Operating Costs and Performance of Large-Volume Submergible Pumps
- Richard K. O'Neil (Reda Pump Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1972
- Document Type
- Journal Paper
- 1,473 - 1,478
- 1972. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.6 Natural Gas, 4.2.3 Materials and Corrosion
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The Big Horn basin in Wyoming presents producing difficulties that respond well to the use of submergible pumps. Here are some statistics on the operating costs and performance of a large number of the pumps in use in the area, and some techniques for predicting pump-life expectancy that perhaps can, with proper modification, be applied to other areas.
The Big Horn basin in northwestern Wyoming contains a large number of fields that historically have been well suited to the use of submergible pumps; that is, they call for high-volume withdrawals. This application of such pumps has been recognized by operators in the area and the use of them has been widespread. This paper reviews the operation of submergible pumps in 14 fields and 30 individual reservoirs throughout the Big Horn basin.
Two factors a developing market for sour crude, and increasing water production caused by typically active water drives in the Big Horn basin made rates of withdrawal more critical, hence increased the demand for submergible pumps. In 1960 there were less than 100 submergible pumps in operation in the Basin. By 1970, the number had increased to more than 400. Fig. 1 shows the growth in the number of submergible pumps run by the six largest users within the Big Horn basin. During 1970, these operators had 247 submergible pumps in operation.
We shall review here the performance of submergible pumps in oil production service over the last 10 years and provide guidelines for maintenance costs and power costs for operating the pumps in the Big Horn basin. Specifically, we shall review the operational life of 611 motor runs from the six largest operators in the area, the 1970 maintenance costs associated with the production involving submergible pumps, and power costs for more than 50 wells with pumps, and power costs for more than 50 wells with individual power meters.
The principal producing reservoirs in the Big Horn basin are the Embar (a Permian dolomite), the Tensleep (a Pennsylvanian sandstone), the Amsden (a Pennsylvanian dolomite), and the Madison (a Pennsylvanian dolomite), and the Madison (a Mississippian limestone). All of the reservoirs are usually quite thick, with net pays ranging up to 150 ft. In varying degrees, all of them are fractured and have active water drives. The reservoirs range in depth from 2,500 to 7,000 ft, with the average being 3,800 ft. Pertinent fluid characteristics are as follows:
Range Average Gravity, degrees API 11.3 to 36 22 Temperature, degrees F 73 to 145 130 Viscosity, cp 10 to 200 24 Percent sulfur 1.89 to 3.93 2.65 Percent sulfur 1.89 to 3.93 2.65 The typical well produces at high water cuts, which mitigates the effects of the high crude viscosities normally encountered. The crude oil is sour, as evidenced by the sulfur content; and the associated gas has a high hydrogen sulfide content. Despite the sour conditions, corrosion has not been a significant factor in the operation of submergible pumps in this area. The life of standard cables with butyl insulation the type normally used because of the moderate temperatures encountered appears to have been adversely affected by the hydrogen sulfide in the gas. However, cable runs of 7 to 10 years have been common.
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