Since companies first began to produce natural gas out of the Barnett Shale, shale production of both oil and gas has increased even as rigs have decreased. This seeming dichotomy is because of the truism that many children hear from parents and teachers: “Practice makes perfect,” which doesn’t just apply to learning the alphabet or riding a bike.

After producers discovered how to unlock hydrocarbons from more shale plays, they also improved efficiencies along with utilizing new technology. However, perhaps just as important has been the application of lessons learned from producing each play.

At the start of the shale revolution, producers tried to take lessons learned and apply them to shale plays that were similar. However, it was discovered that no two plays are alike, according to Randall Wright, president of Wright & Co. Inc.

While speaking at Hart Energy’s recent DUG East conference in Pittsburgh, Pa., Wright said that even though the shale revolution is less than 10 years old, it can be divided into two generations due to the improved learning curve.

“As operators gain knowledge, they get better performance from their wells,” he said. Wright noted that the first generation of horizontal drilling focused on shorter laterals of 2,800 feet to 3,500 feet, wide stage placement and lower estimated ultimate recovery (EUR) levels. The second generation of horizontal drilling has been characterized by longer laterals of 4,000 feet to 7,500+ feet, reduced cluster spacing, and higher EUR.

The second generation doesn’t have all of the positives, though, as leasing costs were much lower in the beginning of shale play development with costs from $50 to $500 per acre, compared to current prices of $10,000 to $20,000 per acre. In addition, well completion and drilling costs have increased to between $4 million and $10 million per well.

“In generation 1, many companies made lots of money by selling acreage, forming joint ventures, financing and mergers. In generation 2, the real question is how do companies recoup hundreds of millions of dollars?” Wright said.

The easy answer is optimizing techniques from previous experience developing other wells and shale plays. This includes lateral placement with geosteering and spacing and completion designs such as optimizing stage distance, utilization of different proppant types and concentration. In addition, producers have become more adept at identifying the “sweet spot” in each play and realize now that not every area will be economically productive.

Producers aren’t the only ones benefitting from new methods, as the Energy Information Administration (EIA) has also improved its production metrics. This too has been a two-generation process with the first generation being represented by its “Drilling Productivity Report” (DPR).

“Prior to the shale revolution, drillers targeted either oil or gas formations; production was relatively stable over a long period from each well; and simple rig count was sufficient to monitor and forecast production,” Samuel Gorgen, operations research analyst, office of petroleum, natural gas and biofuels analysis at EIA, said during a presentation at the conference.

However, as producers began to drill in tight formations, it led to high IP rates and steep production declines along with multiple wells from one surface location. In addition, some of these formations also produced both oil and gas.

The EIA’s DPR was first released in October 2013 and was designed to fill in missing data and provide forecasts for six key regions: the Marcellus, Bakken, Eagle Ford, Permian, Haynesville and Niobrara, which have lags in the release of production data. As an example, Gorgen noted that 2013 production data from West Virginia was missing at the time of the conference, but the report was able to provide accurate forecasts by utilizing pipeline flow data.

To improve this report, the agency is expanding its production survey in 2015 by separating 14 states (California, Montana, Colorado, Utah, Kansas, North Dakota, Arkansas, Mississippi, Alabama, Michigan, Ohio, West Virginia, Pennsylvania and New York) from its “other” category while also adding oil and lease condensate production by API gravity and sulfur content categories. This will add 14 states to gas production coverage and 20 states/areas to oil production coverage.

One of the most interesting aspects EIA has found in this reporting has been that declining rig counts do not necessarily indicate a drop in production because less productive rigs are the first to leave an area. “A shift to pad drilling helps improve productivity,” he said.

This has been found in the Marcellus, when the rig count began to drop in 2012, but production continued to climb. “The rig count has stabilized around 100 in the Marcellus, but analysis indicates production will continue to increase,” Gorgen said.

To get an idea of just how different plays can be, Mike Warren, Ph.D., senior vice president of Hart Energy Research & Consulting, noted that his group classifies the Marcellus and Utica shales into six subdivisions because of the differences found within the plays.

These include the Marcellus dry gas in Pennsylvania; Marcellus wet gas in Pennsylvania and West Virginia; vertical drilling in Pennsylvania; the Utica-Ohio; and the Utica-Pennsylvania. Of these subdivisions the ones receiving the most attention from producers are the Marcellus wet gas and the Utica-Ohio. “The Utica-Pennsylvania is still in the starting blocks and the exploratory phase and it will be years before it takes off,” Warren said.

While dry gas drilling isn’t nearly as big a focus, it is still an important part of the region and producers are moving drilling to more economic areas, including northeastern Pennsylvania, with counties west of Susquehanna and Wyoming counties experiencing noticeable drop-offs in activity.

Vertical drilling remains profitable in targeted regions, such as Warren and McKean counties, Pa., according to Warren. As horizontal drilling has become more cost-effective it has been displacing vertical drilling in the state. It is likely that when the shale revolution reaches its third generation of development vertical drilling will be a thing of the past.