Presenters: Rusty Braziel & David Braziel
Natural gas, NGLs and crude oil - the drill bit hydrocarbons - may look different and have different end-use markets, but each of these products share a common production source – the wellhead. And they have something else in common. The economics of extracting these hydrocarbons has been changed radically by shale technologies. Module #2 explores extraction economics and forecasting methodologies for the three drill bit hydrocarbons.
The four videos in Module #2 are:
2.1 The Basics, Unconventional Vs Conventional Production, Price Scenarios, Type Curves and Investment Returns. Unconventional drilling techniques have radically reshaped upstream oil and gas. As these new technologies were coming into their own, $100 oil meant that producers could turn a large profit. However, in today’s landscape, producers’ decisions on whether to drill and complete a well aren’t always as clear cut so an economic analysis must be undertaken to make that determination. To calculate the economics of an individual well, you need to consider the total cost of drilling and completing the well, the cost of moving the hydrocarbons produced from the well to market, and the revenues generated from selling all those hydrocarbons at market prices. Those economics yield producer investment returns, which are the primary drivers of production – both unconventional and conventional.
2.2 Well Cost, Production Rates, Decline Curves & Other Variables. So, what do we need to know to analyze production economics? We need to know the cost of drilling and completing the well, along with the expected operational costs. Next, we need to identify how much of each drill bit hydrocarbon will be produced and on what timeline. Lastly, we must understand how much is due to the tax-man and royalty owners. Only when we can reasonably estimate each of these variables, can we begin to come up with the basis of our economic analysis.
2.3 Model 2.1 Production Economics Single Commodity. In this section, users will be introduced to the first model, Model 2.1, which calculates a producer’s internal rate of return for a well given a set of inputs. Here we will begin with a single-commodity gas well in the Haynesville to illustrate the key points of production economics. Our focus will then shift to our Permian business case where we will calculate economics, again, based on the production of a single commodity which in this case, is oil. Later in Module 6, we will go two steps further into a multi-commodity model.
2.4 Production Forecasts - Concepts and Model 2.2 – Production Forecasting. Section 4 builds on the concepts introduced for the Permian in the previous section and applies many of those same concepts to the next step in our midstream infrastructure analysis – production forecasting. Since the 2014 decline in oil prices, there has been a fragmentation of the economic geography of oil and gas production in the U.S., opening a wide rift between high and low-quality E&P assets. The most sought-after assets have been in the Permian basin where strong initial production rates from stacked plays create a producer’s paradise. This section drills down on a county in the Delaware portion of the Permian showing how those factors can lead to soaring production. In Model 2.2, users will calculate a production forecast for Loving County, Texas. To accomplish this, we will apply the ladder forecast method – a well-by-well build-up of typical production profiles as defined by the typical ARPS type curves for the area.