primary objective was to maximize
incremental oil production without upgrading jack and rods.
The well chosen had been drilled in 1994 and completed in the
Basal Quartz as an oil producer, perforated from 983.0-987.5 m.
The zone was 40 m thick with a shale stringer at 995 m. The well
was making 4.6 m3/day of oil, and 74.7 m3/day of water with a
2" pump and 228 jack stroking at a 100" stroke and 11.5
SPM. Fluid properties were 28 °API oil with a GOR of 0.06
m3/m3, trace sand, 7.9% CO2, and 0.6% H2S. Disposal zone had a
static reservoir pressure of 4760 kPa and an average injectivity
index of 0.31 m3/day/kPa. Target production was 8.1 m3/day of
oil and 15.4 m3/day of water.
The Basal Quartz was perforated from 1009-1023 m for disposal
and the well was equipped with a 1-1/2" x 2-3/4" DPGS
system. After working through some initial operational and spacing
problems the jack was started up at 7.5 SPM. Initial test results
were 6.1 m3/day of oil and 9.7 m3/day of water. Over the following
months oil rates declined to 4.2 m3/day while water rates to surface
increased slightly to 14.0 m3/day. After eight months of operation
the DPGS system was pulled and replaced with a high volume ESP.
The Bellshill Lake field was subsequently sold to Archean Energy.
Teardown of the DPGS revealed that the bottom pump's pressure
activated "rag" plunger had experienced unexpected scaling
in the 100% water environment. This resulted in a low pump efficiency
and reduced total fluid production into the wellbore. The system
was never optimized because of concerns of oil carry over precipitated
by the lower than expected oil cuts to surface. It is worthwhile
noting that had the unit been started at 11.5 SPM, oil production
would have doubled.
Two recent installations were performed by Renaissance Energy
in late 1998. One was in the Webb South field in southwest Saskatchewan.
The well was completed in the Roseray at 1150 m in October 1997.
The well was producing on PC pump at 8 m3/day oil and 70 m3/day
but was shut-in on and off due to the economics of handling the
90% watercut fluid.
Fluid properties were 15 °API oil with 1% sand. Disposal zone
was perforated also in the Roseray from 1176-1179m with no impermeable
layer between production and disposal perforations. Disposal zone
was tested with an injectivity index of 0.07 m3/day/kPa. With
the DPGS system installed the well came back on line at 5.9 m3/day
and 11.0 m3/day oil. As the well was drawn down, sand rates increased
and the intakes to the small bore top insert pump were quickly
plugged. Alternate designs for handling the heavy sand laden fluid
were proposed but have not yet been implemented.
Another Renaissance well was completed in the Provost field. This
well had been completed in the Dina sand at 786 m in August 1993.
The well had been shut-in since July 1994. The 95% water cut fluid
was too expensive to truck from the single well battery. The well
had been producing at 2 m3/day oil and 40 m3/day water.
Fluid properties were 23° API oil with a GOR of 11 m3/m3,
trace sand, 1.5% H2S, 5% CO2, and 50,000 ppm chlorides. Disposal
zone was perforated in the Dina from 816-817 m and 820-824 m,
with an impermeable barrier at 809 m. The disposal zone was tested
with an injectivity index of 0.25 m3/day/kPa and static reservoir
pressure of 5600 kPa. The well was put on conventional production
for a few weeks to reestablish IPR's and water cuts which came
in at 85%. Target production for the DPGS system was 3.3 m3/day
oil and 8.6 m3/day water.
An 1-1/2" x 2-3/4" system was installed and the well
came on at 2.9 m3/day oil and 9.5 m3/day water. Within a month
of operation however, the disposal zone tightened up to an injectivity
index of 0.01 m3/day/kPa and parted a connection in the pump.
Although there was no sand in the pump, the disposal zone swabbed
at 5% sand cut fluid. The zone was swabbed down to less than 1%
cut and tested back at the original injectivity levels.
During the first month of production water cuts had risen to 95%
so a smaller 1-1/4" x 2-3/4" system was re-installed
into the well. At the time of writing this Provost well had been
operational again for less than a week at only 4.7 SPM. Initial
production figures look promising with 1.7 m3/day of oil at 80%
watercut, down from the 95% on conventional pump. As the well
is speeded up oil production should increase to around 3 m3/day
with a water cut to surface of around 50%.
Some of the key data from above is presented in Table
1.
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