Shale exploration started in earnest in 2004 with just two Marcellus wells drilled. The early stages of shale exploration in the Appalachian Basin included well production estimates based on experience with other shale formations like the Barnett Shale in Texas or Fayetteville Shale in Arkansas. While the early estimates were useful for company's interest in further Marcellus development, the lack of actual production data made estimating production from an Appalachian Basin well somewhat challenging.
Initial production (IP) from a well is used to estimate the potential for future production. A basic view of initial production would suggest the higher the initial well production the more natural gas the well will produce over its lifetime. While IP rate is often a great guide to future production several factors can influence the IP rate, including but not limited to geology, wellbore exposure to the formation, and the number of stages completed. Geology of the formation determines how much natural gas might be available for extraction (technically recoverable reserves). The geologic characterization of the Marcellus does vary considerably, sometimes even on the same well pad. The IP rate may also be influenced by the length of the horizontal wellbore in the shale formation. Basically, the more formation a company has in contact with the wellbore (longer the horizontal lateral), the higher the initial production might be. Finally, the number of wellbore stages completed is also thought to influence initial production. A stage is a length of the wellbore completed at a given time. A typical 5,000 foot horizontal wellbore may include 10-35 stages ranging in length from roughly 100-500 feet each. The influence of the number of horizontal stages on initial and overall production is still a topic of great debate and continued research; however, many (not all) exploration and production companies are trending toward more and shorter stages.
The initial decline, or decrease in production, over the first year of operation of a shale well is an important variable in estimating the potential for future production. Generally, the steeper the first year decline in production, the lower future production estimates will be. By way of example, if a well has an initial production rate of 10 million cubic feet (mmcf) per day, and declines over the first year to 3 mmcf per day, future production estimates need to be based on 3 mmcf per day. The average first year decline rates across Pennsylvania appear to range from approximately 60% to 80%. The initial decline is also referred to as a hyperbolic decline, which is often seen in shale decline curve graphics as the characteristic hockey stick pattern of a steep initial decline. As shale wells remain in production, the volume of natural gas will shift from a sudden rush and rapid decline to a steady exponential decline, represented by the straight portion of the decline model. Both hyperbolic and exponential decline rates can be seen in the average cumulative production/decline curve for Pennsylvania above.
When looking at the lifetime of a shale well, production is often referred to as the estimated ultimate recovery (EUR). Implied in the term EUR is a lifetime of a well, and although most shale wells are still relatively young, analysts generally look at a 20-30 year lifetime for a shale well. Also influencing EUR projections is the dramatic shift in the level of natural gas production from conventional to shale reservoirs.
The scale of natural gas production from shale wells is entirely different than Pennsylvania has seen in the past. In 2004, shale exploration was in its infancy in Pennsylvania with only two shale wells drilled, but not entering the production stream (that year). That same year, more than 30,400 conventional wells reported natural gas production totaling 159.25 billion cubic feet (bcf) or about 430 million cubic feet (mmcf) per day. Jumping ahead 10 years, just over 4,900 shale wells reported producing more than 3.1 trillion cubic feet (tcf) or just over nine bcf per day. The conventional wells remained consistent with 56,000 conventional wells reporting more approximately 190 bcf of natural gas production. The dramatic shift in natural gas production can also be seen in the production across Pennsylvania, with several counties topping 1 tcf of production from horizontal shale wells in just the last 3½ years. With all the available data for wells reporting more than three years of production, some shale wells have only produced a few hundred mmcf while others have topped 10 bcf in actual production. As additional data becomes available, the EUR for shale wells in Pennsylvania will likely change; however, based on current data the majority of wells appear to fall in the EUR range of 4-8 bcf, with exceptional wells capable of far exceeding average expectations.
Given the complexity of natural gas production and to help owners of natural gas rights and businesses make better decisions, Penn State Extension and the Penn State Marcellus Center for Outreach and Research have created a web-based app to look at data across Pennsylvania. To produce the app, the team analyzed 4,000 horizontal shale wells. By looking closely at actual well production, a cumulative production model was assembled to create royalty estimates and better decision making tools for businesses and individuals. A free beta version of the new royalty calculator is available. A subscription version of the app will also be available allowing greater access to county-based data. Check the Penn State Extension website for updates and availability.