The Metropolitan Industry #1

Another example of a spud unconventional gas well omitted from the Pennsylvania Department of Environmental Protection’s Act 13 report, this one in the West Falls Formation.

Metropolitan Industry #1

In 1975, Quaker State Oil Refining Corporation completed the Metropolitan Industry #1 in Darlington Township, Beaver County, as a test of the Lower Silurian Medina Group (Harper & Abel, 1979; Lytle, Piotrowski, & Heyman, 1976; Piotrowski & Harper, 1979). The well was drilled to a total depth of 6,666 feet in the Queenston Shale (Lytle, Heyman, Piotrowski, & Krajewski, 1977; Lytle, Piotrowski, et al., 1976). After no gas was encountered in the Medina, the well was plugged back to test the Upper Devonian shale (Harper & Abel, 1979; Lytle, Piotrowski, et al., 1976). There was no natural production from the shale, but after hydraulic fracturing from just above the Onondaga limestone to above the Tully limestone the well initially produced 150 Mcfgepd (Harper & Abel, 1979; Lytle et al., 1977; Lytle, Piotrowski, et al., 1976; Piotrowski & Harper, 1979).

At the time, the Pennsylvania Geological Survey claimed the well “could be a most significant discovery” (Lytle, Piotrowski, et al., 1976: 25), and credited it with discovering the Darlington Field. This enthusiasm proved to be short lived, however, as production declined each day, and by the end of 30 days the well was non-productive (Lytle et al., 1977). “When shut-in, pressure would build up, but on opening up the well, it would blow off to nothing in a short time. Evidently, there was very little original fracture porosity. Gas accumulated mainly in fractures induced when the well was completed by hydraulic fracturing” (Lytle et al., 1977: 23). The well was eventually plugged and abandoned (Piotrowski & Harper, 1979).

Despite being completed on February 6, 1975, “the [well] record was not received until 1976” (Lytle, Piotrowski, et al., 1976: 25–26). In 1977, some two years after it had been completed, the state published the well record (Lytle et al., 1977). The well was originally assigned Permit #BEA-20054 (Lytle et al., 1977). Under current nomenclature, the Metropolitan Industry #1 is known as API #37-007-20054 (Hosterman & Whitlow, 1983; Ryder et al., 2012).

Initially, the Metropolitan Industry #1 was described as having been completed in the Upper Devonian shale (Lytle, Piotrowski, et al., 1976). The following year the Pennsylvania Geological Survey reported the well produced from so-called Zone I facies, “the second major black shale unit in Pennsylvania” (see Figure 1), which was thought to be “approximately equivalent to the Rhine Street Shale of New York” (Piotrowski & Krajewski, 1977: 41). By 1978, the Metropolitan Industry #1 was considered to produce from the “Rhinestreet shale facies” (Harper & Abel, 1979: 38). Finally, by 1979, it was shown that the well completed and produced from the West Falls, Sonyea, and Genesse Formations (see Figure 2) (Piotrowski & Harper, 1979).

Figure 1. Upper Devonian Cross Section Circa 1977


Source: Piotrowski & Krajewski, 1977

Figure 2. Metropolitan Industry #1 Combined Well Logs


Source: Piotrowski & Harper, 1979


Harper, J. A., & Abel, K. D. 1979. Devonian Shale Research in Pennsylvania: An Update. In R. G. Piotrowski, C. L. Cozart, L. Heyman, J. A. Harper, & K. D. Abel (Eds.), Oil and Gas Developments in Pennsylvania in 1978: 34–43. Harrisburg, PA: Pennsylvania Geological Survey, Fourth Series, Progress Report 192.

Hosterman, J. W., & Whitlow, S. I. 1983. Clay Mineralogy of Devonian Shales in the Appalachian Basin. Washington, DC: U.S. Geological Survey.

Lytle, W. S., Heyman, L., Piotrowski, R. G., & Krajewski, S. A. 1977. Oil and Gas Developments in Pennsylvania in 1976. Harrisburg, PA: Pennsylvania Geological Survey, Fourth Series, Progress Report 190.

Lytle, W. S., Piotrowski, R. G., & Heyman, L. 1976. Oil and Gas Developments in Pennsylvania in 1975. Harrisburg, PA: Pennsylvania Geological Survey, Fourth Series, Progress Report 189.

Piotrowski, R. G., & Harper, J. A. 1979. Black Shale and Sandstone Facies of the Devonian “Catskill” Clastic Wedge in the Subsurface of Western Pennsylvania. Washington, DC: U.S. Department of Energy.

Piotrowski, R. G., & Krajewski, S. A. 1977. Devonian Shale Research in Pennsylvania. In W. S. Lytle, L. Heyman, R. G. Piotrowski, & S. A. Krajewski (Eds.), Oil and Gas Developments in Pennsylvania in 1976: 33–42. Harrisburg, PA: Pennsylvania Geological Survey, Fourth Series, Progress Report 190.

