dcasto,
That isn't quite right. The technology of eductors/ejectors are really closer to a standard compressor than it is to gas lift and has almost nothing to do with plungers.
What I did for BP was set up a series of ejectors (compressible power fluid, the Oil & Gas industry mistakenly refers to any non-steam thermocompressor as an "eductor") designed to provide Critical Flow (using Coleman's equation) up the tubing while the bulk of the flow went up the annulus. This significantly flattened the decline in a group of wells.
I described the application of thermocompressors in an Oil & Gas Journal article a few years ago (there is a copy at
Basically the ejector doesn't care where the power fluid comes from as long as it is at the right pressure and the right mass flow rate. I've designed a couple that use pressure wasted across a choke to suck on other wells and they work well. The most famous example was the CalTech Eductor that was installed on BP's Indefatigable Field in the North Sea to use excess pressure to suck on an adjacent Shell platform.
I'm actually dealing with Caltech as a supplier (they rent the units) I'm not too familiar with Coleman's equation, does it deal with nozzle sizes and min/max driver pressures/velocities ?
In November, 1969 a man named R.G. Turner from Baker Oil Tools published a paper in JPT asserting that at some increasing gas velocity the ability of a gas to carry liquid upward in a vertical conduit begins improving. This velocity was termed "critical velocity" (not to be confused with the other 10 things that are called "critical velocity" in fluid mechanics). Mr. Turner did all of his experiments at pretty high pressure and his equations significantly overstate the minimum velocity at lower pressures.
A few years later a researcher at Exxon named Coleman revisited the experiment at much lower pressures and published basically the same equation with a lower constant that seems to work better at mid-triple-digit flowing tubing pressures. This equation is commonly called the "Exxon Equation" or the "Coleman Equation" and it is used by a lot of people working in gas well deliquification to try to determine the flow rate that just exceeds the onset of liquid loading. The trade off is that the higher the flow rate the more pressure is lost to friction, minimizing that parasitic pressure-drop is worth a bunch of additional reserves recovery.
To bring the story up to date a guy named M. Li presented a paper at the 2001 SPE Permian Basin Oil & Gas Recovery Conference in Midland where he got a new data set under 100 psig and came up with a constant that was considerably lower than Coleman's, but that was done in this decade so very few people have accepted it yet (8 years is just too new for our industry).
I sized the ejectors I used in the San Juan Basin to provide a flow rate up the tubing that was slightly in excess of the "critical rate" predicted by the Coleman Equation.
Caltech does pretty good with custom applications. They are a bit more conservative than I like (i.e., they tend to want higher power-gas pressure and higher power-gas mass flow rates than I get from other vendors, but not hugely so). I love these projects that make productive use of otherwise wasted energy. If there is any way I can help, my e-mail address is on my web page.
