Pumping Unit Optimization
- D.G. von Hollen (BeauTech Inc.) | S.K. Newton (BeauTech Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Latin America/Caribbean Petroleum Engineering Conference, 23-26 April, Port-of-Spain, Trinidad
- Publication Date
- Document Type
- Conference Paper
- 1996. Society of Petroleum Engineers
- 2.2.2 Perforating, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 1.10 Drilling Equipment, 4.6 Natural Gas, 3.1.1 Beam and related pumping techniques
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In order to produce available fluids, pump jacks used at surface have been engineered to stroke as slow as 6 (six) strokes per minute (SPM) and as fast as 14 (fourteen) SPM. Depending on available production, pump length (stroke) and pump size were the only two other variables taken into consideration. This approach works well until a time is reached when production has declined to a point where production inflow no longer matches pump capacity. As production declined, the typical method of compensation was to shorten the stroke, downsize the pump and remain at a constant SPM somewhere around 10 (ten) SPM.
As production declines this approach eventually results in partial pump fill even with small bore pumps, short stroke and slowing the unit as much as possible with current sheave limitation.
At this point it is physically impossible to fit a large enough sheave on the gear box or small enough sheave on the electric motor to reduce the speed below approximately 6 (six) SPM.
On some lower volume fluid production (100 bbls. and less) beam pumping wells it is difficult, if not impossible, to maintain constant production without tagging bottom at all times to keep them from "gas locking". The unit pumps quite well for a few days with the pump spacing set just off "tag" then stops pumping and the string has to be lowered 12-14" to make it pump again. If the string is not raised up again the "tag" destroys the clutch at the top of the pump (fig. 14) and pump life is short with all too frequent parted rods and tubing failures.
By reducing SPM to match the fluid inflow capability of the formation a more constant effective weight can be kept on the end of the rod string (on top of the traveling ball) so the rods don't contract and cause pump spacing to vary.
By reducing SPM according to the available fluid production of a well and keeping a pump efficiency in the range of 60%+ (appendix) erratic rod loads could be reduced or eliminated and production maintained without continually "tagging" bottom. Slowing down like this should prevent excess gas being driven into the tubing. This would eliminate the possibility of the tubing flowing above the pump. If the weight of fluid over the plunger were more constant and rod elasticity was better controlled the plunger would continually return to a preset point at the bottom of the stroke. At the slower SPM more time would be allowed for gas separation to happen in the annulus instead of causing interference in the pump. This would keep the unit pumping constantly with no additional adjustments at surface. Prime mover horse power and amperage draw could be reduced as well. At the same time tubing wear would be reduced and pump run time extended (ref. 2). (By shutting the unit down at the time of pump off; this paper shows better pump run times).
The well chosen for application of the theory came on line at 150 barrels per day and 500 mcf gas then declined to 12.7 barrels per day and 64 mcf gas. A 100" stroke length beam pumping unit was on the well with a 1.5" zero slip pump installed (fig. 14). Other well information is recorded in (table 1) Pumping was very erratic as it continually needed to be respaced in order to make production. Dynamometer cards taken before the slow down were very erratic and unpredictable.
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