What Kind of Umpire Is the Pennsylvania Public Utility Commission?

The Social Psychology of Organizing (Weick 1979) is a classic, cited more more than 12,700 times according to Google Scholar. The book opens with a series of vignettes about organizational events. One of my favorites is about balls and strikes:

“The story goes that three umpires disagreed about the task of calling balls and strikes. The first one said, ‘I calls them as they is.’ The second one said, ‘I calls them as I sees them.’ The third and cleverest umpire said, ‘They ain’t nothin’ till I calls them.'” (Simons 1976: 29 as cited in Weick 1979: 1).

What are we to make of this quote? Of course a number of interpretations are possible. But one straightforward interpretation is that the three umpires operate from different ontologies. Or as Michel Callon (1998) proposed: ontologies vary. In this case, the first umpire might be called a positivist; the second an interpretivist; the third a constructivist. Or to be more alliterative: realist, relativist and relationalist.

I thought of this illustration while reading StateImpact Pennsylvania’s description of the Pennsylvania Public Utility Commission (PUC). Among other things the PUC is responsible for assessing fees on spud unconventional gas wells under Act 13 of 2012. In this regard, Pennsylvania Senate President Pro Tem Joe Scarnati, “who shaped the majority of the impact fee, has said he envisions the commission serving as an umpire, ‘calling the balls and strikes’ of whether local regulations fit within the law’s framework.”

That got me thinking: Just what kind of umpire is the PUC?

Act 13 Reporting Paper a Top 10 Download Again

According to SSRN, our paper — An Analysis of Unconventional Gas Well Reporting under Pennsylvania’s Act 13 of 2012 — is once again a top 10 download in several categories, including:

The paper was published in the December issue of Environmental Practice and analyzes the extent to which the Pennsylvania Department of Environmental Protection (DEP) complied with its reporting requirements under Act 13. Using publicly available data, we find that the DEP likely omitted between 15,300 and 25,100 unconventional gas wells from its Act 13 report. Left uncorrected, we estimate that Pennsylvania’s state, county, and municipal governments could forfeit fees of $205-$303 million in 2012 and up to $0.75-$1.85 billion cumulatively over the expected life of these wells. We propose the implementation of a relational database and geographic information system as a way for the DEP to fulfill its Act 13 obligations.

The Ashcroft #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.

Ashcroft #1

In December 1975, St. Joe Petroleum Corporation spud the Richard J. Ashcroft #1 well in Greene Township, Beaver County, ultimately drilling to a total depth of 7,519 feet in the Queenston Shale (Heyman & Cozart, 1978). The Ashcroft #1 was originally drilled as a test of the Lower Silurian Medina Group (Piotrowski & Harper, 1979), and reportedly completed on December 6, 1975. Although there was a slight show of gas, the well was initially shut-in, pending further production tests (Heyman & Cozart, 1978). The well was later plugged back, and, on February 19, 1976, was reportedly completed in the Devonian Rhinestreet shale (Piotrowski & Harper, 1979). However, after being hydraulically fractured, there was no sustained flow, and as of 1979, the well was again reported as shut-in (Piotrowski & Harper, 1979). The Ashcroft #1 was assigned Permit #BEA-20060 (Heyman & Cozart, 1978), now API #37-007-20060 (Ryder, 2004; Ryder et al., 2012; Trippi & Crangle, 2009). See Figure 1.

Figure 1. Ashcroft #1 Gamma Ray Log 

ashcroftlog

Source: Trippi & Crangle, 2009

References

Heyman, L., & Cozart, C. L. 1978. Oil and Gas Developments in Pennsylvania in 1977. Harrisburg, PA: Pennsylvania Geological Survey, Fourth Series, Progress Report 191.

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.

Ryder, R. T. 2004. Stratigraphic Framework and Depositional Sequences in the Lower Silurian Regional Oil and Gas Accumulation, Appalachian Basin: From Ashland County, Ohio, through Southwestern Pennsylvania, to Preston County, West Virginia. Washington, DC: U.S. Geological Survey, Geologic Investigations Series, Map I-2810.

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.

