Range Resources pioneered the Marcellus Shale play in 2004 with the Renz #1 well in Washington County, Pa. Since that time Range has grown to be one of the largest lease holders in the Marcellus with more than 1 million net acres and has more than 600 producing wells in the core area of the play in southwest Pennsylvania.

As a production team, we have faced many new challenges and obstacles in developing the Marcellus Field. Geographic diversity, the evolution of drilling and completion techniques, more prolific wells and longer laterals require us to be flexible and innovative with our approach to drilling and producing productive wells.

Due to high reservoir pressures and relatively low liquid volumes, our Marcellus wells produce naturally for up to three years before artificial lift is required. We have taken a proactive approach in analyzing the wells for their future artificial lift needs to ensure we can maximize production rates in older wells. Our main tool for candidate selection is Turner’s critical flow rate model. Turner’s calculation shows us that gas production in these wells can decline to around 11.3 Mcm/d to 12.7 Mcm/d (400 Mcf/d to 450 Mcf/d) before liquid loading occurs.

Our team analyzed a number of artificial lift options for these wells. We eventually narrowed our focus to two methods—gas lift and plunger lift—and we are evaluating the potential of capillary strings as a third method.

In our selection of artificial lift systems, rod pumps, electric submersible pumps (ESPs) and jet pumps were eliminated due to the relatively low fluid volumes produced in the wells. We looked closely at ESPs, but the added cost of this solution over the alternatives didn’t make sense. Because ESPs work best with homogeneous fluids, we didn’t feel that they were a good fit for our wells where we experience changing ratios of water, condensate and gas, which causes the overall fluid density to change and results in erratic production and slugging.

Gas lift was chosen as the solution for a small segment of wells where we had lower reservoir pressures and higher fluid volumes. So far this has only been a solution for a very small number of wells.

Our main choice of artificial lift has been plunger lift. With our proactive approach we target the plunger lift systems for installation when gas production declines to about 17 Mcm/d (600 Mcf/d), well above the Turner rate for most of our wells. We selected this production level to avoid allowing wells to decline to the point where production is severely impeded by liquid loading. The plunger lift systems provide an economical method of producing the produced liquids, thus stabilizing production and slowing the decline characteristics of the well.

The only drawback we see with the plunger lift systems is that they require some shut-in time while the plunger is falling. Although we run quick trip and bypass-type plungers, they still require some shut-in time, which cuts into the time that the well is producing. To counter this, we have been considering the use of capillary strings as an interim step to be used between the time a well is producing naturally and the time it is required to be on a plunger lift system. The capillary string would give us the ability to inject surfactants to lighten the density of the fluid column, which reduces the critical velocity needed to lift the fluids. Unlike plunger lift systems, there is no downtime while using a capillary string, so we can maintain production 24 hours per day. Our goal with the capillary strings would be to delay implementation of a plunger lift system until the wells have declined to a lower gas rate, possibly around the 5.7 Mcm/d (200 Mcf/d) range. The capillary strings would only be used in dry gas wells due to the separation issues that arise when surfactants are used in wells producing NGLs and condensates. Once a plunger lift system is installed, we feel that it can remain in place until well abandonment.

When examining wells for artificial lift, we try to keep an open mind and examine all options. The method that delivers good results in one well may not produce the same results in another. And we know we must be prepared to change artificial lift methods as a well’s production characteristics change.