Who’s in charge here? By Kyle Ferrar, Western Program Coordinator
FracTracker Alliance recently worked with Clean Water Action to map an update to last year’s report* on the use of unlined, above ground oil and gas waste disposal pits, also known as sumps.
The new report identifies additional oil field wastewater pits and details how California regulators continue to allow these facilities to degrade groundwater, surface waters, and air quality. Other oil and gas production states do not permit or allow these type of operations due to the many documented cases of water contamination. A report published in 2011 identified unlined pits and other surface spills as the largest threat to groundwater quality. The sites are ultimately sacrifice zones, where the contamination from produced water and drilling mud solid wastes leaves a lasting fingerprint.
Central Coast & New Central Valley Pit Data
Figure 1. Central Coast wastewater pits
New data has been released by the Central Coast Regional Water Quality Control Board, identifying the locations of 44 active wastewater facilities and 5 inactive facilities in the California counties of Monterey, Santa Barbara, and San Luis Obispo. The number of pits at each facility is not disclosed, but satellite imagery shows multiple pits at some facilities. The locations of the majority of central coast pits are shown in the map in Figure 1, to the right.
In the web map below (Figure 2), the most updated data shows the number of pits at “active” facilities (those currently operating), shown in red and green, and inactive pits, shown in yellow and orange. The number of pits at each facility in the central valley are shown by the size of the graduated circles. Pit count data for the central coast facilities was not reported, therefore all facilities are shown with a small marker.
Figure 2. Interactive map of California oil field wastewater pits
Exploring the new central coast data shows that the operators with the most facilities include Greka Oil & Gas Inc. (14), E & B Natural Resources (10), ERG Operating Company, LLC (6), and Chevron (5). As shown in the table below, the majority of central coast pits are located in Santa Barbara County.
Table 1. Summaries by County
Site Counts by Activity and County
Facility Counts
Pit Counts
County
Active
Inactive
Active
Inactive
Santa Barbara
35
2
Unknown
Unknown
Monterey
9
0
Unknown
0
San Luis Obispo
0
3
0
Unknown
Kern
161
191
673
347
Fresno
8
5
31
14
Tulare
6
1
28
1
Kings
5
0
14
0
San Benito
0
4
0
5
Grand Total
224
206
746
367
Wastewater Pit Regulations
Way back in 1988, the U.S. EPA recognized that the federal regulations governing disposal practices of wastewater are inadequate to protect public health, but has yet to take action (NRDC 2015). There is little chance the U.S. EPA will enact regulations focused on pits. In certain cases, if wastewaters spill or are discharged to surface waters the operations will fall under the jurisdiction of the Clean Water Act and will require a National Pollutant Discharge Elimination System (NPDES) permit. Since the objective of the pit is to contain the wastewater to keep it away from surface waters, pits and the wastewater facilities in California that manage them do not require federal oversight. For now the responsibility to protect health and environment has been left to the states.
Most states have responded and have strict regulations for wastewater management. For the few states that allow unlined pits, the main use is storage of wastewater rather than as an dedicated method of disposal. The majority of high production states have banned or ended the use of unlined pits, including Texas, North Dakota, Pennsylvania, Ohio, and New Mexico, Texas (Heberger & Donnelly 2015). An effective liner will prevent percolation of wastewaters into groundwater. The goal of California oil field wastewater pits is quite the opposite.
For California, percolation is the goal and a viable disposal option.
Therefore other regulations that require monitoring of liquid levels in the pits are moot. In fact there is no evidence of regulation requiring spill reporting in California whatsoever (Kuwayama et al. 2015).
Numerous other extraction states throughout the country have phased out the use of open pits entirely, including those with liners due to the common occurrence of liner failures. The list includes those new players in the shale boom using hydraulic fracturing techniques such as North Dakota, Ohio, Pennsylvania, Wyoming, and Colorado. Rather than using the pits as storage, these states’ regulatory agencies favor instead the protections of closed systems of liquid storage. Wastewaters are stored in large tanks, often the same tanks used to store the fresh water used in the hydraulic fracturing process.
Because hydraulic fracturing in California uses much less water, it should be much easier to manage the flowback fluids and other wastewaters. According to the CCST report, 60% of the produced water from hydraulic fracturing operations was disposed to these unlined pits. Regardless of extraction technique, oil extraction in California produces 15 times the amount of wastewater. In total, an estimated 40% of all produced water was discharged to unlined “percolation” pits. As the 3rd largest oil producing state in the country, this equates to a massive waste stream of about 130 billion gallons/year (Grinberg 2014).
Regulatory Action
The facilities’ permits identify waste discharge requirements (WDRs) that allow for the discharge of oil field wastewater to the “ground surface, into natural drainage channels, or into unlined surface impoundments.” Using the Race Track Hill and Fee 34 Facilities as an example, the WDRS place criteria limits on total dissolved solids (TDS), chlorides, and boron. If you disregard all the other toxic constituents not monitored, the allowable concentration limits set for these three wastewater constituents would be reasonable for a discharge permit on the east coast, where a receiving body of water could provide the volume necessary for dilution. When the wastewater is applied directly to the ground or into a pit, the evaporative loss of water results in elevated concentrations of these contaminants.
