UPDATE (5/26/2015; 10:10 am ET): EID was recently contacted by the researchers of this groundwater study, who provided us with further comments on their report. EID has posted these comments in full in the spirit of facilitating an ongoing debate regarding the study.
To read the researchers’ full comments, click here (they are also provided in full at the end of this post). Below are some further observations from EID on the new material provided to us.
Llewellyn et al: “We explicitly state in the paper that there is no evidence that HVHF of the Marcellus Shale at depths of approximately 6000‐7000 feet was the cause of impacts. In fact, we provide strong evidence that this did not happen. When HVHF fluids are injected into the target formation (e.g. Marcellus Shale), they mix with natural formation fluids that contain high levels of dissolved solids (e.g. salt, metals, etc.). Of these, chloride and bromide tend to persist in water and their ratio is an excellent tracer of the chloride source. Examination of the impacted household water well chemistry did not have ratios of chloride: bromide that would indicate impacts from fluids that had migrated from the Marcellus Shale.”
Energy in Depth: This is something that EID pointed out in its original rebuttal of the study. As we said, “the researchers completely rule out the possibility that contamination could have been caused by the hydraulic fracturing process.” However, the researchers do make a number of less-than-perspicuous statements on this point, which caused a great deal of confusion among reporters and readers of the report. Notably they refer to the “possible” detection of HVHF fluids multiple times in the paper and use flowback fluids (which they associate with the HVHF process) as a proxy for the detected contaminants.
“Therefore, we conclude that it is possible that HVHF fluids used at the Welles 1 pad contaminated the drinking water aquifer.” … “The most likely way for HVHF fluids to contaminate the shallow aquifers would therefore be through surface spillage of HVHF fluids before injection or by shallow subsurface leakage during injection.”
The abstract states:
“However, contamination of shallow potable aquifers by HVHF at depth has never been fully documented. We investigate a case where Marcellus Shale gas well wells in Pennsylvania caused inundation of natural gas and foam in initially potable groundwater by several households…The most likely explanation of the incident is that stray natural gas and drilling or HF compounds were driven ~1-3 km along shallow to intermediate depth fractures to the aquifer used as a potable source.”
The passage does not reference the 1-3 km distance as being a horizontal distance, so a reader is left without a clear explanation of what this means.
The study makes this claim in the conclusion:
“In one [homeowner] well, 2-BE was positively identified and is a common constituent of both HVHF and drilling fluids. These impacts were likely caused by drilling or HVHF fluids used in the gas wells.”
This leads to the obvious question: if the researchers were willing to declare definitely in their follow up to EID that “there is no evidence that HVHF of the Marcellus Shale at depths of approximately 6000‐7000 feet was the cause of impacts,” why not go ahead and say that in the actual study?
Finally, several statements attributed to the researchers in the press in the wake of the report’s release also appear to be at odds with key sections of the report text, which, again, found that “contamination of shallow potable aquifers by HVHF at depth has never been fully documented.” For example:
From the Associated Press: “This is the first documented and published demonstration of toxic compounds escaping from uncased boreholes in shale gas wells and moving long distances” into drinking water, said Susan Brantley, one of the study’s authors.
From the New York Times: “This is the first case published with a complete story showing organic compounds attributed to shale gas development found in a homeowner’s well,” said Susan Brantley, one of the study’s authors and a geoscientist from Pennsylvania State University.
From Penn State News: “These findings are important because we show that chemicals traveled from shale gas wells more than two kilometers in the subsurface to drinking water wells,” said co-author Susan Brantley… “The chemical that we identified either came from fracking fluids or from drilling additives and it moved with natural gas through natural fractures in the rock.”
From State Impact NPR: “We can say with confidence that gas migration happens,” said Llewellyn. “These [water] wells were impacted by natural gas, and we’re finding signatures that are very similar to frack flowback samples that Dorman collected.”
Llewellyn et al: “This paper [Smith et al. (2014)] was published in Fall 2014 at approximately the same time we submitted our paper for peer reviewed publication and we were unfortunately unaware of it; otherwise, we would have cited it in our article. Some have made the point that the water well where we identified 2‐BE was a replacement well provided to the homeowners by the gas company. This well was emplaced in an effort to provide the household with potable water immediately following the initial impacts. The well was installed by a local water well driller hired by the gas company. The driller grouted the casing in place with cement using good practice. Given the findings of Smith et al. (2014), we acknowledge that it is possible – but highly unlikely ‐‐ that the foam in this replacement well and the 2‐BE may have originated from this source. For example, in contrast to the small amount of cement used in the replacement well, approximately 42,500 gallons of cement was used to remediate the gas wells at the nearby Welles 3, 4 and 5 pads to alleviate methane migration and casing pressure/well integrity issues. Further, even if the 2‐BE came from the grouting, such a scenario does not explain the presence of the UCM (~1000 hydrocarbon compounds) nor the foam that was observed in both the replacement wells and in the original water wells that had not been cemented. Furthermore, state regulations for public water supply wells actually require cement grout ‐‐ and of course most water wells do not foam as a result.”
Energy in Depth: There have been a number of peer reviewed studies, including Smith et. al, which have noted the presence of 2-BE glycols, organic acids, and other organics in the materials used to construct water and monitoring wells. That these papers were not noted or acknowledged in this report represents a fairly glaring omission.
