Liquid loading is a common cause of production impairment in gas wells, particularly depleted wells. North American gas producers need a low-cost pumping system to recover more gas from each well.

Most gas wells produce some water and/or hydrocarbon condensate. As long as the gas is flowing fast enough, the liquids blow out as droplets. As the well depletes, the velocity in the

Figure 1. Well Progression: As a well depletes, we can initially leverage the well’s own energy using plungers or foamers, but at some point we have to add external power. (All graphics courtesy of BP America Production Co.)
well bore drops and the liquid pools. This increases the pressure at the bottom of the well, which reduces the velocity, which pools more liquid, until the well stops producing completely. The rate of liquids production (b/d) is relatively unimportant; a low liquids volume will simply take a bit longer to kill the well.

A typical well produces at a velocity high enough to sweep out liquid early in the well’s depletion (Figure 1). This flowing regime can be extended by installing a velocity string. Eventually, however, that fails and then we harness the well’s own energy by using foamers or plungers.

With further depletion, the “self-powered” methods stall out, and we have to add external power to the well. In most cases, a very small liquid volume needs to be lifted in order to deliquify the well bore. Most deep gas wells produce less than 10 b/d of liquids. In theory, we need add only a very small amount of power to many existing gas wells and we could significantly increase gas production.

The opportunity

In depths shallower than roughly 5,000 ft (1,524 m), there are cost-effective options for powered artificial lift. Sucker rod pumps are popular, particularly above 3,000 ft (914 m), as are progressive cavity pumps. Gas lift and electric submersible pumps are also used, though generally in high liquids (>200 b/d) situations.

Below 5,000 ft, the options narrow quickly for low rate wells; only gas lift and sucker rod pumps are routinely installed. For a stand-alone system, the minimum cost for either is about
Figure 2. Hydraulic Power Distribution: If we had small, efficient pumps, many US wells could use them.
US $150,000. This includes the workover to install either gas lift valves or the pump and the surface equipment, either a compressor or a pumping unit. A minimum of about 25 hp is generally specified, partially because smaller equipment is not routinely available. In general, producers find that the cost and operational impact of gas lift and beam lift discourages them from putting power into deep gas wells.

In theory, the amount of power needed to remove the liquids is very small. Assuming a power efficiency of 50%, a depth of 10,000 ft (3,048 m) and a water rate of 10 b/d, only 1.5 hp is required. There’s a big gap between today’s 25 hp solutions (at $150,000 installed) and the actual requirement for many wells (1 to 2 hp). This gap provides an opportunity to create an entirely new market for artificial lift.

United States well set

Most deep US gas wells should need only small amounts of power to remove liquids (Figure 2). As of the end of 2005, there were approximately 63,000 producing gas wells deeper than 5,000 ft, with a power requirement of 25 hp or less (assuming 50% power efficiency). For comparison purposes, 25 hp represents 165 b/d of water from 10,000 ft or 330 b/d of water from 5,000 ft.

In general, this well population has a true vertical depth of less than 13,000 ft (3,963 m). Fifty percent of the wells are in Texas, with another 30% in New Mexico, Colorado and Wyoming combined. Ninety percent of the wells are cased with 41¼2-in. casing or larger, and when they have tubing, it is normally 2 3/8 in.

Potential production

How many wells could we install such a system in, and how much additional gas production is possible? Since this will be working against the economic limit, the intuitive answer is “lower cost, bigger market, more gas.”

Figure 3. Market and Value Estimate: The size of the low power pump market, and resulting incremental gas production, will depend on the overall cost of the pumping system.
In the US well set, there are certainly situations where a small amount of liquid removal will yield large increases in gas rate; these are characterized by high depletion, high permeability and low free water production at the perfs. Conversely, this well set also contains relatively undepleted, low permeability pay wells that will provide much lower production increases when deliquified. These parameters are not readily available in public well data so a rigorous estimate is very difficult.

We made some simple assumptions to estimate the production increase: a 50% first-year volume uplift on any well making 200 Mcf/d or less; an economic hurdle of a 1 year pre-tax, pre-royalty simple payout; and $4/Mcf wellhead gas price. Figure 3 shows what we expected intuitively: the lower the cost, the larger the opportunity. At $150,000/well cost, no spending can be justified. Having a system that could be installed and operated for a $60,000/well cost could be applied to 18,000 existing wells in the United States. That would be a total spend of $1 billion and would yield 1.2 Bcf/d of gas production. Relative to US gas consumption of roughly 60 Bcf/d, that is a pretty significant opportunity.

Upside and downside

Even if a proven system of components were available today, it would take years to add the installation and service capability needed to get to installation rates of thousands per year, and to drive the cost down the experience curve. Also, the estimate is a snapshot in time; wells are leaving this population when they stop producing, and enter the population due to natural decline. Most gas wells without active water drive will eventually be candidates for a low-cost system.

Besides the obvious upside and downside of the 50%/200 Mcf/d assumptions, this estimate does not take into account wells that were not producing at the end of 2005. Five percent of the estimated 300,000 wells that did not report production at the end of 2005 would be 15,000 wells. Wells outside the United States have not been included. Finally, it is likely that the technology developed could be applied to wells less than 5,000 ft in depth, improving recovery of that large resource base.

The obvious downside is failure to achieve a reliable, low cost system due to technical challenges. In particular, solids handling by a pump and corrosion due to fresh water condensation in gas producing conduit could be significant barriers to achieving a low cost, reliable system.

Current activity

Numerous suppliers and inventors have recognized the potential of this market and are developing pumps. Following successful downhole pump trials, system development will package not only the pump but also the liquid/power conduits, surface power supply and sales/service. Ultimately, the amount of gas resource that is recovered, and not left in the ground, will depend on the development of new, low-power technology that will reliably and economically remove small liquid volumes from marginal gas wells.

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