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.

Treatment Sizing
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.

Re-Treatments
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.