As EID noted in its original rebuttal of the study, the 2-BE, glycols, phenols, organic acids, and organic compounds were present in the cement materials used to construct monitoring wells by EPA in Pavillion, Wyoming. To its credit, EPA eventually recognized this fact and withdrew the report it had commissioned.
The basic question we’re left with, then, is: which is more likely? Is it more likely that a contaminant originating from the cement used to build the actual well was detected by these researchers? Or is it more likely that the compound detected here migrated through miles of solid rock to contaminate the water in the well? The researchers claim the contaminants were unlikely to have originated from well completion cements, but likely to have come from cements used in the gas wells drilled miles away. Maybe they’re right. But the odds (and the science) certainly don’t support that.
Llewellyn et al: “[S]eptic systems are not a probable source for a number of reasons. The possibility of septic system derived contaminants was one of the first scenarios the authors examined to explain the foam, UCM and 2‐BE in the impacted household wells.”
Energy in Depth: As chronicled in a report commissioned by the Center of Rural Pennsylvania, there are literally thousands of examples of septic systems contaminating local underground sources of drinking water – in northeast Pennsylvania alone. Here, the researchers say that septic systems qua originators of contaminants was “one of the first scenarios the authors examined.” What they actually found from that examination, and how serious they were in actually studying it, is not mentioned.
Llewellyn et al: “In addition to 2‐BE being identified at ng/L concentrations in Well 1, the UCM (comprised of ~1000 individual hydrocarbon compounds) was identified at all wells we sampled (e.g. Wells 1, 3 & 6). Each of the individual compounds that comprise the UCM are also at ng/L concentrations, indicating that the total hydrocarbon concentration is likely at least on the order of μg/L (parts‐per‐billion). Based upon the research of Frank Dorman (coauthor), many natural and synthetic organic compounds can cause foaming at these levels. This is especially the case in the presence of natural gas, because gas facilitates foaming as it bubbles out of the water.”
Energy in Depth: The researchers acknowledge here that “many natural and synthetic organic compounds can cause foaming,” but they do not acknowledge this in their study, aside from a brief mention that dismisses other possibilities, which is buried in the supplemental section.
Further, their research suggests foaming can occur at parts per billion levels, yet the 2-BE was detected at parts per trillion levels, which would suggest that the 2-BE was not the cause of the foaming. And the fact that the foaming in one well stopped is an indication that it is likely related to some other more local source than one occurring miles away. It’s also worth noting that foam from certain garden hoses is very common and widely noted, likely caused by organic plasticizers in the plastic hosing.
Llewellyn et al: “[I]it is indeed likely that these impacts are derived from different sources. We state this explicitly in the paper. There is overwhelming evidence that natural gas migrated from Welles 3‐2H or multiple gas wells present on the Welles 3, 4 and 5 pads: for example, these wells were reported to have excessive annular pressures due to poor construction and subsequent remedial activities (e.g. “cement squeezes”) were successful in reducing sustained annular gas pressures that had contributed to the gas migration to the impacted water wells. Additionally, we summarized three reasonable scenarios for the UCM and the 2‐BE (but also see FAQ 6 above pertaining to 2‐BE). First, the gas company was cited for a pit leak on the Welles 1 pad, and this could therefore implicate a surface‐related release. Second, drilling fluids could have leaked out of one of the gas well boreholes at shallow to intermediate depths. The final scenario is leakage at shallow to intermediate depths of HVHF fluids prior to or during injection at the Welles 1 gas wells – well above the depth of hydraulic fracturing in the shale. We explain the scenarios in our paper.”
Energy in Depth: Again, none of these scenarios appear or were discussed in the actual paper. As EID noted in its original rebuttal, if these compounds came from drilling or HVHF fluids, the researchers would also have found have high levels of chlorides (Cl, Na. Br, DS, and Ba). None of these are present at elevated levels in these wells. How would 2-BE and UCMs show up but not the chlorides?
The researchers’ samples show that chloride, barium, and bromide levels were low, basically at background levels common to the region, reducing the likelihood (significantly) that they came from shale development.
Llewellyn et al: “We also wanted to illustrate the concept of a ‘multiple lines of evidence approach’ for investigating alleged contamination from oil and gas drilling activities. In this case, the PA Department of Environmental Protection (PADEP) determined that adjacent Marcellus shale gas wells (Welles series) had impacted water resources, including the private wells with natural gas. However, no explanation or cause was assigned to the foam identified in the water wells. As a result, we used GCxGC‐TOFMS to further investigate potential causes for the water foaming. Multiple lines of evidence, such as hydrogeologic characterization, the timeline of the gas well construction and remedial activities, GCxGCTOFMS analytical results, natural gas isotopic measurements, and methane migration data were used to draw reasonable conclusions.”
Energy in Depth: The researchers claim to use a “multiple lines of evidence approach” in the study, but the reality is that they ignore lines of evidence, fail to reasonably interpret some evidence, and in other cases, fail to seek evidence for obvious questions:
- The study repeatedly mentions drilling fluids or HVHF fluids as a likely cause even though there is a distinct lack of chlorides or other compounds found in their tests. Given the fact that both drilling fluids and HVHF solutions are both typically high in chlorides (or other markers such as barium in drilling fluids) and the fact that solutions do not spontaneously disassociate from themselves, this is significant oversight.
