Improving Oil and Gas Production With the Beam-Mounted Gas Compressor (1984)

Summary This paper explores parameters involved in and advantages obtained by use of the Beam-Mounted Gas Compressor (BMGC), a single-acting gas compressor operated by the walking beam of a rod pumping unit. Its main function is to draw gas from the casing side of an oil well and to discharge the gas into the flow line. By doing so, the BMGC operation actually reduces the backpressure on the formation face, thus allowing additional oil to enter the wellbore for production. Introduction The first Sub-scalez (SS-1) formation is one of many productive horizons in a large oil field west of productive horizons in a large oil field west of Bakersfield, CA. Most SS-1 wells are characterized by low bottomhole flowing pressures (BHFP's) in the range of 20 to 90 psia [138 to 620 kpa]. Table 1 lists reservoir properties of the SS-1 formation. Although memoir estimates indicate that the SS-1 formation still contains significant volumes of oil and gas, the recovery has been masked by high casing and flowline pressure. A zero-pressure gas compression system has been under consideration for use as a large-scale casing pressure (CP) reduction system for most of the SS-1 pressure (CP) reduction system for most of the SS-1 wells. The zero-pressure system would alleviate the high CP problems and enhance oil and gas production. However, the decision to install a large gas compression system required some testing on a smaller scale in the area of CP reduction vs. oil and gas recovery. The BMGC was selected to accomplish the task of a small zero-pressure system. The BMGC was used on 42 SS-1 wells with excellent improvements in oil and gas production. The performance, results, installation, and production. The performance, results, installation, and maintenance requirements of the BMGC are discussed in this paper. Theory Pumping well productivity depends on many factors. Pumping well productivity depends on many factors. Factors considered for BMGC installations included (1) pumping unit capacity, (2) downhole pump condition, pumping unit capacity, (2) downhole pump condition, (3) ability of the formation to give up fluids, (4) density and nature of the annulus fluid, and (5) location of annulus fluid levels. For Factors 1 and 2. the problem could quickly be identified by running dynamometer surveys or by closing surface valves on the wellhead and allowing the pump to run for a few minutes. If the tubing pressure increases with the pump strokes, this indicates that the downhole pump is in good condition. If the tubing pressure does pump is in good condition. If the tubing pressure does not increase, this indicates that the downhole pump is defective, a hole exists in the tubing, or a leak exists in the surface equipment. For Factors 3, it is a little more difficult to establish whether a formation's ability to give up fluids can be enhanced. From initial production tests, one can establish whether a well is capable of producing a certain volume of oil and gas. With time, the production rate of a well could decline. The decline rate of a pumping well could be determined by decline-curve analysis with confidence if the well has been on production for 5 or more yearn. In addition, transient-pressure surveys could be conducted to determine effectively the permeability-thickness (kh) values, which in turn could be translated permeability-thickness (kh) values, which in turn could be translated into recovery figures. For the SS-1 formation, all wells have been producing for more than 5 years. Also, pressure surveys were conducted on most of the wells. From the long production history and the pressure surveys, we could judge which wells were capable of producing incremental volumes of oil and gas with the use of the BMGC. Factors 4 and 5 are interconnected. The relationship between the annular fluid level and the density of the fluid is proportional to the magnitude of the back-pressure exerted on the formation face. If a well is not pumped off, a column of fluid will exist above the sandface. The fluid exerts backpressure on the formation in the form of hydrostatic weight. An increase in the hydrostatic weight on the sandface will require an equal increase in the BHFP to produce the same volume of oil and gas. In addition to the hydrostatic weight of the fluid level, the surface CP also exerts backpressure on the sandface. The CP in most cases reflects the pressure of the gas column above the annular fluid level. Therefore, it could be inferred that an increase in the backpressure on the formation will cause a decline in the drawdown and correspondingly reduce the productivity of the well. As discussed by Gilbert, the PI of an oil well depends on drawdown. The ability of the formation to produce fluid increases with an increase in the pressure drawdown. If the CP exerts sufficient backpressure on the formation, the drawdown and the productivity of the well is reduced. JPT P. 276