Trippi, M. H., & Crangle, R. D., Jr. 2009. Log ASCII Standard (LAS) Files for Geophysical (Gamma Ray) Wireline Well Logs and Their Application to Geologic Cross Section C-C’ through the Central Appalachian Basin. Washington, DC: U.S. Geological Survey, Open File Report 2009-1021.

The Fleck #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.

Fleck #1

In 1975, Peoples Natural Gas Company spud the James Fleck #1 in Sandy Creek Township, Mercer County, reaching a total depth of 9,246 feet in “Precambrian granite” (Lytle et al., 1977: 23). The well was plugged back and fractured in the Lower Silurian Medina Group from 4,990 to 5,040 feet, discovering the Fleck Pool in the Sheakleyville Field (Lytle et al., 1977). In 1977, the Pennsylvania Geological Survey reported two different completion dates for this well: August 27, 1975, and March 12, 1976, creating indeterminacy as to when these events took place (Lytle et al., 1977). Regardless, initial production was reportedly 231 Mcfgpd, and the well was assigned Permit #MER-20116 (Lytle et al., 1977), or API #37-085-20116 under current nomenclature (Baranoski, 2002). The well was then shut-in (Heyman & Cozart, 1978). According to later reports, “although a significant amount of gas was encountered, it was not deemed sufficient to justify the expense of putting the well on line” (Harper & Abel, 1979: 41).

Around this same time, the Energy Research and Development Administration (ERDA) had launched a five-year study of Devonian organic-rich shales in the Appalachian Basin (Piotrowski & Krajewski, 1977).[1] As it relates to the James Fleck #1, in addition to production from the Medina Group, well logs indicated gas production in so-called Zone I facies, which were then thought to be “approximately equivalent to the Rhine Street Shale of New York” (Piotrowski & Krajewski, 1977: 41). Seizing upon this potential, Peoples Natural Gas Company and the ERDA began negotiating the possibility of using the James Fleck #1 to test the West Falls Formation (Frohne, 1978; Piotrowski & Krajewski, 1977).

These negotiations succeeded, and in March 1978, the newly formed U.S. Department of Energy (DOE) “attempted to stimulate the Rhinestreet facies … by means of a massive hydraulic fracturing treatment” (Harper & Abel, 1979: 41). In preparation for the treatment, the Devonian Shale was perforated with 50 holes between 3,112 and 3,360 feet deep (Frohne, 1978). The planned hydraulic fracturing treatment called for 270,000 gallons of nitrogen-water foam fracturing fluid, 324,000 pounds of sand proppant, and 12 major pieces of fracturing equipment (Frohne, 1978). Additionally, 6 gallons of surfactant, 1 gallon of clay stabilizer, and 44 pounds of calcium chloride per thousand gallons of water were injected with the foam (Frohne, 1978). The job also included 2,000 pounds of flaked benzoic acid to be used as a temporary diverting agent to insure that the entire perforated interval accepted some fracturing fluid (Frohne, 1978). See Table 1 for complete specifications of the planned massive hydraulic fracture treatment.

Table 1. Fleck #1 Massive Hydraulic Fracture Treatment Schedule

fleckmhf

Source: Frohne, 1978

However, during the hydraulic fracturing treatment, unexpectedly high pressures were encountered, as well as a mechanical packer problem, resulting in a catastrophic downhole casing failure (Frohne, 1978). During the curtailed foam frac operation, 1,582,000 SCF of nitrogen gas, 18,500 gallons of water, and 19,700 pounds of sand had been pumped into the well, most of which then rapidly escaped from the fractured interval and returned to the surface. During the flowback, a substantial amount of sand proppant was sprayed over the backside of the well location. Trees about 30 to 50 yards away had coats of sand plastered on trunks and branches, and there was a solid layer of sand over the rear quadrant of the well site (see Figure 1). “This served to illustrate the potential hazards associated with any stimulation effort, as well as the need for good wellhead arrangement and spectator control” (Frohne, 1978: 5).