- The study fails to look for other potential causes of the alleged foaming, including the replacement water wells themselves, naturally occurring organic compounds, on-lot septic systems, or even their own equipment.
- The study ignores well known literature on very similar situations studied by the EPA and others in Wyoming, or other works on 2BEs and other compounds found in cement.
- The lack of more specific analysis of the UCM hydrocarbons makes it difficult to draw any real conclusions. UCM hydrocarbons can be from many different sources.
— Below are the researchers’ comments in full –
Frequently asked questions about the study “Evaluating a groundwater supply contamination incident attributed to Marcellus Shale gas development” by Llewellyn GT, Dorman F, Westland JL, Yoxtheimer D, Grieve P, Sowers T, Humston‐Fulmer E, Brantley SL, 2015 (PNAS, doi: 10.1073/pnas.1420279112).
The information presented below was developed by several of the study’s co‐authors including Garth Llewellyn (Appalachia Hydrogeologic and Environmental Consulting, LLC), Frank Dorman (Penn State), Dave Yoxtheimer (Penn State), and Susan Brantley (Penn State) to provide context for the information presented in the original study.
- Some newspapers reported that no conflict of interest (COI) was noted on the version of the paper that was released by the journal when it was under embargo. In contrast, the published version notes a conflict of interest, i.e. that Llewellyn was paid as a consultant by the homeowners prior to the new research reported in the paper. Why was the COI not on the original version?
The original draft of the paper – “the galleys” –noted there was no COI by any of the authors. This was initially the result of not realizing there was a COI declaration option (i.e. a box to check) during the original submission process. If the COI box is not checked off then the default states there is no COI. The authors sent corrections to PNAS before release of the embargoed paper including a COI declaration when it was realized there was a COI declaration option. It was felt that Mr. Llewellyn’s previous consulting work for the homeowners could be construed as a COI and hence was declared as such. Nonetheless, the paper released under embargo to the media by PNAS did not contain the corrected description of the COI. The official published version of the paper notes correctly that Garth Llewellyn worked for the homeowners as a consultant. There was no intentional “misleading” by the authors or by PNAS. It should be noted that Mr. Llewellyn was no longer working for the homeowners at the time of sampling in Summer and Fall 2012, and that none of the other seven co‐authors had any COI with the study. PNAS released a statement acknowledging the inconsistency to the media that had received the pre‐released version of the paper on May 11, 2015.
The PNAS statement reads, “We apologize for the confusion regarding the conflict of interest statement for the PNAS article “Evaluating a groundwater supply contamination incident attributed to Marcellus Shale gas development,” published online May 4, 2015. When the paper was first received by PNAS, it had no conflict of interest statement. When the authors returned their proofs, they added a conflict of interest statement for the first author. The embargoed version of papers that we prepare for EurekAlert do not include author corrections to proofs. We regret that our process did not relay this conflict of interest information to the media. We are closely examining our process to ensure that such updates are relayed to the media in a timely fashion in the future. The published article with the updated conflict of interest statement is attached.”
- Does this study implicate high‐volume hydraulic fracturing (HVHF) at depth for the observed natural gas, foam, UCM and 2‐BE observed in the homeowner wells?
No. On the contrary, we explicitly state in the paper that there is no evidence that HVHF of the Marcellus Shale at depths of approximately 6000‐7000 feet was the cause of impacts. In fact, we provide strong evidence that this did not happen. When HVHF fluids are injected into the target formation (e.g. Marcellus Shale), they mix with natural formation fluids that contain high levels of dissolved solids (e.g. salt, metals, etc.). Of these, chloride and bromide tend to persist in water and their ratio is an excellent tracer of the chloride source. Examination of the impacted household water well chemistry did not have ratios of chloride:bromide that would indicate impacts from fluids that had migrated from the Marcellus Shale.
- Why did you write this paper? How is this work different from articles already in the public domain discussing these types of issues?
We analyzed this incident largely because foam was consistently observed emanating from household Wells 1 – 6, but commercial laboratory chemical analyses of groundwater samples from the household wells did not detect any typical compounds that would explain the foam. Foam that was observed in the water indicated the presence of compound(s) that warranted further investigation. The authors evaluated existing case data, in addition to conducting further groundwater studies.
We demonstrate the application of a very sophisticated analytical tool, “two‐dimensional gas chromatography with a time‐of‐flight mass spectrometer” (GCxGC‐TOFMS) that provides significant improvements in evaluating alleged cases of oil and gas drilling impacts. This tool allows investigators to detect organic compounds in water at much lower detection limits (parts per trillion) and also to identify them more easily than conventional methods currently used. The development and use of GCxGCTOFMS should be considered by others who want to either confirm or refute alleged oil and gas industry impacts to water resources.