Ryder, R. T., Trippi, M. H., Swezey, C. S., Crangle, R. D., Jr., Hope, R. S., Rowan, E. L., et al. 2012. Geologic Cross Section C–C’ through the Appalachian Basin From Erie County, North-Central Ohio, to the Valley and Ridge Province, Bedford County, South-Central Pennsylvania. Washington, DC: U.S. Geological Survey, Scientific Investigations Map 3172.

What Counts as an Unconventional Gas Well Spud?

As I have delved deeper into Act 13 of 2012, I’ve realized that one critical question is: what counts as an unconventional gas well spud?

According to Act 13 an unconventional gas well fee is “imposed on every producer and shall apply to unconventional gas wells spud in this Commonwealth regardless of when spudding occurred. Unconventional gas wells spud before the fee is imposed shall be considered to be spud in the calendar year prior to the imposition of the fee… (Ch. 23 §2302(b)).”[1]

The population of wells liable for these fees is circumscribed by three interdependent definitions (see Ch. 23 § 2301). First, a spud is “the actual start of drilling of an unconventional gas well.” Second, an unconventional gas well is “a bore hole drilled or being drilled for the purpose of or to be used for the production of natural gas from an unconventional formation.” Third, an unconventional formation is “a geological shale formation existing below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval where natural gas generally cannot be produced at economic flow rates or in economic volumes except by vertical or horizontal well bores stimulated by hydraulic fracture treatments or by using multilateral well bores or other techniques to expose more of the formation to the well bore.”

Criterion 1: Formation Geology

One critical determinant of unconventional gas well fees is formation geology – wells spud in shale formations below the base of the Elk Sandstone or its stratigraphic equivalent. The Elk Sandstone is late Devonian-age, or more than 360 million years old (Ma) (Carter, 2007). Accordingly, shale formations older than the Elk Sandstone qualify as unconventional formations under Act 13. In Pennsylvania, at least 12 formations containing 19 different shale members meet this requirement according to recent subsurface nomenclature (see Table 1).[2]

Table 1. Shale Formations in Pennsylvania Below the Elk Sandstone


Source: Gehman et al., 2012

Criterion 2: Well Timing

The second determinant of unconventional gas well fees is well timing – any unconventional well spud regardless of when spudding occurred. Devonion-age shales have been spud in Pennsylvania since at least 1860, the year after the famous Drake well. Since the 1880s, formations older than Upper Devonian-age have been drilled, with at least 36 wells drilled to the Marcellus Formation or deeper before 1930 (Fettke, 1950).

For instance, in 1889 the Presque Isle Natural Gas Company drilled a well to the Trenton Limestone (i.e., penetrated all 12 formations listed in Table 1). Starting in 1930, exploration of formations older than Upper Devonian grew dramatically, with 559 such wells drilled from 1930-1949 and another 1,391 drilled from 1950-1959 (Fettke, 1950, 1956; Lytle et al., 1961).[3] Thus, Act 13 requires that fees be imposed on unconventional gas wells drilled, even as far back as 1860, with a subset of these wells more visible and prevalent from 1930 onward.

Criterion 3: Spud Interval

The final determinant of unconventional gas well fees is spudding – the start of unconventional gas well drilling. In the oil and gas industry spudding is clearly differentiated from completion and production, both of which are activities that can only occur, if at all, after spudding. Indeed, not all spud wells are completed or placed in production.

By anchoring its definition of an unconventional well on spudding, Act 13 requires that unconventional gas wells be identified without reference to completion or production activities – as wells may never undergo such activities. But in that case, how does one differentiate unconventional and conventional wells, as both are essentially identical at the start of drilling?

Option 1 is to differentiate between two spud dates – the start of surface drilling and the start of subsurface unconventional shale drilling. Thus, unless and until a well penetrates a shale formation below the Elk Sandstone or its stratigraphic equivalent it would not qualify as an unconventional gas well spud. Although Act 13 does not explicitly distinguish between surface and subsurface drilling, this distinction is implicit in the Pennsylvania Department of Environmental Protection’s (DEP) (2012a) interpretation of Act 13:

An unconventional gas well is a well that is drilled into an unconventional formation, which is defined as a geologic shale formation below the base of the Elk Sandstone or its geologic equivalent where natural gas generally cannot be produced except by horizontal or vertical well bores stimulated by hydraulic fracturing.

In other words, once a well is drilled into a shale formation below the Elk Sandstone it counts as an unconventional gas well. Because one or more unconventional shales (i.e., formations 1 through 3 in Table 1) occur throughout the areal extent of Pennsylvania’s extant oil and gas production, the population of wells liable for unconventional gas well fees under this interpretation would minimally include any wells that penetrate the Tully Formation, as there is no way to reach this formation without first going through (i.e., spudding) an unconventional shale. By way of example, all 1,986 deep wells known to have been drilled before 1960 would owe unconventional gas well fees under this interpretation, plus any similar wells drilled since then. Additionally, any wells spud in the three formations described above would be liable for fees, whether or not they reached the Tully Formation.

Option 2 is to only count wells as unconventional spuds if the formation targeted for production is an unconventional formation. In other words, spudding an unconventional shale formation en route to a deeper formation would not automatically result in unconventional well fees. Instead, only in cases where the intended production formation contained shale would the well be liable for unconventional gas well fees. Under this interpretation any wells ultimately spud in any of the 12 formations listed in Table 1 would owe unconventional gas well fees.