Figure 1. Fleck #1 Massive Hydraulic Fracture Treatment Schematic

fleckdiagram

Source: Frohne, 1978

Despite extensive remedial efforts, the treatment had to be aborted, and the well was plugged and abandoned (Frohne, 1978; Piotrowski, Cozart, Heyman, Harper, & Abel, 1979; Piotrowski & Harper, 1979). Following these events, the Pennsylvania Geological Survey published another completion record for this well, dated March 16, 1978 (Piotrowski et al., 1979).


[1] The ERDA was created on Oct 17, 1974 as part of the Energy Reorganization Act of 1974. On October 1, 1977, the ERDA was combined with the Federal Energy Administration to form the United States Department of Energy.

References

Baranoski, M. T. 2002. Structure Contour Map on the Precambrian Unconformity Surface in Ohio and Related Basement Features. Columbus, OH: Ohio Department of Natural Resources.

Frohne, K.-H. 1978. Technical Assessment: Massive Foam Stimulation Attempt in Mercer Co., Pa. Washington, DC: U.S. Department of Energy.

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.

Heyman, L., & Cozart, C. L. 1978. Oil and Gas Developments in Pennsylvania in 1977. Harrisburg, PA: Pennsylvania Geological Survey, Fourth Series, Progress Report 191.

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.

Piotrowski, R. G., Cozart, C. L., Heyman, L., Harper, J. A., & Abel, K. D. 1979. Oil and Gas Developments in Pennsylvania in 1978. Harrisburg, PA: Pennsylvania Geological Survey, Fourth Series, Progress Report 192.

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.

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

upperdevonian1977

Source: Piotrowski & Krajewski, 1977

Figure 2. Metropolitan Industry #1 Combined Well Logs

metro1logs

Source: Piotrowski & Harper, 1979

References

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.

Paper on Act 13 Reporting Published

Our paper — An Analysis of Unconventional Gas Well Reporting under Pennsylvania’s Act 13 of 2012 — was published in the December issue of Environmental Practice. According to SSRN, the paper has been among the most frequently downloaded papers in the following categories:

In the paper we analyze the extent to which the Pennsylvania Department of Environmental Protection (DEP) complied with its reporting requirements under Act 13. Using publicly available data, we find that the DEP likely omitted between 15,300 and 25,100 unconventional gas wells from its Act 13 report. Left uncorrected, we estimate that Pennsylvania’s state, county, and municipal governments could forfeit fees of $205-$303 million in 2012 and up to $0.75-$1.85 billion cumulatively over the expected life of these wells. We propose the implementation of a relational database and geographic information system as a way for the DEP to fulfill its Act 13 obligations.

The paper’s findings were reported by several newspapers and industry publications, including the Pittsburgh Post-Gazette and Platt’s Gas Business Briefing.

Another Early Rhinestreet Well

A few months ago I wrote a series of posts about early unconventional wells that appear to have been omitted from the Pennsylvania Department of Environmental Protection’s (DEP) Act 13 report, contrary to requirements.

Today I stumbled across another early Rhinestreet Shale well. According to Tarr (1980, p. 4), in November 1979, in the the northeastern portion of the Lake Erie shoreline the Pennsylvania Department of Environmental Resources (DER), the US Department of Energy (DOE) and the Morgantown Energy Technology Center (METC) “completed the Commonwealth of Pennsylvania [COP], 3 DER Presque Isle State Park, Permit #ERI-20846 [now 37-049-20846] in the Devonian Shale interval 117-1247.5′. The well was bottomed at a total depth of 1276 ft in the Middle Devonian Onondaga Limestone. The well flowed 160 Mcfpd natural from the open hole. Reservoir pressure was 170# psig after being shut-in 33 days. Gas production was obtained from the interval 945-1040 ft in the Upper Devonian Rhinestreet Shale.” In other words, this well qualifies an unconventional gas well under Act 13.

As of 1994, ERI-20846 was one of two gas wells in Presque Isle State Park, then known as the “Marina” well. According to a DER report, the Marina well was completed on October 10, 1979, at a depth of 1,276 feet. It was estimated to heat several buildings (marina, manager’s home, and administration building) for 30 to 40 years. The DER provided $23,000 towards the $200,000 project. This well last reported production in 2006. It was not listed in the DEP’s Act 13 report of spud unconventional gas wells.