We also wanted to illustrate the concept of a “multiple lines of evidence approach” for investigating alleged contamination from oil and gas drilling activities. In this case, the PA Department of Environmental Protection (PADEP) determined that adjacent Marcellus shale gas wells (Welles series) had impacted water resources, including the private wells with natural gas. However, no explanation or cause was assigned to the foam identified in the water wells. As a result, we used GCxGC‐TOFMS to further investigate potential causes for the water foaming. Multiple lines of evidence, such as hydrogeologic characterization, the timeline of the gas well construction and remedial activities, GCxGCTOFMS analytical results, natural gas isotopic measurements, and methane migration data were used to draw reasonable conclusions. Lastly, we felt that public disclosure of such incidents will help scientists and non‐scientists understand potential impacts, enabling more informed decision‐making by stakeholders.
- Aside from isolated cases, there have not been many reported problems with shale gas wells causing significant water quality problems: why highlight issues that do not appear to be widespread in areas undergoing unconventional shale gas development?
Several of the coauthors on the Llewellyn et al. (2015) paper previously published a peer‐reviewed article emphasizing the rarity of significant, large water quality‐related problems associated with shale gas development as documented in publicly available data (Brantley et al., 2014). However, even these relatively uncommon problems should be investigated thoroughly and discussed openly to make them even less common. An analogy can be drawn to the airline industry: crashes are extremely rare ‐‐ but when they happen, their cause(s) are evaluated to the fullest extent. Given ongoing unconventional oil and gas development, the public controversy surrounding it, and questions about its environmental impacts, the authors argue that information and data describing such events should be communicated to the public and openly discussed. The “social license” of unconventional gas development ultimately depends on the public’s awareness and understanding.
- Aside from natural gas impacts, your paper discusses the presence of a targeted compound, 2‐BE and a “UCM” from samples collected from the household water wells. Why did you specifically look for 2‐BE and what is a “UCM”?
The compound 2‐butoxyethanol (2‐BE) is known to be commonly used in drilling and HVHF fluids. It is an ingredient in at least one common drilling additive (Airfoam HD) as confirmed by the GCxGC‐TOFMS analysis described in the paper. Further, there are confirmed cases as reported by the PADEP of Airfoam HD/2‐BE impacts to water resources as a result of Marcellus gas drilling operations. Airfoam HD was cited by the PADEP as the cause of foam discharging from a spring above the Pine Creek canyon wall in Lycoming Co., PA in 2010. More recently in 2014, drilling fluid additives were also cited by the PADEP for the presence of foam, 2‐BE, glycols and volatile organic compounds (VOCs) identified in a private water well in Springville Twp., Susquehanna Co., PA. As such, we felt it prudent to evaluate for the presence of 2‐BE, given the readily apparent foam emitting from the water wells present at the three households described in the paper.
Besides the presence of 2‐BE in one of the impacted water wells we sampled, a “UCM” or unresolved complex mixture of hydrocarbons was identified in all samples we collected from the impacted households. The UCM is a mixture of ~1000 different hydrocarbons that comprise a “signature” observed in the GCxGC‐TOFMS chromatograms. The hydrocarbon classes range from aliphatic (e.g. they contain no aromatic rings), aromatic (e.g. they contain 6‐carbon aromatic rings), saturated (e.g. no double bonds between carbon atoms), unsaturated (e.g. double bonds between carbon atoms) and oxygen‐substituted hydrocarbons (e.g. they contain –COH, CO and ‐COOH groups). We refer to the UCM as being unresolved since we have not identified each of the individual compounds that comprise the complete UCM signature – we just know that the compounds are present.
We also observed a similar “UCM” signature in various samples of flowback/production fluid samples taken from gas wells throughout the Marcellus Shale region. We did not observe any 2‐BE or “UCM” in background groundwater samples we collected from private water wells in the region that were not impacted by gas drilling activities.
- Are there other potential sources of 2‐BE?
Yes, 2‐BE is used in various products that could be a potential source of the compound. Other uses are described in our article’s Supporting Information. However, given the observed foam from the impacted water wells, the co‐occurrence of 2‐BE, thermogenic methane, and UCM as well as the other lines of evidence presented in our paper and amplified below, we argue that it is highly unlikely that it is derived from a source other than shale gas development.
- A recent peer‐reviewed article by Smith et al. (2014) documents the leaching of 2‐BE from Portland cement used in well construction. Isn’t that a better explanation for the presence of low concentrations (ng/L) of 2‐BE in the well? Why didn’t you cite this paper?
This paper was published in Fall 2014 at approximately the same time we submitted our paper for peerreviewed publication and we were unfortunately unaware of it; otherwise, we would have cited it in our article.
Some have made the point that the water well where we identified 2‐BE was a replacement well provided to the homeowners by the gas company. This well was emplaced in an effort to provide the household with potable water immediately following the initial impacts. The well was installed by a local water well driller hired by the gas company. The driller grouted the casing in place with cement using good practice. Given the findings of Smith et al. (2014), we acknowledge that it is possible – but highly unlikely ‐‐ that the foam in this replacement well and the 2‐BE may have originated from this source. For example, in contrast to the small amount of cement used in the replacement well, approximately 42,500 gallons of cement was used to remediate the gas wells at the nearby Welles 3, 4 and 5 pads to alleviate methane migration and casing pressure/well integrity issues. Further, even if the 2‐BE came from the grouting, such a scenario does not explain the presence of the UCM (~1000 hydrocarbon compounds) nor the foam that was observed in both the replacement wells and in the original water wells that had not been cemented. Furthermore, state regulations for public water supply wells actually require cement grout ‐‐ and of course most water wells do not foam as a result.
