Periodic steam injection

Eig. 2. Cychc steam stimulation of an oil well (a) steam, injected into a well over a period of days or weeks in a heavy oil reservoir, introduces heat (huff) that, coupled with (b), alternate soak periods lasting a few days to allow (c) a production phase of weeks or months (puff), thins the oil. This process may... 

In steam stimulation, heat and drive energy are suppHed in the form of steam injected through weUs into the tar sand formation. In most instances, the injection pressure must exceed the formation fracture pressure in order to force the steam into the tar sands and into contact with the oil. When sufficient heating has been achieved, the injection weUs are closed for a soak period of variable length and then allowed to produce, first applying the pressure created by the injection and then using pumps as the weUs cool and production declines. 

To date (ca 1997), steam methods have been appHed almost exclusively in relatively thick reservoirs containing viscous cmde oils. In the case of heavy oil fields and tar sand deposits, the cycHc steam injection technique has been employed with some success. The technique involves the injection of steam at greater than fracturing pressure, usually in the 10.3—11.0 MPa (1500—1600 psi) range, foUowed by a soak period, after which production is commenced (15). 

The turbine temperature, flow, and speed increases in a very short time of about three to five minutes to the full rated parameters. There is usually a short period of time where the temperature may overshoot. If supplementary firing or steam injection for power augmentation is part of the plant system, these should be turned on only after the gas turbine has reached full flow. The injection of steam for power augmentation, if done before full load, could cause the gas turbine compressor to surge. 

Relevant only for a small fuel time constant and under low pressure Various modes of dynamic flow redistribution Occurs with steam injection into vapor suppression pools Very-low-frequency periodic process (-0.1 Hz)... 

Recovery of oil sand bitumen by steam injection involves either cyclic or continuous injection of steam at high pressure into a well. In cyclic injection, steam is injected into the oil sand formation for a period of time ranging from weeks to months. The steam spreads or floods the formation creating heat or pressure. The steam is then turned off, and the well is sealed for weeks to months. When the well is reopened, a mixture of water and bitumen can be withdrawn. 

For a period of 3-6 weeks, steam is being injected into the top and bottom of the reservoir through the tubing string of the producing well. Next, the well is shut-in for 2-3 days. It is then placed back in production. One and the same well is used both for steam injection and oil production. After the treatment, the well produces at a higher rate. The cycles of steam injection-oil production can be repeated several times. 

For each group of 7-10 producing wells, one steam injection well was employed. The distance between the injection well and the producing wells was 50-60 m. Steam was injected at the rate of 50-60 t/day per each injection well under the pressure of 8-24 kg/cm at the wellhead temperature of 180-28CK. For the 2-year period, the cumulative volume of steam injected into the individual unit areas of the Okha field amounted to 25-40 thousand tons. For the treated sections of bed IV as a whole, the steam/oil factor averaged 3.6 t/t however, from one unit area to another it fluctuated widely between 1.7 and 12.5 t/t Again, for the treated section of bed IV as a whole, the oil recovery factor increased from 0.13 before the steaming to 0.238 after the treatment In some of the individual unit areas the recovery factor went up to 0.4-0.5. 

The relative increases in flow rates of well 34 were smaller. Prior to the steam flooding this well produced for a long period of time at the daily rate of 6 t of water and 0.5 t of oil. But after 6 months of continuous steam injection well 34 increased its yield to 9 t of water and 11 of oil and by the end of the 7th month it further increased the daily flow to 13.5 t of water and 1.5 t of oil. By that time the temperature at the wellhead reached 45°C. 

Steam injection continued for a period of two years using wells 257 and 258. At first, injection well 256 was also used, but later it had to be excluded for technical reasons. The continuous steam flooding was carried out under the following regime volume of steam injected ranged from 120 to 170 t/day injection pressure and temperature, measured at the wellhead, were 28-30 kg/cm2 and 22J0-225°C. 

Following the above described periodic steam flooding, further steam injection was shifted from well 256 to well 257. Still, production well 474 continued to yield oil for over two more years. By the end of that period of time, however, its yield was down to 2-3 t/day. The stimulation of well 474 was due entirely to the steam injection through well 256. The steam injection well 257 was located at a distance of 170 m from the production well 474. At no time during the steam injection through well 257 was any effect recorded in the well 474 (see Fig. 33). 

When the effectiveness of periodic steam flooding via well 236 sharply decreased, steam injection was shifted to well 257. A regime of uninterrupted flooding was employed with daily steam input of 160-1701 at wellhead pressure of 35-40 kg/cm and at a temperature of 226-225°C. To control the movement of heat front in the reservoirs of unit area "b," the temperature, the flow of reservoir liquids and the geochemical changes were monitored in the production wells downdip from the injection well 257. 

The calculation called for cold water injection over a period of 170 days. Actually, the injection was continued only for 150 days at an average daily rate of 195-200 m. In order to control the process of steam flooding and to be able to predict its progress, a number of thermo-and hydrodynamic surveys were carried out both during the period of steam injection and of cold water injection. Temperature profiles were constructed for several wells, and maps were drawn showing isobars and isotherms for specific points in time. Using these data it was possible to follow the steam penetration within the oil-bearing bed and to decide on application of appropriate measures in the EOR treatment. 

While the experiment was in progress, steam injection into the well 257 was interrupted for one month. During that period of time, steam was injected into the production well 258 (located 100 m west of well 257) at the rate of 190 t/day and into production well 454 (located 200 m north of well 257) at the rate of 200 t/day. During tins same time the temperature in the observation well 477 decreased to 31°C, that is, almost down to natural formation temperature. 

Comparison of curves drawn on Figs. 41-44 shows that the cyclic-steaming-by-block was most effective on the group of wells 107, 133, 184 and 134 stimulated by steam injection into well 159. Thanks to the temperature increase in the third period, the productivities (rioii) of these wells were, respectively, 2.0, 1.25, 2.06, and 2.9 times greater after the treatment (3rd period) than before it (1st period) (see Fig. 41). 

Steam injection started in April 1969 in the northern part of the area, and in December 1970 in the southern part. During the period from 1969 to 1976, a total of 350,000 t of steam was injected into the reservoir, yielding an additional amount of 24,000 t of oil (Table 25). Starting in January 1974, cold water was being injected into the Khorasany reservoir in order to displace the heat bank. As of 1980, 144,000 m3 of water was injected and resulted in the recovery of approximately 24,000 tons of additional oil. 

The steam stimulation process, also known as the steam huff and puff, steam soak, or cychc steam injection, begins with the injection of5000-15,000 bbl of high-quality steam. This can take a period of days to weeks to accomplish. The well is then shut in, and the steam is allowed to soak the area around the injection well. This soak period is fairly short, usually from 1 to 5 days. The injection well is then placed on production. The length of the production period is dictated by the oil production rate but can last from several months to a year or more. The cycle is repeated as many times as is economically feasible. The oil production will decrease with each new cycle. 

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