Cementing Compositions for Thermal Recovery Wells
- Wayne A. Walker (Halliburton Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1962
- Document Type
- Journal Paper
- 139 - 142
- 1962. Original copyright American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Copyright has expired.
- 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.14 Casing and Cementing, 5.4.6 Thermal Methods, 2.2.2 Perforating, 5.5.2 Core Analysis
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This paper presents the results of firing a number of different cementing compositions to the high temperatures which are expected to be encountered in thermal recovery wells. These compositions can be handled by ordinary cementing equipment and have sufficient thickening time to permit placement in wells to at least 6,000 ft in depth. Tests were conducted at temperatures of 700, 1,000 and 1,500F for periods of one, three and seven days, and at 2,000F for one day in dry heat at atmospheric pressure. Physical appearance, weight loss, shrinkage, change of permeability and compressive strength were the properties recorded or calculated. These tests showed that a cementing composition can be designed for the most severe temperature conditions expected in the thermal recovery process. These compositions will set hydraulically at low temperatures in one to two days and will retain most of their original physical properties after being heated to these extreme temperatures.
Neither the concept of using heat in the wellbore to stimulate oil production nor its actual use is new. Even the idea of using heat for this purpose in the producing formation itself was put forth in 1917, but the first recorded engineered use of thermal recovery (in situ combustion) in the United States was not until 1952. Since that time more than two dozen such projects have been undertaken to recover oil by this process. According to one major oil company, thermal recovery has been proved as an excellent secondary recovery method. Another states, "a high percentage of oil in a short time gives an attractive economic payout". A three-year experiment at South Belridge field, Kern County, Calif., shows that approximately 50 per cent of oil in place had been produced in 18 months, and 80 per cent of original oil was reported to have been recovered in tests in Illinois. The potential use of this method of recovery and the optimistic outlook of the participants point toward its increasing use as a method of secondary recovery, especially since the cost of exploration and production of oil increases year after year. Many of the papers and articles published to date on thermal recovery processes have dealt with the mechanics, engineering, economics and feasibility of the process, and very little has been mentioned about the problems of cementing the casing, either in the injection or producing wells. Most wells have been completed open-hole with the casing set at the top of the zone to be fired. Engineering personnel of some of the oil companies engaged in thermal recovery projects suggest that it would be better if the pipe could be cemented through the zone with a suitable material and then perforated. Some believe the cementing composition is not a problem, while others believe the type of material used is very important and take all precautions possible. The isolation of zones seems to be a stringent requirement in this process, especially in the injection wells. For these reasons a study of cementing materials was made to provide necessary recommendations for the most suitable compositions to use in wells where extremely high temperatures are encountered. This paper presents the results of tests on different cementing materials under various temperature conditions likely to be found in the thermal recovery processes, with emphasis on the advantages and disadvantages of the various blends tested.
Testing Procedures and Materials Evaluated
In initiating our laboratory tests for this project we found it difficult to duplicate actual field conditions. Some of the major problems were to ascertain well temperatures, how to duplicate them and what pertinent data to extract from the experiments. The range of temperatures that occur in a well when it is fired is governed somewhat by specific local conditions, the type of igniter used and the length of time the igniter is in use. Temperatures have been reported to range from 320 to 1,400F in field tests where electrical igniters were used, and they would he even higher if a gas igniter were used. Temperatures even higher than those experienced in field tests have been encountered in laboratory model experiments. For these reasons a wide range of temperatures was covered during testing. The average expected temperature probably will be in the range of 600 to 1,200F. The time the cement will be subjected to these temperatures will vary according to how long the igniter is used, how fast it is desired for the front to move away from the borehole and the temperature of the injected air.
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