- What did the foam look like and when was it observed?
All the authors observed the abundant, white, frothy foam that had a consistency somewhere between foam that one sees when doing the laundry and the foam used as shaving cream. We have included a number of photographs (see Figures 1, 2 & 3) as an addition to the photograph we published in the original paper. The homeowners indicated that foam was not present in their original wells prior to the initial sediment and natural gas impacts observed in July 2010. After the initiation of impacts on the wells, the three households utilized water buffalos that they had been given as a source of potable water; therefore, they cannot recount exactly when the foaming began in their wells. Once the families were given water buffalos, the wells were only used by environmental consultants for the purpose of sampling and we do not have documentation pertaining to all of the observations by the gas company’s consultants. However, first author Garth Llewellyn served as an environmental consultant through his firm for one of the households (owners of Wells 1 and 2) beginning in Spring 2011. During that period Well 2 was not operational and therefore sampling was only conducted for Well 1. Foam was observed in Well 1 during every sampling event on a quarterly basis through Spring 2012. In Spring 2012, Garth Llewellyn and his firm were retained by all three households for consulting services and observed foam in household Wells 1 through 6, when sampling was conducted by his firm at the same time that samples were taken by the gas company’s environmental consultants. Sampling by the authors commenced in Summer/Fall 2012 at which point we observed foam from all the wells we sampled (i.e. Wells 1, 3 and 6). At that point, first author Garth Llewellyn was no longer contracted by the families as a consultant and was helping to conduct the research at his own expense.
- Isn’t it very reasonable that the foam may have originated from equipment used to pump/sample the household water wells?
No. From Spring 2011 through Spring 2012, Garth Llewellyn and his firm, Appalachia Hydrogeologic and Environmental Consulting used dedicated equipment installed by the gas company to pump and sample Well 1. The only additional equipment used was a standard rubber garden hose that was connected to a sampling spigot in order to pump the well prior to sampling and direct water away from the sampling point. Notably, he and his firm have sampled in excess of 1000 households throughout Susquehanna, Bradford and Wyoming counties in PA using this hose or similar hoses for pre‐sample purging without foaming (including wells that did have natural gas impacts). Further, concurrent sampling (splitsampling) was conducted by his firm and a consulting firm contracted by the gas company in late Spring 2012 (Figures 2, 3). During this time, the gas company’s consultant used their own equipment for pumping and sampling the wells and the presence of foam was always observed in all sampled wells (Wells 1 – 6). Finally, the authors observed similar impacts in Fall 2012, when sampling Wells 1, 3 and 6. Given the numerous parties collecting samples at various times with different equipment, it is not reasonable to conclude that equipment was the cause for foam. Notably, the hoses are used for purging (pumping) the well prior to sampling but are not used in the sample collection process itself.
- If the purging/sampling equipment didn’t cause the foam, isn’t the most probable source onsite, given that the impacted households are rural and use onsite septic systems? Couldn’t septic systems also reasonably explain the presence of the UCM and 2‐BE?
No, septic systems are not a probable source for a number of reasons. The possibility of septic systemderived contaminants was one of the first scenarios the authors examined to explain the foam, UCM and 2‐BE in the impacted household wells.
- First of all, two of the authors are professional geologists (PGs) and have extensive practical consulting experience throughout PA. Some private wells in northeast PA do have impacts from onsite septic systems, but none have been observed to “foam”, even with naturally occurring methane that would serve to “agitate” the water.
- The three background wells (outside the area affected by gas drilling impacts) we analyzed exhibited no evidence of foam, the UCM or 2‐BE, despite all having onsite septic systems.
- Septic system impacts to groundwater are characterized by elevated nitrate (>2‐3 mg/L; Panno et al., 2006). Tables 1 – 6 provide water quality data for Wells 1 – 6, respectively, pertaining to chloride, bromide and nitrate concentrations. Notably, Wells 1, 2, 3, 4 and 5 had nondetectable to low nitrate concentrations (maximum of 1.4 mg/L for Well 5). Well 6 had concentrations of non‐detectable to 4.9 mg/L in May and November 2012, respectively. The single elevated nitrate concentration of 4.9 mg/L in November 2012 (Well 6) is inconsistent with septic waste impacts as a plausible explanation because: (1) ubiquitous foam was observed from Wells 1 – 6, (2) the UCM was identified in all sampled wells (e.g. Wells 1, 3 and 6) and (3) 2‐BE was identified in Well 1.
- Figure 3 in Llewellyn et al. (2015) illustrates samples for which Cl:Br ratios are available. The cross‐plot can be used to assist in evaluating the source of chloride present in groundwater. The collective data indicates halite as the probable source (e.g. road salt), which is applied throughout the study area for winter road deicing.
- In your paper, you document very low concentrations (e.g. ng/L or parts‐per‐trillion) of organic compounds (e.g. UCM & 2‐BE). How could such low concentrations of organic compounds cause foaming and are they a health risk?
We cannot comment on the toxicity of the identified UCM and 2‐BE as none of the authors are toxicologists. Furthermore, before health risks can be assessed, one must identify the actual compounds and corresponding concentrations using a broad exploratory approach.
