How to Screen Unconventional Shale Projects
by John L. Graves and Bill Vail
NAPE The Magazine for Dealmakers, Fall 2024
IT’S OLD NEWS THAT THE RISE OF UNCONVENTIONAL development techniques, such as horizontal drilling and hydraulic fracturing, revolutionized the oil and gas industry. Those methods unlocked vast resources previously deemed uneconomical, offering lucrative investment opportunities. Moreover, reservoir targets in shale and tight formations dramatically diminished the uncertainties associated with conventional developments. Yet, there remain risks and complexities requiring thorough screening before making investment commitments. This article outlines key steps and considerations for screening investments in unconventional shale prospects.
UNDERSTANDING UNCONVENTIONAL RESOURCES
Since the breakthrough in the Barnett Shale roughly 20 years ago, the combination of horizontal drilling and multistage hydraulic fracturing has revolutionized our industry. Horizontal drilling succeeds by exposing the wellbore to thousands of feet of reservoir rock. As the technology has improved, lateral lengths have steadily increased from 5,000 to 15,000-foot sections. Engineering has excelled in drilling longer sections of horizontal wellbore with faster penetration rates for fewer dollars spent. These improvements have freed up funds for subsequent stimulations
Hydraulic fracturing has also played its part, multiplying the reach of the wellbore from thousands of linear feet to hundreds of fracture faces, each with thousands of square feet of reservoir exposure. Injecting fluids and proppants under high pressure into rock formations to create fractures dramatically improves the deliverability of the completions in a number of ways. Obvious design enhancements include increases in the number of stages per well, the volume of fluid injected per foot of completion and the amount of total injected sand. As more complex fracturing procedures emerged, tens of thousands of wells proved that they could deplete vast quantities of reservoir rock at producing rates that justified the substantial expenses.
KEY CONSIDERATIONS FOR SCREENING DEALS
So where are the risks and uncertainties to be found when thousands of horizontal wells have already succeeded? As most reservoir engineers will tell you, there can be a noticeable discrepancy between the best and the worst completions in an unconventional resource play, whether oil or gas. The chances of a horizontal well completion resulting in a dry hole are remarkably small. On the other hand, the poorest performers of a known resource play will not return their drilling and completion costs, even though the average well is expected to do so. If you cannot avoid drilling and completing one of the lesser performing wells in any given sample, then you need to prepare yourself for the worst. The reason that the major operators in the largest basins can realize robust financial returns is because they stay committed to the development of hundreds of horizontal wells, where the results from the best wells are blended together with the lesser returns from poor to mediocre wells.
Key considerations for screening investment opportunities can be broken down into several categories: geological characterization, engineering and operational assessments, and economic assumptions that drive the financial metrics.
GEOLOGICAL CHARACTERIZATION
Addressing the geology first, we believe that the top oil and gas operators thoroughly examine the geological subsurface in order to identify “sweet spots” that represent the best potential for high-performing completions. Potential investors should analyze important characteristics that include studies of regional structure, the presence of regional faults, formation stresses that influence wellbore orientation, formation continuity and reliable correlations of stratigraphy.
For instance, nomenclature within a formation can be important. Many completion reports that are provided to state regulatory agencies are not specific enough for detailed characterizations. We encourage the creation of regional cross sections where different zones within a known formation can be identified. A good example where secondary zones are important within the larger section is the Wolfcamp formation in the Permian Basin. Many completions are found in different subsections where the labels are Wolfcamp “A,” “B,” “C,” “XY,” etc., usually labeled from shallowest to deepest. Not all completions labeled “Wolfcamp” in the state records are going to be comparable.
Another example of geologic characterization that could have a direct effect on well performance is the presence of natural fractures. Consider the resurrection of the Austin Chalk play in South Texas. This play was the granddaddy of horizontal drilling, where the application of horizontal drilling was improved upon and made commercial in the 1980s. The industry’s return to the Chalk in the last 10 years is primarily a function of exploiting its natural fracture systems. Another good example is the Marcellus Shale in Pennsylvania. As soon as the Marcellus was considered a gas play comparable to the Barnett Shale, experts in Appalachian geology identified the regional faulting and cleat systems found in Marcellus outcrops. These insights led to significant improvements in well deliverability in large portions of the play.
Geological characterization can also apply to the fluid properties in the formation as well as the rock properties. Several plays like the Eagle Ford Shale in Texas have three or more fluid “windows.” The windows refer to the reservoir fluids in situ where a specific phase, gas or oil, is proved to produce. In the Eagle Ford Shale play, there also exists a third “window,” a transition zone, between the oil and gas windows where the reservoir produces rich gas. With rich gas, natural gas processing leads to the sale of natural gas liquids, an important component of the well’s revenue stream. And if this aspect of unconventional resources isn’t confusing enough, the Eagle Ford Shale gas window is typically downdip from the rich gas and oil windows, the exact opposite of what one might find in a conventional hydrocarbon reservoir. Geologists familiar with an area should be able to explain this phenomenon and map where the different fluid “fairways” are located.
ENGINEERING ASSESSMENTS
When satisfied with the geological characterization, investors should turn toward an engineering and technical analysis of the potential investment. The next question to be addressed: How successful were previous completions in the targeted reservoir? The most valuable engineering dataset that can be compiled is a database of the estimated ultimate recoveries for as many wells in the play as possible. EUR is the volume of hydrocarbons produced by a single well over its entire producing life. For a horizontal completion, EUR is found by adding the cumulative production for the subject well to the reservoir engineer’s estimate of future production volumes by phase (oil, gas and water). In short, the reservoir engineer determines a projection of future hydrocarbon volumes that results in the economically recoverable reserves. EURs, revenues and income generated by these volumes over time become the basis for estimated financial returns generated by the initial drilling and completion investment.