The same report noted that the second well — the Beach #7 — was drilled in 1910 by the City of Erie at a depth of 3,572 feet. It was used to run machinery at waterworks park and later abandoned in the 1920s. However, the well was apparently not plugged.

In 1970, a black, foul-smelling surface discharge was reported in the Beach 7 well area. The discharge resulted in the release of hydrogen sulfide gas into the air and other hazardous substances into the soil and shallow ground water near the well. As the odors continued, DER uncovered the pavement overlying the discharge in 1979, and identified the well as the source of the discharge. The discharge was found to be emanating from a deep underground formation called the Bass Island formation.

From 1964 to 1971, over one-billion, ninety-million gallons of wood pulping wastes were injected into the Bass Island formation by the Hammermill Paper Company at wells located approximately four miles to the east of the Presque Isle State Park 7 well. An explanation is that the injected wood pulping wastes flowed along the Bass Island formation and surfaced at the Beach 7 well. [The] Beach 7 well was shut off and plugged in April 15, 1980 to 900 feet of the surface. At that time a substantial amount of gas was found near the surface that did have potential for use.

In September 1983, the Beach 7 well was placed on EPA’s National Priorities List. The National Priorities List consists of hazardous sites across the country where cleanup need’s are so serious as to warrant designation as a Superfund site. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), commonly known as the “Superfund,” was passed by Congress in 1980. The Act addresses the nationwide problem of uncontrolled hazardous sites.

In 1992, EPA delisted the well from the National Priorities List. Restoration work was done on the site.

So, according to this report, wastes injected into a disposal well four miles away traveled from the Bass Island Formation, (which is of Upper Silurian age, and thus, much older and stratigraphically lower than the Marcellus Formation), and a depth of 3,500+ feet, through numerous intervening formations, before finally migrating up the Beach #7 well, with a bottom depth of ~1300 feet. In other words, here is at least one example that suggests fracking fluids may be able to travel laterally and vertically without much difficulty!

Hydraulic Fracturing News Roundup

According to the Wall Street Journal, Baker Hughes Inc (BHI) has warned it is facing a difficult adjustment as companies such as Chesapeake Energy Corp (CHK) retreat from natural gas drilling amid a 10-year low in the commodity’s price. Are the issues unique to Baker Hughes, or will the problems spread to other oil services companies such as Halliburton and Schlumberger?

In Pennsylvania, Judge Keith Quigley of the Commonwealth Court ordered a 120-day halt to provisions of Act 13 of 2012 set to take effect on Monday related to land use and local zoning regulations. The lawsuit, filed by seven Pennsylvania municipalities, accuses the state’s General Assembly of enacting an “unconstitutional” statewide zoning ordinance “by way of an improper use of its police powers and by enacting zoning regulations without consideration of zoning districts, comprehensive plans or how the zoning enactments would serve to protect the health, safety, morals or welfare of local communities.”

Act 13 of 2012 has also the focus of national attention because of concerns it imposes a “gag order” on doctors. Some medical professionals are concerned because they will have to sign a confidentiality agreement in return for access to proprietary information on chemicals used in hydraulic fracturing. The president of the Pennsylvania Medical Society has said the provision could have a chilling effect on research and on doctors’ ability to diagnose and treat patients who have been exposed.

According to Bloomberg, at a conference yesterday U.S. Energy Secretary Steven Chu indicated that the federal government needs to play a larger role in overseeing new technologies for developing oil and natural gas so as to prevent damage to natural resources. “The technology for recovering oil and gas through hydraulic fracturing has really raced ahead,” Chu said. “That’s something I believe that can be developed very responsibly. There has to be a regulatory role because there may be some people who want to cut corners.”

On the heels of Secretary Chu’s statement, President Obama released an executive order that will coordinate the administration’s activities on natural gas. The order creates a working group that includes various White House offices such as the Council on Environmental Quality and National Economic Council, as well as relevant cabinet departments and agencies like Interior, EPA and Department of Homeland Security.