In addition to 2‐BE being identified at ng/L concentrations in Well 1, the UCM (comprised of ~1000 individual hydrocarbon compounds) was identified at all wells we sampled (e.g. Wells 1, 3 & 6). Each of the individual compounds that comprise the UCM are also at ng/L concentrations, indicating that the total hydrocarbon concentration is likely at least on the order of μg/L (parts‐per‐billion). Based upon the research of Frank Dorman (coauthor), many natural and synthetic organic compounds can cause foaming at these levels. This is especially the case in the presence of natural gas, because gas facilitates foaming as it bubbles out of the water.
- Is it possible or even likely that the natural gas and the organic compounds (e.g. UCM, 2‐BE) came from separate sources?
Yes, it is indeed likely that these impacts are derived from different sources. We state this explicitly in the paper. There is overwhelming evidence that natural gas migrated from Welles 3‐2H or multiple gas wells present on the Welles 3, 4 and 5 pads: for example, these wells were reported to have excessive annular pressures due to poor construction and subsequent remedial activities (e.g. “cement squeezes”) were successful in reducing sustained annular gas pressures that had contributed to the gas migration to the impacted water wells. Additionally, we summarized three reasonable scenarios for the UCM and the 2‐BE (but also see FAQ 6 above pertaining to 2‐BE). First, the gas company was cited for a pit leak on the Welles 1 pad, and this could therefore implicate a surface‐related release. Second, drilling fluids could have leaked out of one of the gas well boreholes at shallow to intermediate depths. The final scenario is leakage at shallow to intermediate depths of HVHF fluids prior to or during injection at the Welles 1 gas wells – well above the depth of hydraulic fracturing in the shale. We explain the scenarios in our paper.
- For this study, you indicate that you sampled Wells 1, 3 and 6 for GCxGC‐TOFMS analysis. Why didyou sample these wells and not the others (i.e. Wells 2, 4 and 5)?
This project was largely unfunded. The National Science Foundation indirectly supported one graduate student (co‐author Paul Grieve), whose overall job was to populate a database of water quality (www.shalenetwork.org). Leco Corporation supported the GCxGC‐HR‐TOFMS analysis. The rest of the work was supported by Penn State seed funds (used to establish new research) and by Appalachia Hydrogeologic and Environmental Consulting, LLC (Garth Llewellyn’s time, transportation and equipment).
Given the limited funding, we decided to sample Wells 1 and 6 since they are located on the northern and southern‐most ends of the households and have pre‐existing and operational infrastructure. We also wanted to sample an original well and decided to select Well 3 since it is centrally located. (see Llewellyn et al., 2015, Figure 1B). In addition to the impacted household wells, we selected three water wells that were outside of the impacted area, but were within a reasonable distance (~5 km) to evaluate natural background water quality using GCxGC‐TOFMS. If we had more funding, we would have sampled all the affected wells (e.g. Wells 1 – 6) and also more private household wells to evaluate background water quality to a further extent.
- Has the gas company improved its well construction practices since this incident?
Representatives of the gas company communicated to us that since 2010, significant improvements have been made to gas well construction practices, including the use of a 3‐string casing design that generally extends down to a depth of approximately 2400 feet and is fully cemented in place. In contrast, at the time of the incident, the implicated gas wells only had protective surface casing down to a depth of approximately 1000 feet. This casing design met regulations at the time of emplacement, but the regulations were strengthened in 2011 to include intermediate casing whenever natural gas occurs at a pressure that could cause migration in the upper several thousand feet of the borehole.
- Why did you write a sensationalized paper?
It is not sensationalized given that the paper provides a substantial amount of factual information related to the case. We have also taken care to indicate uncertainty where it is warranted. We state unequivocally that we cannot unambiguously identify the exact source of the UCM and 2‐BE. However, we know with certainty that: (1) natural gas impacts were the result of adjacent, upgradient Marcellus shale gas wells; (2) foam was observed multiple times in the original and replacement water wells; (3) 2-BE was identified in Well 1; (4) a UCM comprised of approximately 1000 different hydrocarbon compounds was identified in all the samples we collected from the impacted wells (i.e., Wells 1 ,3, 6); (5) the background water wells we sampled had no UCM nor 2‐BE; and (6) the UCMs identified from the impacted homeowner water wells were similar to the approximately 30 samples we analyzed from Marcellus Shale flowback/production fluids.
—Original post, May 4, 2015—
A new study published this week garnering the attention of The New York Times and others cites issues related to well-integrity as “the most likely explanation” for trace amounts of a common compound being detected five years ago in a water well near Sugar Run, Pa.
As expected, activists have been quick to seize on the study as evidence – finally, after 65 years! – that hydraulic fracturing can contaminate water, notwithstanding the authors going out of their way to make clear in the text that the “data released here do not implicate” that technology as the culprit.
Having anticipated that some of their findings might be distorted upon entering the public sphere, the researchers should be credited for including a number of statements about the limitations of the data available. But even having made these concessions, the authors still arrive at a set of conclusions in the end that, based on our reading, don’t quite square with the facts of the case as they demonstrably exist.
