Summary of Polymer Treatments
The polymer treatments were designed to be relatively small volumes with high concentrations of polymer. The reservoir has a relatively high temperature of 220°F and it was thought that this might be a problem causing some degradation of gel strength. Therefore, treatments were designed to finish at concentrations of 10,000 ppm. Job logs for each of the three treatments are included in the appendix.
SU 10-28, NWSE Sec 28, T8N, R58E
On March 11, 1996, a MARCIT™ polymer-gel treatment was pumped in the SU 10-28 well. Perforation depth of the D Sand is at 6309 to 6334 ft. A total of 1150 lb Water-Cut 204® was injected with 418 bbl water in three stages with concentrations of 6000, 8000 and 10,000 ppm of polymer-gel. The average injection rate was 580 bpd with wellhead pressures from vacuum at the start to 1750 psi at the end. The well was shut-in for 6 days before injection was resumed at 204 bwpd with a wellhead tubing pressure of 575 psi. Post-treatment pressure fall-off test and temperature log were run on May 10. The fall-off test indicates a reduction of permeability-thickness (kh) from 43 to 24 md-ft (see table 4). A temperature log run after treatment indicates the injection water is confined to the D Sand perforations. A radioactive-tracer and temperature log was run in this well in 1993 and also showed all injection into the reservoir interval.
The only direct offset producer to the SU 10-28 well is the SU 7-28 well, located SWNW Sec 28. During the 3 months prior to the treatment the well averaged 29.1 bopd and 259.3 bwpd. An oil-cut of 9.4 percent is computed for this time period. During the last quarter, October through December, the well averaged 26.7 bopd and 260.6 bwpd. The current oil-cut is 9.3 percent.
Figure 11 and 12 are plots of allocated production for the SU 7-28 well. Figure 11 is production rate with time and figure 12 is producing rate with cumulative produced oil. Also shown on the graphs is the average daily injection at the SU 10-28 well. Trends of production history are computed through the recent data. The figures show that the is no change from the oil rate or oil-cut trends. The injection rate at the SU 10-28 well has been steady at about 300 to 350 bwpd. Injection wellhead pressures have increased from vacuum to about 1100 psi.
SU 3-21, NENW Sec 21, T8N, R58W
The Sooner Unit 3-21 well was treated June 6,1996, with 442 bbl of water with 1200 lb of WATER-CUT 204® MARCIT™ gel. Treatment consisted of three stages of 6000, 8000 and 10,000 ppm concentrations of polymer-gel. A pressure fall-off test performed after treatment indicates a reduction of permeability (kh) by 70 percent from 126 to 37 md-ft (see table 4). A temperature log run after treatment indicates the injection water is confined to the D Sand perforations at 6293 to 6322 ft. There has been no positive production response observed as of this time. Prior to treatment, the well was injecting an average of 568 bpd with no wellhead pressure. After treatment, the injection has averaged 291 bpd with wellhead pressure of about 1200 psi.
There are four wells which off-set the SU 3-21 injection well. These wells are the SU 13- 16, SU 14-16, SU 4-21 and SU 6-21. During the 6 month period prior to the polymer-gel treatment, these wells averaged, in total, about 32 bopd and 735 bwpd. Average oil-cut is computed as 4.2 percent. During the six months following the treatment, these wells averaged 27 bopd and 573 bwpd. Average post-treatment oil-cut is computed as 4.5 percent. During December 1996, these wells averaged 23 bopd and 507 bwpd. The corresponding oil-cut is 4.3 percent. Figure 13 and 14 are plots of allocated production for the wells which off-set the SU 3- 21 injection well. Figure 13 is producing rate with time and figure 14 is producing rate with cumulative produced oil. Also shown on the graphs is the average daily injection at the SU 3-21 well. Trends of production history are computed through the recent data. The figures show that there has been no positive change from the oil-rate or oil-cut trends. The injection rate at the SU 3-21 well has declined considerably from 600 to less than 300 bwpd. Injection wellhead pressures have increased from vacuum to about 1200 psi.
The treatment has resulted in reduction of water injection of 277 bpd or 49 percent. Both oil and total fluid production rates at offset wells are down by 25 percent. The pumping unit run- times at the SU 4-21 and SU 6-21 well are still decreasing. This indicates that steady-state injection-withdrawal has not yet been achieved (the reservoir-drainage volume is pressure depleting).
The total original-oil-in-place (OOIP) for this 200-acre portion of the Sooner Unit is calculated to be about 1,208,000 bbl. Cumulative secondary recovery to-date is 168,000 bbl or 13.9 percent of OOIP. The extrapolated secondary recovery for this injection cell at the SU 3-21 well is about 225,000 bbl to 2 percent oil-cut. The secondary recovery factor is computed to be 18.6 percent of OOIP.
SU 15-21, SWSE Sec 21, T8N, R58W
The SU 15-21 well was treated August 6, 1996, with 497 bbl of water with 1400 lb of WATER-CUT 204® MARCIT™ gel. The treatment was in three stages starting at 6000 ppm and ending with a maximum concentration of 10,000 ppm. The maximum wellhead-injection pressure was 810 psi. A fall-off test was performed pre-treatment and indicated a permeability (kh) of 453 md-ft for the 20 ft D Sand interval. Perforation depth is 6259 to 6288 ft (see table 4). A pressure fall-off test was not performed after treatment because treating rates and pressures indicated similar results with the treatments at the other two wells. Prior to treatment, the well was injecting about 650 bwpd with no pressure at the wellhead. After treatment, the well was injecting water at about 400 bwpd with a wellhead pressure of 250 psi.
