Shale has transformed the economics of oil and gas production in the U.S. and is creating an era of lower cost energy. Attractive rates of return are bringing producers to profitable shale plays like bees to a honey pot. Among the keys to those attractive rates of return are high initial production and high cumulative production rates in the early years of typical shale wells. Today we continue our rundown of shale production financial return calculations with a review of well production estimation techniques.
The first episode in this series (see Drilling) discussed “unconventional resources” and conventional hydrocarbon drilling then reviewed the technologies developed by the late George Mitchell and his team to produce unconventional shale resources. In the second episode (see Shale Production Economics – Part 2 – Drilling and Completion Costs) we introduced the eight input factors for our model of production economics and provided example values for drilling and completion costs. In this series we are modeling the economics of shale production with reference to a specific example – the Haynesville Shale. We use the Haynesville because it is a dry gas formation, meaning that only natural gas (“mostly methane”) is produced. That allows us to model the production economics without having to delve into the complexities associated with wet gas (including NGL) or combined crude and gas liquids. These liquid hydrocarbons are, of course very important to many US shale plays today, but once you understand the economic returns on a dry gas well then the liquids produced from wet gas or oil wells can be viewed as an additional uplift dimension to the basic model.
In this third episode we tackle methods to estimate how much gas shale wells will produce over their lifetime. The overall production estimate, known as the estimated ultimate recovery (EUR), as well as the rate of production over time, go a long way toward determining the economic feasibility of a well. Our aim is to give you an understanding of the different ways that planners, analysts and the experts – known as reservoir engineers, go about estimating the lifetime production of a shale gas well as well as its rate of decline over time.
And again as we said last time, these calculations are intended only as approximations. The factors we show are primarily derived from investor publications. We have averaged typical results from the play, so these numbers are not representative of any one producer or area within the Haynesville. Also, the numbers change periodically so these figures may not represent the most recent data being seen by producers in the area. However, they are generally representative of Haynesville economic inputs and thus can be used to understand the way the economic calculations work.
Before we get into the production estimation models, let’s first look at the relationship between three critical variables that determine well production. Those three variables are; the initial production rate (IP – in this context the production rate during the first month), the decline rate (meaning the rate at which production declines over time) and the EUR (meaning the total well lifetime production). The chart below plots the relationship between the daily production curve (blue line, left axis) and the cumulative production curve (red line, right axis) for the lifetime of a typical Haynesville well. This well has a high IP rate of 10 MMcf/d (blue line, first month of production). As is typical for shale wells, the rate of production falls off quickly so that by the end of the first two years it is only about 2.1 MMcf/d. But then the decline curve flattens out, so that by the end of the fifth year (60 months), the well is still producing about 1.1 MMcf/d. Even after 300 months (25 years) the well is still producing.
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