Scattered in and throughout what’s otherwise a pretty dense report, here are six important things that are worth knowing:
Fact #1: The study’s attempt to blame drilling activities hinge on the researchers’ post-hoc discovery of “very low concentrations” of a trace compound (2-butoxyethanol or 2-BE) commonly found in hundreds of household products.
The researchers base their argument almost entirely on the detection of trace concentrations of undifferentiated hydrocarbon compounds in three wells, two of which were water “replacement” wells, and the third, a single detection of a trace concentration of compound 2-BE in a separate replacement well. As the report states:
“When we analyzed a subset of the household waters with GCxGC-TOFMS in 2012, we detected very low concentrations of 2-BE. This compound is of special interest because [EPA] has suggested that 2-BE could be an indicator of contamination from HVHF activities.”
2-BE can be an indicator of a lot of things, actually – a fact that the authors concede in the end, though not in the actual report text itself. No, what the researchers bury deep in the supplemental reading packet is the fact that 2-BE is found in hundreds if not thousands of household products, including things as common as Windex and cosmetic products. From that supplemental document:
“… 2-BE is used in industry as a solvent for paints and surface coatings and as an ingredient for paint thinners, herbicides, degreasers, dyes, soaps, and cosmetics. … Domestic US production of 2-BE has steadily increased — reported amounts include 59 million kilograms, 123 million kilograms, 136 million kilograms, and 185 million kilograms for years 1975, 1984, 1986, and 1995, respectively …. 2-BE could also result from consumer product use, such as outdoor use of liquid cleaners and paints.”
Other likely sources not considered by this study include the discharge of common household chemicals containing 2-BE (and other products) into subsurface septic systems present at these homes. In fact, elevated nitrate levels in some of the samples suggest septic or agricultural impacts may be present.
Yet, at no point do the researchers consider that the “very low concentrations of 2-BE” could be from any one of these multiple, common and commercial sources.
Further, as the Agency for Toxic Substances and Disease Registry (ATSDR) points out, most people are exposed to this compound several times a day in the workplace or at home. And here’s something that might surprise you: It’s also approved for use by the U.S. FDA as a food additive.
Additionally, 2-BE is known to have a very short half-life in the environment, around seven to 28 days depending on external conditions. Its biodegradability is one of the reasons why it is considered a safe and effective product for drilling both gas wells and water wells. Would 2-BE used in the drilling of a gas well in 2009 show up in tests done in 2012? Not likely, according to the science.
Fact #2: 2-BE also is used in the actual construction of water wells
Even while stating in their paper that the presence of 2-BE in the water well most likely came from the use of a “common drilling additive” known as Airfoam HD, the authors then admit that “we have no evidence that Airfoam HD was used in the Welles series gas wells.” While we don’t know if Airfoam was used in the drilling of any of the gas wells in question, AirFoam is a product commonly used in the drilling of water wells, of which there are thousands in place in Bradford Co., Pa.
Notably, 2-BE is also found in common Type I/II Portland cement, plenty of which is used in water and monitoring well construction – and was specifically used in the construction of these three replacement wells. The replacement water well containing the 2-BE in question was newly drilled and used approximately 200 gallons of Portland Cement in its completion, which could easily explain the detections of these trace compounds. As a 2014 peer reviewed study on organic compounds in Portland Cements used in monitoring well construction explains,
“Some cements also contained ppb concentrations of benzoic acid, phenols, propylene glycol, and 2-butoxyethanol. Leaching of cured cement samples in water produced ppm (mg/L) concentrations of glycols in the supernatant. These results show that cured cements in monitoring or water wells can contaminate groundwater samples with glycols and phenol. Our findings should help prevent future sample bias and false positives when testing for glycol compounds and phenol in groundwater samples from monitoring or water wells and highlight the need to test materials or products used in monitoring or water well drilling, completions, development, and sampling to avoid false positives when sampling and analyzing for less common analytical constituents.” (emphasis added)
If all this talk about 2-BE seems to you like déjà vu all over again, it’s because you’re right: Back in 2011, EPA seized on a “hit” of 2-BE as potential evidence that hydraulic fracturing had impacted water quality in Wyoming, only to be forced later to disavow the report its regional office had issued, and exit itself from the case entirely.
Now years removed from that incident, we know that the contamination found by EPA in Pavillion was likely a false-positive detection of 2-BE and glycols, traced to the materials EPA used to construct the monitoring wells where it collected samples for the water quality analysis in the first place. As one peer reviewed study put it,
“[T]o establish a link to hydraulic fracturing in the deep monitor wells, the EPA draft report relied heavily on the detection of exotic organics chemicals such as glycols and 2-butoxyethanol in the deep groundwater monitor wells, some of which were present at very low or trace concentrations, at least initially. If the detection of such low chemical concentrations is to be used as a criterion to show impacts from hydraulic fracturing, it is important to exercise extreme care in decontaminating drilling tools, well casings, and screens placed in the well, in the use during drilling of hydrocarbon-based fluids and lubricants, in eliminating the potential for well construction materials to leach chemicals into the water, in conducting thorough well development, in confirmation sampling, and in robust laboratory QA/QC protocols.”