Developed by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission, FracFocus.org turned one year old this week. About 130 companies have logged the chemicals used in hydraulic fracturing of more than 15,000 wells over the past year. The site has been visited by about nearly 150,000 unique visitors. Officials for the website estimate that 75 percent of all wells drilled in the United States are logged on FracFocus, based on scrutiny of a recent Baker Hughes‘ monthly rig report.

In New York, Ulster County executive Mike Hein issued an executive order today to prevent the spreading of brine from hydraulic fracturing on any county-maintained roads, including “the purchase of any liquid waste product from hydraulic fracturing operations (fracking waste brine) or the use of such fracking brine by any part of Ulster County government.”

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

act13shales

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).

DEP May Have Omitted at Least $49 Million in Medina Group Unconventional Well Fees

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 at wells in the Medina Group. In Northwestern Pennsylvania the Medina Group consists of three lower Silurian-aged members: Grimsby Sandstone, Cabot Head Shale, and Whirlpool Sandstone.

Figure 36 of Oil and Gas Developments in Pennsylvania in 1987 provides summarized records of 391 well completions that penetrated formations of Middle Devonian age or older (i.e., to the Marcellus Formation or lower). The majority of these wells were categorized as producing from the Medina Group. Details on the depths to and thicknesses of each of these three members, together with the depths of the producing interval, were provided for approximately 350 Medina Group completions. Using these data it is simple (if tedious) to calculate whether or not the Cabot Head Shale was completed. If my math is correct, 198 out of 350 Medina Group wells were completed in the Cabot Head Shale.

The Appalachian Basin Tight Gas Reservoirs Project, a three-year project sponsored by the U.S. Department of Energy and undertaken by the West Virginia Geological and Economic Survey and the Pennsylvania Geological and Topographic Survey, reported on 10,906 Medina completions in Pennsylvania through approximately 2007. Assuming the ratio of Cabot Head Shale to Medina Group wells from 1987 holds for other time periods, this would suggest approximately 6,170 Cabot Head Shale completions.

This is significant, because any well completed in the Cabot Head Shale meets Act 13′s definition of an unconventional well, and thus, is required to pay unconventional impact fees. Assuming these wells were all vertical, that would be a fee of at least $8,000 for 2011, or a total of more than $49 million in impact fees due under Act 13. And yet, none of these wells were included in the Pennsylvania Department of Environmental Protection’s reports to the Pennsylvania Public Utility Commission as required by Act 13.

As startling as this oversight is, the above estimate likely understates the number of Medina Group wells liable for unconventional impact fees. First, I have been overly conservative in my calculations —  only including wells that explicitly completed the Cabot Head Shale. In many cases the wells reported in 1987 were completed to within a foot or so of the Cabot Head Shale. Because the Medina is generally more than 2,000 feet below the surface, any hydraulic fracturing of the Grimsby Sandstone or the Whirlpool Sandstone will grow vertically, and therefore, penetrate and produce from the Cabot Head Shale. In that case, the number of unconventional wells may include every Medina Group well ever completed. If so, the impact fees due under Act 13 would grow to more than $87 million.

Second, I have only reported on completed wells, but Act 13 requires that impact fees be paid on all spud unconventional wells. A well is spud the moment drilling begins. As a consequence, the number of spud wells is likely to be meaningfully higher than the number of completed wells, but so far I have not found a data source that would allow me to reliably estimate the ratio of spud wells to completed wells for the Medina Group during this time period. Whatever this ratio turns out to be, it simply adds to the magnitude of the reporting failures by the Pennsylvania Department of Environmental Protection.

Third, to estimate the total population of Medina Group wells I used the well database generated by the Appalachian Basin Tight Gas Reservoirs Project. But it is likely that this is actually not the population of Medina wells, but only a sample of them. To the extent that more than 10,906 Medina wells were spud in Pennsylvania in the Cabot Head Shale, then my estimate of the impact fees due is too low.

In sum, my analysis suggests the operators of Medina Group wells collectively owe a minimum of $49 million to $87 million in unconventional well impact fees under Act 13, and the total could be much higher. And yet none of these wells has been reported as required by the Act.