American Oil and Gas Reporter - June 2014 - 105

SpecialReport: Artificial Lift Technology
FIGURE 7
Oil Response Comparison of Treated Wells
12

P1
P2

11
10
([Daily Oil Rate]/[phi-h])

9
8
7
6
5
4
3
2
1
0
2

Months Active

noted that the manifold gas meter was
reading improperly for the first month of
production.
Since all the P2 treatments were done
preactivation, the only economic comparison between the two project areas
must be on incremental costs. The added
capital cost to the P2 project is approximately $1.50 per barrel of oil produced
to date, but is projected to drop to less
than $0.38 per barrel of oil before the
projected economic limit is reached. These
economics neglect the benefit of not
having deferred production, as in P1, and
the time value of money, which would
favor P2 economics.
The difference in incremental cost to
date is attributed to the increased magnitude of the conformance problem in the
P2 area and the difference in maturity of
the projects, with P1 having been fully
active for two years longer than P2. The
severity of the problem is highlighted by
the increase in average job size from
13,000 barrels of polymer gel per well at
P1, rising to 17,000 barrels per well at
P2.
Another way to compare the effectiveness of the conformance treatments
is to compare the initial oil response of
problems wells in P1 treated after initial
activation with pretreated wells in P2.
Figure 7 shows the oil rate divided by
phi-h. This is used to scale down wells
with larger OOIP and make all wells relatively comparable.

Since the P1 wells were treated after
having been activated, the graph compares
preactivation treatment with problem
wells that required post-activation treatment. The oil response difference between
project areas one year after activation is
nearly three times better in the treated
project, and it was not necessary to shut
in wells for treatments. As suggested earlier, treating the project area prior to CO2
activation means there is no CO2 in the
ground to interact with the gel setting.
Troubleshooting
The biggest problem encountered after
treating a producing well with polymer
gel is producing back gel. Some nonmatrix
flow features have proved too severe for
gel to withstand the pressure drop. Polymer

cleanup using an ESP in these problem
wells has taken months instead of days.
Looking back, we see these were the
jobs with larger-than-design volumes that
did not build pressure as intended.
One such well's treatment had inconsistent pressure that built only to 435 psi
tubing pressure after nearly 24,000 barrels
of gel had been pumped. The increases
in pressure were caused largely by friction
from increases in polymer concentration
and injection rate. Polymer quality appeared good throughout these treatments,
with all samples cross-linking as expected.
To counteract this concern in the next
project area, P3S, many polymer jobs
that would not build pressure were tailed
in with cement. Additionally, polymer
gel treatments not building pressure after
10,000 barrels of injection were suspended,
and cement was placed into the dominant
offending interval.
The interval to squeeze is determined
by running an injection profile survey
after more than 7,000 barrels of gel have
been pumped. Cement is pumped in multiple stages until squeeze pressure is
achieved. Cement volumes averaged 250
barrels. The 18-3A injector previously
mentioned took 11,916 barrels on a vacuum before treatment was suspended and
the offending intervals were squeezed
with 714 sacks of cement before building
any positive surface pressure. The step
rate test performed when this well was
activated shows an injectivity index of
8.2 bpd/psi, indicating we should not
have immediate issues.
Some treatments are pumped to plan,
building pressure consistently through
the treatment, once positive wellhead
pressure is achieved. One of the first pretreatment wells in the P3S project area is

Williams Plans To Expand Transco Pipeline System
HOUSTON-Williams Partners LP
says it will expand its Transco pipeline
system by 1.2 billion cubic feet a day,
with the expansion serving Cheniere Energy's Sabine Pass liquefied natural gas
export facility in Louisiana.
According to the company, Sabine
Pass Liquefaction will be the anchor
shipper on the $300 million Gulf Trace
project to link Transco to the LNG export
terminal. Williams Partners says it also is
holding a binding open season to gauge
additional interest in the expansion.
When the initial phase is complete in

late 2015, the Sabine Pass LNG terminal
will be the first large-scale LNG export
facility in the United States, Williams
says. Cheniere already has signed longterm off-take contracts with several foreign-based companies.
Williams also announces the Federal
Energy Regulatory Commission has approved its application to build and operate Transco's $50 million Mobile Bay
South III expansion project, which will
provide another 225 MMcf/d of gas to
Gulf Coast customers.
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JUNE 2014 105

American Oil and Gas Reporter - June 2014

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