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!

What If Words Meant Things?

In an earlier post, I asked: Has the DEP has complied with Act 15 of 2010?

Specifically, Act 15 required: 1) well operators to file initial Marcellus Shale production reports covering the preceding calendar year with the Pennsylvania Department of Environmental Protection (DEP) on or before August 15, 2010; 2) subsequent semi-annual reports to be filed with the DEP on or before February 15 and August 15 of each year; and 3) the DEP to make these reports publicly accessible on the department’s internet website beginning November 1, 2010.

However, contrary to the requirements of Act 15, the DEP never published a report covering the “preceding calendar year” (meaning 2009). Nor did the department publish reports covering the subsequent semi-annual period of January 1, 2010, to June 30, 2010. Act 15 required both reports to be submitted by operators to the DEP by August 15, 2010, and for these reports to be published by the department by November 1, 2010.

In light of these apparent violations of Act 15, I emailed the DEP on April 18, 2012 to inquire about the matter. Yesterday, I received a response from Kurt Klapkowski, the Director of the Bureau of Oil & Gas Planning and Program Management within the Office of Oil and Gas Management in the Department of Environmental Protection.

It turns out that according to the DEP, the meaning of “preceding calendar year” is open to interpretation. Below is an excerpt from the email response:

Section 212(a.1) required that the initial Marcellus production report be filed on or before August 15th, 2010 and that it include production data from the preceding calendar year.  The Department interpreted this language to mean that the initial Marcellus report was to include production data from the preceding 12 month period.  This would include the two preceding semiannual periods (07/01/2009 through 12/31/2009 and 01/01/2010 through 06/30/2010).  The next Marcellus production reports due on February 15, 2011, would include only data from that preceding semiannual period (07/01/2010 through 12/31/2010).

I wondered, is “calendar year” an ambiguous term, one open to several plausible interpretations? Not according to the Internal Revenue Service: “Calendar Year — A calendar tax year is 12 consecutive months beginning January 1 and ending December 31.” Wikipedia offers a similar conclusion: “Generally speaking, a calendar year begins on the New Year’s Day of the given calendar system and ends on the day before the following New Year’s Day.”

Perhaps Pennsylvania is on a unique “calendar system”? Actually, no. Like most of the Western world, Pennsylvania follows the Gregorian calendar. For instance, the Pennsylvania Department of Revenue appears to agree that a calendar year starts on January 1. Similarly, the Pennsylvania Code uses the term “calendar year” some 300 times. However, its meaning must be sufficiently obvious and taken for granted, as no where in the first 20 results could I find a definition of the term. Apparently, readers are assumed to know a calendar year when they see one.

In short, it is difficult to find any support for the DEP’s decision to “interpret” the term “calendar year” to meaning anything other than January 1 to December 31.

But what of the DEP’s actual interpretation? According to the Director, the DEP interpreted “preceding calendar year” to mean “production data from the preceding 12 month period. This would include the two preceding semiannual periods (07/01/2009 through 12/31/2009 and 01/01/2010 through 06/30/2010).”

However, basic mathematics together with a review of the legislative history of Act 15 of 2010 suggest that this interpretation has no credibility whatsoever.

Prior to becoming law, Act 15 of 2010 was known as Senate Bill 297. It was introduced by Pennsylvania Senators Yaw, Baker, Pileggi, Rafferty, Wonderling, Browne, Costa, O’Pake, Alloway, Vance, Earll and Smucker on February 24, 2009 and referred to the Senate’s Environmental Resources and Energy Committee. The Bill was amended by the committee on May 5, 2009, at which point it went up for consideration. On June 8, 2009, upon third consideration, the Senate passed the Bill by a vote of 47-0.

The Bill then went to the Pennsylvania House where it was referred to the House’s Environmental Resources and Energy Committee. On January 26, 2010, the House considered an amended version of the Bill, and on March 10, 2010, upon third consideration, the Bill was passed by a vote of 195-0. At this point it went back to the Senate for re-consideration, where it was passed again, this time by a vote of 50-0 on March 16, 2010. Finally, Senate Bill 297 was presented to then Pennsylvania Governor Ed Rendell, who signed the Bill into law on March 22, 2010, at which time it became known as Act 15 of 2010.

How could a law enacted on March 22, 2010, possibly intend for the term “preceding” to refer to the time period July 1, 2009 to June 30, 2010 — as the latter months of this time period had not yet even occurred at the time of the Bill’s passage, and therefore, had no way of “preceding” the legislation? Quite obviously this was not what the Act intended.

In short, it appears that the DEP has failed to comply with Act 15 of 2010. The July 1, 2009 to June 30, 2010 time period neither precedes the passage of Act 15 of 2010, nor qualifies as a calendar year. As a result of these failures, it is not possible to accurately calculate the production of Marcellus-related natural gas back to January 1, 2009, as required by Act 15.

Has the DEP Complied with Act 15 of 2010?

