DIVERSE METHODS SPREAD THERMAL EOR IN U.S.S.R.

Arcadi A. Bokserman
Intersectoral Scientific & Technological Complex
Moscow

Yusuf G. Mamedov
All-Union Scientific & Research Oil & Gas Institute
Moscow

Dmitri G. Antonlady
Scientific & Industrial Enterprise Sojuzthermneft
Krasnodar, Russia

Energy saving technologies that improve the efficiency of thermal enhanced-oil-recovery (TEOR) are expanding the application of TEOR to a wider area and different geological environments of the U.S.S.R.

As shown in Table 1, TEOR production in the Soviet Union reached 72,700 b/d in 1990. The production had gradually increased from 5,000 to 6,000 b/d during the middle 1970s when the first complete statistical data became available.

The major part of TEOR production, more than 55%, is from steam flooding. Another 35% uses hot water to produce about 25,000 b/d of light oil with a high paraffin content. This light oil is produced in the Uzen oil field in West Kazakhstan.

Also, successful in situ combustion in the Gnedincy oil field in the Ukraine produced, in 1990, 8,200 b/d of high water cut light oil.

CONVENTIONAL APPLICATIONS

Since the beginning of the 1950s, waterflooding has become the dominant technology for oil production in the U.S.S.R. Currently, more than 90% of domestic oil is produced with this technology.

The wide application of waterflooding has helped increase average projected ultimate oil recovery by as much as 42-44%. In some oil fields, still producing after many decades, the oil recovery has already exceeded 60-65% and even 70%.

Nevertheless, many oil fields are characterized by very low recovery efficiency. The percentage of such fields is sharply increasing. Fields producing heavy oil fall into this category.

In the U.S.S.R., the conventional TEOR methods studied in laboratories and applied in field practice are steam drive, in situ combustion, and hot-water injection.

STEAM DRIVE

Steam drive technology is the leading thermal EOR method in the Soviet Union. Production from this technology averaged 2,000-3,000 b/d in the beginning of 1970s and reached nearly 40,000 b/d in 1990. Altogether, 16 projects are currently active.

Steam drive is implemented over a wide range of geological conditions (Table 2). The optimization of the process is based on the following principles:

• Inject steam followed by cold water to create and propagate the heat zone in the formation.

• Use a wide, dense areal well pattern or row patterns to provide better conditions for monitoring and controlling the field development.

• Shift the steam injection front to improve heat utilization and to size correctly the heat slug.

• Optimize well density to injection/production rates and size of the heat slug by creating the maximum possible heat utilization and hydrodynamic interference among layers with different permeabilities.

• Use cyclic steam flooding to recover oil from less permeable parts of the formation.

• Use selective thermal stimulations of bottom hole zones in producing wells to control movement of heated zones and displace additional oil.

The previously mentioned principles for optimizing steam floods have been successfully used in the Soviet Union since the end of the 1960s.

The Okha heavy-oil field located in Sakhalin in the Far East is an example of steam flooding followed by cold water application. Production history of this field is presented in Fig. 1. Oil properties and geological characteristics are listed in Table 2.

As is seen in Fig. 1, steam injection in the Okha field started in 1968 when the oil production rate decreased to 1,800 b/d from a maximum level of 4,500 b/d. The steam injection response was quickly observed in an oil production increase that reached a maximum rate of 5,200 b/d in 1978. Cumulative steam/oil ratio (SOR) averaged 2.7.

Currently, steam drive is used in the fourth pay unit of the 10th block. This block has more than 30 million bbl of oil-in-place. Before starting to decline, oil production in this pilot reached a maximum of 2,750 b/d in 1972, four times higher than the production rate prior to steam (Fig. 2).

Cumulative SOR was reduced from 2.8 in 1973 to 1.6 in 1989, and ultimate oil recovery reached in this pilot is estimated to be 63%.

The first time in the Soviet Union that a deep, highly complicated, heterogeneous thick carbonate formation containing heavy oil was steam flooded was in the Usa oil field, located in the northeastern part of the Komi Republic.

Geological characteristics and oil properties of the Usa oil field are listed in Table 2.

Oil recovery factors in the Usa field for the primary and secondary stages did not exceed 7-10% of original oil-in-place (OOIP). This low recovery was the main reason to introduce heat into the formation.

Superheated-water injection with temperatures of 485-560 F. was started in 1982 and showed a very high efficiency. Recoverable oil reserves increased by 8001,000 million bbl, and ultimate oil recovery is estimated to reach 27% of OOIP.

IN SITU COMBUSTION

In situ combustion has been used in the Soviet Union since the end of the 1950s. Projects currently existing on a commercial scale produced 8,200 b/d of oil in 1990. Wet in situ combustion is successful in the Karajanbas heavy oil field, West Kazakhstan. Geological characteristics and oil properties of this field are presented in Table 2.

