The Future Outlook for Tertiary Recovery
- I.F. Roebuck Jr. (Core Laboratories Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1961
- Document Type
- Journal Paper
- 416 - 418
- 1961. Original copyright American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Copyright has expired.
- 5.4.2 Gas Injection Methods, 1.6 Drilling Operations, 5.3.2 Multiphase Flow, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas, 5.4.1 Waterflooding, 6.5.2 Water use, produced water discharge and disposal, 5.3.4 Integration of geomechanics in models
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What is the future outlook for tertiary recovery in the United States? Undoubtedly, 25 years ago this same question was asked with regard to the outlook for secondary recovery. At that time, economic conditions were such that oil operators and petroleum engineers were searching for means of increasing oil reserves -- not only through the use of more advanced exploration and drilling technology, but also through prolonged and more efficient production from producing wells and through additional recovery from depleted reservoirs. This search led to the development and widespread application of fluid-injection operations for the purposes of pressure maintenance and secondary recovery. That this search was successful is evidenced by the fact that unitized fluid-injection projects alone produced a total of 357 million bbl of oil and condensate during 1958, representing 15 per cent of all the oil produced in the U. S. during that year. In a report recently presented to the Interstate Oil Compact Commission by its Secondary Recovery and Pressure Maintenance Committee, it was indicated that an additional 14.8 billion bbl of oil will be recovered in the future by conventional gas- and water-injection operations. On the other hand, it has been estimated that less than one-third of the total original oil in place will be recovered from currently developed reservoirs by primary production and conventional gas- and water-injection operations. Even with the widespread application of the recently developed miscible-displacement and in situ-combustion techniques, less than one-half of the original oil in place in these reservoirs will be recovered. Once again conditions are such that oil operators and petroleum engineers are searching for methods of obtaining greater percentages of the oil from currently producing fields and from reservoirs which have previously been subjected to primary and secondary operations -- hence, tertiary recovery.
To avoid confusion due to somewhat vague terminology, it would be well to define the various types of recovery operations. For the purpose of this paper, the following definitions are stipulated. Primary recovery is the production of oil reservoir by depletion of the natural reservoir energy. Pressure maintenance is the production of an oil reservoir by means of artificial stimulation and/or by augmentation of the natural producing mechanism(s) by fluid injection prior to depletion of the natural reservoir energy. Secondary recovery is the production of an oil reservoir by some means of artificial stimulation (fluid injection) after the natural reservoir energy has been essentially depleted by primary recovery operations. Tertiary recovery is the production of an oil reservoir by some means of artificial stimulation after secondary recovery or pressure maintenance operations. Since tertiary recovery, by definition, would consist of additional recovery of oil from reservoirs which have previously been flooded to economic abandonment, it would seem reasonable to assume that such additional recovery would be expensive and more difficult to obtain than the oil recovered under secondary operations. Therefore, it seems appropriate to examine some of the more important factors which are contributing to the desirability of and/or the necessity for tertiary recovery operations.
Exploration-Drilling Costs Up, Crude Prices Stable
The average cost per barrel for all newly-drilled liquid-hydrocarbon reserves in the U. S. increased from approximately $0.71 in 1950 to a maximum of $1.33 in 1957. This cost declined to $1.17 in 1958 and to $1.06 in 1959. The average cost of finding a barrel of crude oil in new fields in 1959 averaged about $2.77. Over this same period, the average price per barrel of crude oil increased from $2.51 in 1950 to a maximum of $3.09 in 1957. It decreased to an average of $2.92 in 1959. Industry-wide statistics indicate that the average domestic operator lost $0.27/bbl of oil produced in 1959, because for each net barrel of crude-oil production at an average wellhead price of $2.92/bbl, a total expense of $3.19 was incurred. This expense included $1.07 for exploration, $1.21 for development, and $0.91 for lifting costs and overhead.
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