March 2001 Supplement  Case Study

Walking beam-operated compressor offers solution for wellhead compression

Chris Huff, Jack Huff, O&G Producer; Trent Day, Aghorn Operating, Inc.; Kevin Sipes, Chisos Operating, Inc.; Mike McGinnis, Range Resources; and Charles McCoy, * Permian Production Equipment Inc.
* cmmccoy@beamgascompressor.com

Bottom line. Using a walking beam-operated gas compressor, operators can increase production and reduce operating costs on rod-pumped wells by drawing gas and gas pressure from the casing to allow additional hydrocarbon flow. Incremental daily revenue in five wells ranged from $100/day to $360/day – a particularly significant increase for often marginal wells. See table.

Design and operation. The beam gas compressor (BGC) utilizes the energy from the normal pumping action of the pump jack, Fig. 1. It is a piston in a cylinder that operates with the motion of the walking beam of the pumping unit. Gas is drawn from the casing during the suction cycle through check valves and is pumped (compressed) through check valves into the flowline on the compression cycle of the unit. The gas flows with liquids to the separator and to the gas sales line. The BGC is a double-acting unit and compresses gas on both the up and down stroke of a pumping unit. Since it requires the same amount of energy on both strokes, it does not affect the counterbalance of the pumping unit.

Fig. 1. The beam gas compressor (BGC) utilizes energy from the action of a pump jack. Gas is drawn from the casing during the suction cycle through check valves and is pumped through check valves into the flowline on the compression cycle.

The size of the BGC is configured to compress the daily gas production at the operator’s desired casing pressure within the pumping unit’s normal operating run time. The unit can operate in corrosive environments, as well as wet- and high-Btu gases, and has been installed on virtually every style of pumping unit. In addition to providing economic production increases, the BGC has environmental benefits – it captures and compresses vented gas into the sales line. It can also be used to boost low-pressure gas to operate lease production equipment.

Energy savings can occur in several ways. By removing the gas and pressure from the casing, pumps work more efficiently and pump-off controllers can more quickly detect pumped-off conditions, shut down the unit and save energy. Operating the BGC takes less horsepower than a skid compressor. In one application, the BGC compressor that replaced a 15-hp skid compressor increased the horsepower draw from the prime mover only 1.5 hp, a significant net reduction. Horsepower draw for the BGC depends on the amount of gas to be moved and line pressure.

The best candidates are wells in which the formation has a good productivity index. Field personnel often know the response of their wells to increases and decreases in operating pressure. But there is a degree of trial and error. Should a well not respond, the BGC is relatively portable and can be moved to other wells with minimal cost.

Wells with high fluid levels and properly operating pumps are not good candidates. However, if the high fluid level is due to inefficient pumping with gas interference / locking, the BGC can be used to reduce gas locking and improve pump efficiency. The BGC has been used for this purpose in many formations.

Field applications. The field applications documented here cover a broad spectrum of applications, including:

• Oil wells with low bottomhole pressures and with a fair-to-good productivity index
• Wells experiencing lost production and mechanical problems due to gas interference (gas locking) in the downhole pump
• Gas wells with good permeability but low formation pressure
• Oil wells that were uneconomical to produce.

In general, operators find advantages of the BGC over other types of wellhead compression to be:

• Using the pumping unit as the compressor prime mover is not only reliable, it is energy efficient and reduces lease operating expense.
• The BGC installation is simple and can be moved to other wells in the field.

And field hands enjoy the low maintenance without the need for daily attention or adjustments, as well as the fact that it does not require a scrubber for condensate.

Case 1 – Lea County, New Mexico (Jack Huff). The BGC was installed on Well 2 on the Bern A lease in June 2000. Reducing the casing pressure from 24 psi to less than 0 increased oil production nearly 40%, while nearly doubling gas production. Average daily revenue increased $171. At today’s prices, this increase of oil and gas translates to approximately $2,500 net monthly income after deduction of taxes, royalty and rental charges for the unit. Based on these positive results, Huff is considering additional units.

Case 2 – Andrews County, Texas (Aghorn Operating). The well was uneconomical to produce for a prior operator because formation pressure was so low that the well would not produce against line pressure. Since installation of the BGC in November 1998, the well has been profitable, even before recent upward swings in oil and gas prices. For a previously unprofitable well, the increased average daily revenue of nearly $350 is significant. In two years of operation, the only maintenance has been to replace the piston seals. Aghorn is presently evaluating another application.

Case 3 – Pecos County, Texas (Chisos Operating). Production response was during the first five months. After that, a second well was completed and production is being allocated by monthly well tests, so data is more erratic. Overall, though, production is holding up. The Forest Switzer 1 is utilizing a pump-off controller. A 10% decrease in energy consumption was realized after installation of the BGC. When the gas and pressure were removed from the casing, the downhole pump worked more efficiently. The pump-off controller more quickly detected pumped-off conditions, shutting the pump down and saving energy. Field personnel report that they have not experienced any problems in operating the unit since an automatic lubrication pump was installed.

Case 4 – Glasscock County, Texas (Range Resources). After installation of the BGC, oil production increased to 22 bopd from 14 bopd, and a minor increase in gas production was noted. In February 2000, a bridge plug was removed to open up lower perforations and the well went to 100% water. The bridge plug was replaced in early June 2000 and the well was returned to production. Production as of September 2000 had leveled off to 33 bopd, 31 Mcfd and 89 bwpd.

Case 5 – Glasscock County, Texas (Range Resources). Production data is based on four months of average production prior to installation, and seven months of average production after BGC installation. Units have been installed on four other wells: Powell 4-13D, Powell 4B-33D, Powell 16A-23D and Powell 9B-33D. These wells were originally equipped with electric-driven, skid-mounted compressors. There was no change in production rates on these other wells; however, utilities were reduced by $300 to $500 a month per well, and rental was $250 to $300 per month less. Little maintenance has been required for the BGC units and, unlike some compressor installations, the BGC units have not locked up during cold weather.

Conclusions. The five case studies represent a variety of field applications. Oil and/or gas production typically increased, while operating costs were lowered through reduced energy consumption, as well as reduced capital and/or rental costs. In one instance, an unprofitable well was saved. Typically, installed capital costs or rental fees are 30 – 50% less than costs incurred with other types of motorized compression equipment.

Experience indicates that no well is such a low producer that it should not be considered for BGC installation. Productivity index and insights from field personnel about well characteristics are key criteria for evaluating candidate wells. Even then, applicability is typically proven by field testing, which is not a problem since installation and removal of the unit is not complicated should the BGC not be effective on a given well. PTD