That’s one of the reasons EPA’s report on Pavillion received such strong criticism by Wyoming state regulators, the U.S. Bureau of Land Management (BLM) and the U.S. Geological Survey (USGS). In fact, subsequent USGS testing uncovered very different results. As a report by the American Petroleum Institute (API) explained,
“A review of the USGS data presented in their report shows pH stabilization did not occur during sampling, and graphs in that USGS report suggest that well MW-01 is still being impacted by high pH cement (known to contain glycols and phenols) and/or drilling fluids used by EPA. Review of all analytical and development data suggests that both monitoring wells MW-01 and MW-02 have yet to be properly developed and are both being affected by cement. USGS was unable to use standard USGS and best practice sampling/purging methods for monitoring well MW-02 due to completion and development problems encountered during the April-May, 2012 USGS investigation. […] It is likely that this steel casing may have introduced to the groundwater organic and inorganic compounds, including hydrocarbons and 2- butoxyethanol (2-BE) allegedly reported sporadically in EPA’s samples.”
Regarding EPA’s samples, Don Simpson, a high-ranking BLM official, suggested EPA’s testing could have introduced “bias in the samples,” adding that the data “should not be prematurely used as a line of evidence that supports EPA’s suggestion that gas has migrated into the shallow subsurface due to hydraulic fracturing or improper well completion until more data is collected and analyzed.”
The authors of this latest study appear to have used the same methods that were widely criticized when EPA implemented them in Pavillion.
Fact #3: Researchers didn’t detect high chlorides in the water they tested, which would have been present in significant volumes had any issues been related to oil and gas activity.
According to the study:
“The most likely explanation of the incident is that stray natural gas and drilling or HF compounds were driven ∼1–3 km along shallow to intermediate depth fractures to the aquifer used as a potable water source.”
But if trace amounts of drilling fluids were actually detected in those wells, the samples would have also contained high levels of chloride, as well as barium and bromide. But the researchers’ samples don’t show that at all – instead, they find chloride, barium, and bromide levels were low, basically at background levels common to the region.
Obviously, if compounds used in the development process had somehow found a way to get into a water well, you wouldn’t just see one of those compounds pop up – you’d see a mix of them. But again, that’s not what the paper’s authors found, suggesting the source of the issue likely had nothing to do with oil and gas.
Fact #4: Samples were not above regulatory drinking water standards
Another pretty important fact that has the potential to get lost in the wider discussion: the actual amount of 2-BE that researchers found in the water they sampled was so low, it didn’t even come close to exceeding EPA’s standards for safe drinking water. In other words: this apparently “contaminated” water was, according to EPA, perfectly safe to drink. From the report:
“[C]ommercial laboratories reported no compounds other than natural gas present at concentrations above regulatory recommended action levels, and no constituents were detected above regulatory drinking water standards.”
Fact #5: Stop right there – this had nothing to do with hydraulic fracturing
It’s worth pointing out that the researchers completely rule out the possibility that contamination could have been caused by the hydraulic fracturing process. To wit:
“If HVHF fluids did contaminate the water wells, it would be surprising if such contamination were due to fluids returning upward from deep strata, given that (i) this has never been reported (6), (ii) the time required to travel 2 km up from the Marcellus along natural fractures is likely to be thousands of millions of years (31), and (iii) Fig. 6 shows that the Cl:Br rations in the drinking waters indicate the absence of salts that would be diagnostic of fluids from the Marcellus Shale (e.g. flowback/production waters).”
The study further states that:
“The data released here do not implicate upward flowing fluids along fractures from the target shale as the source of contaminants….”
Fact #6: This event predates the implementation of updated well-casing rules in Pennsylvania, which have been praised by the Obama administration
In 2011, the Pa. Dept. of Environmental Protection (DEP) updated its well integrity rules, which have rightly been singled out as model standards for the entire country, and praised by the Obama administration. Here’s a passage from the 2013 State Review of Oil and Natural Gas Environmental Regulations (STRONGER) (which was formed by the U.S. Environmental Protection Agency (EPA) and the Interstate Oil and Gas Compact Commission (IOGCC)):
“DEP is commended for its hydraulic fracturing program. Standards for well casing and cementing require that the operator conduct those activities to control the well at all times, prevent migration of gas or other fluids into sources of fresh groundwater; and prevent pollution of fresh groundwater..”
Back in the report text itself, the researchers concede:
“It is not possible to prove unambiguously that the UCM and 2-BE were derived from shale gas-related activities.”
But as we’ve seen, not only is impossible to prove these exceedingly small volumes of compounds found their way into water as a result of oil-and-gas related activities, it’s actually quite possible to lay out a series of scenarios that have nothing to do with oil and gas, and yet are orders of magnitude more likely as a possible origination point.
But again, the researchers base their conclusions almost entirely on the detection of “very low concentrations” of 2-BE, and ignore outright the fact that this compound is found in a wide array of everyday products and used by a number of industries – including the industry responsible for constructing the actual water wells from which the samples were taken!
Finally, no explanations are provided for why the samples they collected don’t also feature high levels of chlorides, a baseline most researchers would have wanted to establish before jumping to any conclusions about oil and gas.
In fact, every bit of data available suggests the far stronger case to be made with respect to the origination and transport of these compounds is related to the construction of the water wells themselves, which, if true, would be richly ironic, indeed. Except for the fact that EPA made this same exact mistake four years back when it conducted its water quality work out in Wyoming.
So now it’s just old.