Incremental oil production

Incremental oil production for each of the pilot wells was calculated by subtracting the extrapolated production decline curve which was established prior to TFSA injection from the actual production after TFSA injection. Results of this analysis indicate that a total of 8150 + 850 bbl (1295 + 135 m3) of incremental oil were obtained due to injection of TFSA. 

Incremental oil production was assumed to have ceased by October 10, 1987 when the two high brine producing Wells TU-107 and TU-104 were shut in. 

At a sales price of 13.00 per barrel, the value of the incremental oil produced by the TFSA was between 94,900.00 and 117,000.00. This revenue was generated at a chemical cost of between 1.93 and 3.87 per incremental barrel. Cumulative incremental oil production, shown in Figure 5, indicates that the volume of incremental oil produced reached a constant and maximum value 18 months after the pilot was started. Of the total incremental oil recovered, 37.5 % was produced in the first six months of the pilot and 81.25 % was produced by the end of the... 

Assumes minimum amount of incremental oil production and that none of the TFSA flowed out of the pilot. 

Figure 5. Cumulative incremental oil production indicates that 8150 bbl of incremental oil were recovered by TFSA.

In this field test, which started on December 2, 2004, four slugs were injected (1) 300 mg/L polymer injection for 10 days, (2) 600 mg/L polymer injection for 50 days, (3) 1000 mg/L polymer injection for 30 days, and (4) 600 mg/L polymer injection for 33 days. The injection was stopped on April 5, 2005, followed by water injection. The median size of the injected microbaUs was 600 nm microballs swelled to 4 pm at 60°C. Eight out of 11 wells responded to the injection. The water injection profile was improved, showing decreased water intake in high permeability layers. The oil rate started to increase by April 2005 and increased significantly during May. In May, the water cut decreased, and by October 2005, incremental oil production reached 1560.1 tons. 

The pilot test was started on Jannary 24, 2000, and ended on March 20, 2001. The liquid rate in the pilot decreased from 377.5 to 219.8 t/d. The oil rate increased from 10.5 to 20.1 t/d, and the water cut decreased from 97.2 to 90.9%. By December 31, 2001, the incremental oil production was 6208 ml By this time, the benefit had already lasted 20 months. Some wells still benefited from the chemical injection after that time. However, one ton of incremental oil costs 40 kg alkalis, 126 L of surfactants, and 7.6 kg of polymer ... 

Oil production generally increases as a result of the improved volumetric sweep caused by foam injection. Incremental oil production from down-dip wells is likely to be higher than that from up-dip wells because of a reduction in steam override. Changes in the steam-oil ratio (SOR) can provide a reliable indication of foam blocking if steam-drive is the primary displacement method. 

Shell (48) used a simple foam model (49) for their Bishop Fee pilot. The foam generation rate was matched by using an effective surfactant partition coefficient that took into account surfactant losses and foam generation inefficiencies. The value of this coefficient was selected so that the numerical surfactant propagation rate was equal to the actual growth rate. Foam was considered to exist in grid blocks where steam was present and the surfactant concentration was at least 0.1 wt%. The foam mobility was assumed to be the gas-phase relative permeability divided by the steam viscosity and the MRF. The MRF increased with increasing surfactant concentration. The predicted incremental oil production [5.5% of the... 

The outcome of pol3nner flooding in a reservoir with layers in vertical communication clearly differs from the case in a reservoir with non-communicating layers. In the latter case, the polymer causes a gross change in the flow ratio between the layers. The fluid diversion, and hence Incremental oil production, begins as soon as polymer is injected and the Incremental oil is produced directly from the low permeability layers. 

Figure 8.23. Timing of incremental oil production as a function of vertical permeability of a two-layer reservoir (Clifford and Sorbie, 1984).

When polymer has left the high-permeability layer, it should be noted that the case with a high degree of cross-flow is more effective in maintaining the incremental oil production in spite of the large quantities of polymer in the low-permeability layer. The reason is that the polymer in the low-permeability layer is largely concentrated near the injector and the cross-flow does not greatly influence flow from the production end. 

However, the cross-flow of oil accounts for only a small fraction of the total incremental oil production, so that the overall profile for kjk = 0.1 is similar to the case of kjk = 0.001. It appears that the vertical permeability has to be extremely low (k < 0.001 kj in order to eliminate effectively the oil recovery mechanism. 

To date, 0.22 pore volume (PV) of the well pattern has been injected. The bottomhole pressure (BHP) of the forrr producer wells has increased by 1.7 to 2.7 times, showing the communication with the injector well, hence, after production has been adjusted to maintain the BHP between 75 to 100 psi. The injectivity is greater than the value estimated for profitability. Polymer breakthrough occurred in two of the 5-spot wells after approximately one year of injection, as forecasted in the reservoir simulation. A slight increase in the pattern oil production and water-cut reduction has been observed. Therefore, incremental oil production is expected in the forthcoming months. 

There is not yet incremental oil production that could confirm oil bank creation. 

Injection and production rates from the polymer flood area showing incremental oil production over the waterflood prediction. 

The incremental oil production attributable to the polymer application ranges from 8% - 22% OOIP. 

Table 2 shows field results from the application of mixed-molecular-weight polymer at one injection station. Injection Station 4. They demonstrate more-favorable incremental oil production and reduced water production than at Injection Station 3, where a more-monodispersed (i.e., unmixed) polymer was used. 

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