Candidate Well Selection
Best candidates are shut-in wells or wells producing at or near their
economic limit. These wells benefit most from a successful treatment
and little is at risk if the treatment fails, other than the treatment
cost. However, with the documented success of these gel treatments in
the Arbuckle formation in Kansas, many operators are treating wells
that are producing economically. Other selection criteria include high
water disposal and/or lifting costs, significant remaining mobile oil
in place, high water-oil ratio, high producing fluid level, high initial
productivity, wells associated with active natural water drive, structural
position and high permeability contrast between oil and water-saturated
rock (i.e., vuggy and/or fractured reservoir). Successful treatments
have been conducted in both cased and open hole completions.
Only empirical methods exist at this time for sizing treatments. Experience
in a particular formation is most beneficial. However, in many instances
larger volume treatments appear to decrease water production for longer
periods of time and recover more incremental oil. Some rules-of -thumb
being used in the Arbuckle formation in Kansas include two times the
well’s daily production rate as the minimum polymer volume or
using the daily production capacity of the well at maximum drawdown
(i.e., what the well would be capable of producing if it were pumped
off) as the treatment volume. In lower fluid level wells the daily production
rate is sometimes used as the minimum polymer volume.
Preparation Prior to Pumping
It is important to ensure the wellbore is clean. Acid is important to
remove near wellbore obstructions that can reduce polymer injectivity.
Most operators acidize the well prior to the gel treatment. In the past
typically 350-500 gal of 15% acid was used prior to the treatment. However,
recent trends indicate larger volumes of acid are being used, 1000-1500
gal. The acid is being pumped away and displaced with water ahead of
the gel treatment. Data obtained during the acid stimulation is important
in making any treatment design changes. In many instances, low acid
injectivity is a good indicator of a potential polymer treatment failure.
It is also recommended to establish a maximum treating pressure; run
a step rate test to determine parting pressure, if necessary. Select
an acceptable source of water to blend and pump the treatment. Gels
can be formed using a wide range of waters, from fresh to formation
brines. Have the service provider test the water’s compatibility
to form the desired gels. Select a polymer-compatible biocide for the
mix water (typically 5-10 gallons per 500 barrels of mix water). Set
tubing and packer to isolate the zone to be treated.
Placing the Treatment
Use stages of increasing polymer concentration. Inject the treatment
at a rate similar to the normal producing rate, one of the service companies
recommend an optimal rate of 1 bbl/minute (BPM) which is equivalent
to 1440 barrels per day. Some rules-of-thumb are 0.25 to 0.5 BPM for
tighter formations and 1.0 to 1.5 for more permeable formations. Keep
treatment pressure below reservoir parting/fracture pressure. Changing
conditions during treatment may warrant design changes during pumping.
It is common practice to perform shut-in pressure tests throughout the
treatment if there is a pressure response. Offset producing wells should
be monitored for polymer entry. Over displace the treatment with water
or oil. In some instances, a rapid pressure response early in the treatment
is a danger sign the treatment may not be successful.
For high fluid level wells in the Arbuckle, the optimal
polymer volume has been 3500 to 4000 barrels of polymer. The polymer
is pumped in increasing stages of concentration. Typical stages start
out at 4,000 ppm, increase to 5,500 ppm, 6,500 ppm and end with 8,000
ppm. High molecular weight polymer is used in the 8,000 ppm stage.
The rationale for using lower concentration gels to begin
the treatment are to test the injectivity of the viscous fluid into
the reservoir and the gel on the leading edge of the treatment will
occupy rock furthest from the wellbore where it will be exposed to much
lower differential pressure, therefore higher concentration gels are
not needed deep into the reservoir. Rationales for higher concentration
gels at the end of the treatment are this gel will occupy the area nearest
the wellbore where it will be exposed to higher differential pressure
and these stronger gels will hold the treatment in place.
Post Treatment Procedure
Most operators are over displacing the treatment with 80-150 barrels
of water and/or lease crude. The well is shut-in for a minimum of 4
to 14 days to allow time for the gels to form. It is then swab tested
for one day or until little or no polymer is observed in the returns.
The well is reactivated based on the swab test results. It is recommended
to monitor production rates for at least 30 days, if not longer.
Some wells have been treated multiple times with polymer. It is believed
that the gels have not chemically degraded, but that the water eventually
finds another fracture or vugular system to travel through. These re-treatments
are typically lower volume. Most of the re-treatments noted an earlier
pressure response due to the existing gel. In many instances initial
production responses were equivalent to the first treatment. It is felt
in many instances the re-treatments are more economical than adding
larger artificial lift equipment.
Updated February 2003