The Karajanbas oil field is divided into two main parts. The western part is developed by in situ combustion and the eastern part by steam drive. The in situ combustion area contains 364 producing and 78 injection wells.

Cumulative oil production as of Jan. 9, 1990, was over 18 million bbl, including 13.5 million bbl additional (enhanced) production since in situ combustion started. Oil production averaged 22,000 b/d with a 31% water cut. Only 3,000 cu ft of air are required to produce 1 bbl of oil in this pilot.

The steam drive area, in the other part of the field, contains 556 producing and 150 injection wells. Cumulative oil production as of Jan. 9,1990, was nearly 28 million bbl; 54% are credited to steam injection.

The average production rate is 37,500 bo/d with 50% water cut and an SOR as high as 3.6.

NONCONVENTIONAL THERMAL

The future of thermal oil production in the Soviet Union depends on wide application of both conventional and nonconventional thermal methods.

The following are the nonconventional thermal technologies tested in laboratories and applied on pilot scales in the oil fields:

• Combination of in situ combustion and hot water

• Combination of hot water together with steam followed by cold water

• Combination of polymers and a heat carrier (steam)

• Combination of a heat carrier and alkalines

• Combination of steam flooding and in situ combustion

• Cyclic air injection

• Cyclic in situ combustion

• In situ two-stage heat slug (TSHS).

TWO-STAGE HEAT SLUG

Calculations show the importance of the relationship between oil recovery and the size of the initially created heat slug as well as the steam quality, well pattern, the rate of heat carrier, and the injected cold water. In other words, the maximum oil recovery for each oil field depends on the combination of these controlling factors.

It was found that a heat slug may be created in the formation by injecting steam and water in certain sequences. Since 1986, TSHS technology has been successfully tested in a 12-well pilot area of the Karajanbas oil field.

The technology involves cyclic injection of steam and cold water as the first stage.

During the second stage, continuous injection of the rest of a heat carrier completes the creation of the heat slug. This slug is then pushed further by cold water.

Fig. 3 compares SOR for conventional steam drive and for TSHS technologies. Both are used in the Karajanbas oil field.

There is not much difference in oil production for both technologies. The main advantage of TSHS is the 30% decrease of SOR in comparison with conventional steam drive.

Also, water cut for TSHS technology is 5-6% less than in conventional steam drive.

Another advantage of the novel technology is the more efficient use of available field equipment.

HEAT CARRIER AND POLYMER

Since 1985, heat carrier and polymer technology has been tested in a Karajanbas oil field pilot that contains three wells.

This technology involves the injection of a high-concentration polymer solution prior to steam. The polymer solution influences the high permeable zone for a long period of time.

The low permeable layers are not affected by the polymer. As a result, this technology can double the sweep efficiency which has reached 60%.

CYCLIC IN SITU COMBUSTION

Cyclic in situ combustion was tested in the Karajanbas oil field. The technique alternates the injection of air during 45-60 days and cold water during the next 15-30 days.

This process significantly reduced the air/oil ratio compared with conventional in situ combustion (Fig. 4).

IN SITU AND FOAM

A pilot project combining in situ combustion with foam recently started in the Karajanbas oil field.

Three injection and 17 producings wells comprise the pilot.

Results to date show a decrease of water cut in producers by 15-20%.

HEAT CARRIER AND CARBAMIDE

The combination of heat-carrier injection and carbamide is being successfully tested in the Okha oil field in Sakhalin. The technology is based on thermal destruction of carbamide at high temperatures. Under such conditions, CO2 and ammonia are generated in situ.

A total of 13,000 SCf Of CO2 and more than 26,000 scf of ammonia are formed from a 1 ton of injected carbamide.

Increased oil production is due to the chemical reaction between an alkaline solution and oil components as well as CO2 dissolution in oil. In the Okha oil field, the technology is being tested in a pilot area with 44 patterns. About 1,050 tons of carbamide were injected into the reservoir, and more than 200,000 bbl additional oil were produced.

The process efficiency is expected to increase 1.5-3 times after being optimized.

OUTLOOK

Among the EOR techniques known worldwide, thermal methods have been developed for a wide range of applications. TEOR can be used under complex geological conditions for heavy oil and bitumen production and allows oil recovery to increase from 6-20% to 3050%.

Currently, only about 20% of the total U.S.S.R. heavy oil reserves with viscosity of more than 30 cp are being produced by TEOR methods. Estimates indicate that the reserves produced by TEOR could triple.

By the year 2000, heavy oil production is predicted to be 275,000-375,000 b/d, and in 2010 it could reach 450,000600,000 b/d. This forecast depends upon the domestic oil price. Fig. 5 shows the outlook for oil production due to thermal EOR vs. various crude-oil prices.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.