Results

Most often the technical approach consisted of continuous injection of CO2 as carbonated water and alternate injections of CO2 and water slugs. This technology proved to be effective in fields containing heavy oils, highly mineralised waters, and in steeply dipping strata having lower reservoir permeabilities. The most successfully carbonated-water EOR project was in the Aleksandrovskay area of the Tuymazinskoye oil field, where the final oil recovery increased by 12%.

An inexpensive source of C02 and a heterogeneously structured oil deposit are considered as necessary conditions for continuous C02 injection. During pilot tests two problems complicated the continuous injection of carbon dioxide, one organizational and the other technical. The organizational problem lied in establishing a reliable system of CO2 collection from the plants, where it is a waste product, and transportation to the oil fields. The technical problem, which was not completely solved, consisted of strong carbon dioxide corrosion of the equipment and communications in the CO2 collection and transportation system.

The results obtained during the injection of CO2 into a Devonian reservoir in the Elabuzhskoye oil field in 1987 have been analysed and are presented below as an example. The CO2 used for this project was formed as a waste by-product during ethylene oxide production at the Nizhnekamskneftekhim petrochemical plant, located 5 km away from the oil field. The Elabuzhskoye oil field has been developed by perimeter water-flooding since 1972. The test area is show schematically in Figure 1, where average inter-well spacing is 500 m. From the beginning of development of the test area a total of 89.2% of the initial recoverable reserves have been recovered; the current oil recovery factor equals 0.437 (finite - 0.490) and the water cut exceeds 61%.

Figure 1. Scheme of well spacing in the test area.

C02 was injected into four injection wells (numbers 542, 544, 545 and 546) located along the test area perimeter. Monthly dynamics of the C02 injection are presented in Figure 2.

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Figure 2. Dynamics of C02 injection into injection wells 542 (a), 545 (b) and 544 (c).

Production wells in the test area were divided into 4 groups based on their response to the C02 injection (Fig.3):

1. appearance of C02 in a well without any change in water cut (wells 842, 932 and 824)

2. appearance of C02 in a well and decrease in water cut (wells 250 and 135);

3. absence of C02 in a well, decrease in water cut (wells 826, 836, 837, 931, 935, 949 and 823) and increase in water cut (wells 822 and 933);

4. no changes were observed in well operations (wells 820, 821, 828, 848, 938, 949, 951).

The analysis of the field data indicates that the greater part of CO2 injected into the oil pool was recovered from production wells during the 11.5 years of the test. The total amount of CO2 which was irreversibly trapped within the pool was not estimated.

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0 100

1987

1988

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1989

Figure 3. Dynamics of water cut and C02 content in wells 932 (a), 250 (b) and 836 (c).

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