Finally, for analysis purposes only, Option 3 would entail counting wells that have been spud and completed in an unconventional shale formation. This is a far more stringent standard than Act 13 requires, and thus, violates its requirements. Nonetheless, such an approach may be analytically useful in establishing the minimum number of unconventional well spuds that any complete analysis would have to exceed to be credible. Said another way, any report from the DEP to the Pennsylvania Public Utility Commission (PUC) with less than this number of wells is necessarily deficient.

Together these three criteria – geological age, well timing, and spud interval – determine the population of wells subject to unconventional gas well fees under Act 13 of 2012. The scope of these requirements can be visualized by constructing a matrix of the 12 formations by the 152 years (1860-2011) over which unconventional gas exploration in Pennsylvania has potentially occurred, resulting in a total of 1,824 formation-years.

In sum, it is not possible to calculate the total unconventional gas well fees due under Act 13 without first determining the number of unconventional wells spud in each and every one of these 1,824 formation-years. Obviously, the results of this calculation are likely to vary considerably depending on which of the three spud interpretations is utilized.

[1] Under Act 13 the PUC is responsible for determining the fee an operator owes based on several factors, including whether the well is vertical or horizontal, the average annual price of natural gas, the age of the well, and potentially, the urban consumer price index if the number of wells drilled in the current exceeds the number drilled in the preceding year.

[2] This nomenclature was not necessarily operant historically, as a result, any analysis must also consider alternative designations for these formations over time. For instance, the Medina Group (Carter, 2007) was known as the Albion Formation (e.g., see Fettke, 1950) until as late as 1995 (Ryder, 2004).

[3] It is worth noting that already by the middle of 1954, hydraulic fracturing was “used extensively” in Pennsylvania, including in wells to the Oriskany and Medina Formations, among others (Moore, 1955).

More Early Unconventional Wells

This post continues my series on unconventional wells that have been omitted from the Pennsylvania Department of Environmental Protection’s Act 13 reporting, with a look back at some wells from 1979-1981.

Commenting on this period, Patchen et al. (1982: 1958) write: “The Devonion shales of Pennsylvania, which have produced gas (normally in uncommercial quantities) since 1860, were the target of several successful drilling attempts in 1981.” These drilling attempts resulted in “three new pools discovered in the deeper shale zones, including the Upper Devonian West Falls, Sonyea, and Genessee formations, and the Middle Devonian Marcellus Formation.”

According to the Pennsylvania Geological Survey’s Subsurface Rock Correlation Diagram (Carter, 2007), the West Falls Formation includes the Rhinestreet Shale; the Sonyea Formation includes the Middlesex Shale; the Genessee Formation includes both the Geneseo Shale and the Burket Shale; and of course, the Marcellus Formation includes the Marcellus Shale. All five of these shales are stratigraphically below the Elk Sandstone, and thus, any wells drilled into these formations are subject to unconventional gas well fees under Act 13, CHAPTER 23 § 2302.

One of these wells was the Combustion Engineering Fee #1 well (Permit #003-20980), drilled in Allegheny County on March 25, 1979, and completed that year in the Marcellus and Genesse formations. According the Pennsylvania Department of Environment Protection’s Oil and Gas Reporting website, this well was still producing gas 365 days a year in 2005, 2007 and 2008. But contrary to Patchen et al.’s (1982) report, the well is reported as “N” in the Marcellus Well field.

UPDATE: On February 4, 2015, I received the following email about the Combustion Engineering Fee #1 well.

Joel – Per this article you wrote I was the PM on the job working for Combustion Engineering at the time, and I somehow found this article. The well was fully DOE funded, the only Marcellus we did on it was to do one fracture, at 7,509 feet, that number sticks with me, take a sample to Mellon Institute for testing, and we then re-fractured at the higher sands in order to get enough gas out to heat the facility. The shale was way too tight for 1979 technology! Just thought you may want to know since your article notes there is really no record of Marcellus Production.
Thanks – Bob Necciai

Another two wells were drilled in Clarion County: the Conner #1 well (Permit #031-2076) and the Minich #2 (Permit #031-20864). Both wells were drilled by Gearhart and Odell and completed in the West Falls, Sonyea and Genessee formations (meaning the Rhinestreet, Middlesex, Geneseo and Burket shales). According to the Pennsylvania Department of Environment Protection Oil and Gas Reporting website, the Conner #1 produced gas in 2002, 2004 and 2005. However, these wells were not reported to the Pennsylvania Public Utility Commission by the Department as required by Act 13. I’ve added all three wells to the spreadsheet of missing Act 13 unconventional wells.

Finally, Patchen et al. (1982: 1980) report on three failed exploratory wells drilled to the Helderberg Group and another drilled to the Hamilton Group. Very possibly, these four wells are also liable for Act 13 unconventional gas well fees. The Hamilton Group includes the Marcellus Shale and the Helderberg Group includes the Mandata Shale. These wells included Permits MCK-39885, SOM-20103, TIO-20104 and WES-21705.