In March 2010, then Pennsylvania Governor Ed Rendell signed Act 15 of 2010 into law, amending Section 212 of the Oil and Gas Act of 1984, in part, as follows:

(a.1) Every operator of a well which produces gas from the Marcellus Shale formation shall file with the department, on a form provided by the department, a semi-annual report specifying the amount of production on the most well-specific basis available. The initial report required under this subsection shall be filed with the department on or before August 15, 2010, and shall include production data from the preceding calendar year. Initial reports shall also specify the status of each well; however, in subsequent reports, only changes in the status must be reported. Subsequent semi-annual reports shall be filed with the department on or before February 15 and August 15 of each year and shall include production data from the preceding reporting period. The Commonwealth shall have the right to utilize such information in enforcement proceedings, in making designations or determinations under section 1927-A of the act of April 9, 1929 (P.L.177, No.175), known as The Administrative Code of 1929, or in aggregate form for statistical purposes. Beginning November 1, 2010, the department shall make the reports available on its publicly accessible Internet website. Any costs incurred by the department to comply with the requirements of this subsection shall be paid out of the fees collected under section 201(d).

In response to Act 15 of 2010, the Pennsylvania Department of Environmental Protection (DEP) created the DEP Oil and Gas Electronic Reporting website. As of today, the website makes available a total of 16 production and 16 waste reports, as shown below.

YEAR REPORTING PERIOD MONTHS
2011 Jan – Dec 2011 (Annual O&G, without Marcellus) 12
2011 Jan – Jun 2011 (Marcellus Only, 6 months) 6
2011 Jul – Dec 2011 (Marcellus Only, 6 months) 6
2010 Jan – Dec 2010 (Annual O&G, without Marcellus) 12
2010 Jul – Dec 2010 (Marcellus Only, 6 months) 6
2010 Jul 2009 – Jun 2010 (Marcellus Only, 12 months) 12
2009 Jan – Dec 2009 (Annual O&G, with Marcellus) 12
2008 Jan – Dec 2008 (Annual O&G, with Marcellus) 12
2007 Jan – Dec 2007 (Annual O&G, with Marcellus) 12
2006 Jan – Dec 2006 (Annual O&G, with Marcellus) 12
2005 Jan – Dec 2005 (Annual O&G, with Marcellus) 12
2004 Jan – Dec 2004 (Annual O&G, with Marcellus) 12
2003 Jan – Dec 2003 (Annual O&G, with Marcellus) 12
2002 Jan – Dec 2002 (Annual O&G, with Marcellus) 12
2001 Jan – Dec 2001 (Annual O&G, with Marcellus) 12
2000 Jan – Dec 2000 (Annual O&G, with Marcellus) 12

However, contrary to the requirements of Act 15, the DEP did not publish a report containing “production data from the preceding calendar year” (meaning January 2009 to December 2009) by November 2010. In fact, it is now nearly 18 months after the deadline imposed by Act 15 of 2010, and the DEP has yet to comply with the Act’s requirements. Additionally, the DEP has yet to publish a “subsequent semi-annual report” for the period January 2010 to June 2010. Operators were to have reported this information to the DEP by August 15, 2010, and the DEP was to have published it by November 2010.

In short, the DEP appears to be in violation of Act 15 of 2010. As a result of these reporting failures, it is not possible to accurately determine the production of Marcellus wells (and under Act 13 of 2012, all unconventional wells).

Separate from these potential failures to adhere to the Act’s requirements, in analyzing the reports that are available, we have uncovered some possible data quality and integrity problems. For instance, numerous identical wells are included in both Marcellus and Non-Marcellus reports (i.e., the same well is included in 2011-0, 2011-1, 2011-2). How can the same well be both a Marcellus well and a Non-Marcellus well during the same reporting interval? Obviously it cannot.

Even more alarming, we have encountered potential data integrity problems. For instance, some wells are included in all three 2011 production reports, but report discrepant quantities and days of production. For example, according to the “Marcellus” reports Well No. 059-24798 produced 802,211 Mcf of gas and was on production for 364 days. But according to the “Non-Marcellus” report, this well produced 707,758 Mcf of gas and was on production for 365 days. That is an approximately 95,000 Mcf discrepancy between the two reports. So how much gas did this well really produce? Finally, in addition to the ambiguity over whether this well is a Marcellus well or not, it is not consistently reported as a horizontal or vertical well.

API OPERATOR  GAS MCF DAYS MARCELLUS HORIZONTAL SOURCE
059-24798 RANGE RESOURCES 325,441 183 Y N Jul – Dec 2011
059-24798 RANGE RESOURCES 476,770 181 Y Y Jan – Jun 2011
059-24798 RANGE RESOURCES 707,758 365 N N Jan – Dec 2011

I have brought these issues to the attention of David Raphael, Chief Counsel for the Office of Chief Counsel in the Department of Environmental Protection, but have yet to receive word on when these reporting deficiencies and data integrity problems might be corrected.

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.