Even with these very lax regulations, a number of facilities are in violation of the few restrictions required in their permits. Cease and desist orders have been several operators, most notably to Valley Water Management’s Race Track Hill and Fee 34 Facilities. According to the Regional Water Board documents, the Fee 34 disregarded salinity limitations and other regulations. As a result the Regional Water Board found soil and groundwater contamination that “threatens or creates a condition of pollution in surface and groundwater, and may result in the degradation of water quality.” Reports show that 6 domestic supply and 12 agricultural supply wells are located within 1 mile of the Fee 34 facility. At the Race Track Hill Facility the wastewater is continuously sprayed over several acre fields in a small watershed of the Cottonwood Creek. During a rain, the salt and boron loadings that have accumulated in the soil over the past 60 years of spraying can create increased salt and boron loading in the Kern River and groundwater. This would be a violation of the Clean Water Act (CVRWQCB 2015).
As shown in Table 2, below, the majority of facilities are currently operating without a permit whatsoever (61.2%). Of the 72 facilities that bothered to get permits, 32 (44.4%) received the permit prior to 1975, before the Tulare Basin Plan was implemented to preserve water quality. Of the 183 active facilities in the Central Valley, only 15 facilities have received Cease and Desist (11% of permitted) or Cleanup and Abatement Orders (6% of unpermitted). Only 3 of the 41 active Central Coast facilities operate with a permit (7.3%).
These types of WDR permits that allow pollutants to concentrate in the soil and the groundwater and degrade air quality. Chemicals that pose a public health risk are not being monitored. But at this point, these facilities are not only sites of legacy contamination, but growing threats to groundwater security. Operators say that closing the pits will mean certain doom for oil extraction in California, and recent letters from operators make pleas to DOGGR, that their very livelihood depends on using the pits as dumping grounds. The pits are the cheapest and least regulated mode of disposal.
Table 2. Facility Status Summaries
Facility Status
Activity
Permitted
Permitted; Cease & Desist Order
Unpermitted
Unpermitted; Cleanup & Abatement Order
Grand Total
Active
75
9
137
6
227
Inactive
20
2
184
3
209
Grand Total
92
11
321
9
433
New Mexico Case Study
Much like the groundwater impacts documented by California’s Central Valley Regional Water Quality Control Board, other states have been forced to deal with this issue. The difference is that other states have actually shut down the polluting facilities. In California, cease and desist orders have been met with criticism and pleas by operators, stating that the very livelihood of the oil and gas industry in California depends on wastewater disposal in pits. The same was said in other states such as New Mexico when these crude and antiquated practices were ended. Figure 3 below shows the locations of wastewater pits in New Mexico and the areas where groundwater was contaminated as a result of the pits.
The New Mexico oil and gas industry predicted in August 2008 that fewer drillers would sink wells in New Mexico, at least in part because of the new pit rule. Pro-industry (oil and gas) state representatives were concerned that new drilling techniques coupled with the pit rules could lead to an industry exodus from New Mexico, hoping that the Governor “would step in to help protect an important state revenue source.” But the state’s average rig count from June — when the pit rule took effect — through December 2008 was 7% higher than it was over the same period in the previous year. Development of oil and gas reserves is independent of such regulation. Read the FracTracker coverage of groundwater contamination in New Mexico, here!
Figure 3. Legacy map of cases where pits contaminated groundwater in New Mexico
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2015/10/Sumps_BrianvanderBrug_LATimes_Revised.jpg400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2016-03-09 14:39:482020-03-12 17:32:29More Oil Field Wastewater Pits Found in California!
It is hard to believe, but disposing of hazardous oil and gas wastewaters in unlined, open-air pits – also known as sumps or ponds – is still a common practice in California. It is also permitted in other states such as Texas and West Virginia. Because these ponds are unlined and not enclosed, they contribute to degraded air quality, are a hazard for terrestrial animals and birds, and threaten groundwater quality. A 2014 report by Clean Water Action, entitled In the Pits provides a thorough summary of the issue in California. Since the report was released, new data has been made available by the Central Valley Regional Water Quality Review Board identifying additional locations of wastewater pits.
With the increase of oil and gas development in unconventional reservoirs, such as the Monterey Shale Play in California, the size of the resultant waste stream of drill cuttings, produced brines, and wastewater has skyrocketed. Operators now drill larger, deeper wells, requiring larger volumes of liquid required for enhanced oil recovery methods, such as steam injection, and stimulations such as hydraulic fracturing and acidizing. While California is the 4th largest oil-producing state, it is 2nd only to Texas in wastewater production. This boom of unconventional development, which may still in its infancy in California, has resulted in an annual waste stream of over 130 billion gallons across the state, 80 billion (62%) from Kern County alone.1
Results of the state mandated California Council on Science and Technology Report found that more than half of the California oil industries waste water is “disposed” in pits.2 As outlined by Clean Water Action, the massive waste-stream resulting from drilling, stimulation, and production is one of the most significant and threatening aspects of oil and gas operations in terms of potential impacts to public health and environmental resources.
Wastewater Facility Details
Last February, the LA Times reported on the pits, identifying a total of 933 in California.3 The most recent data from the Regional Water Quality Control Board of the Central Valley shows:
A total of 1,088 pits at 381 different facilities
719 pits are listed as “Active.” 369 are “Idle.”
444/939 (47.3%) ponds do not list a permit.
462 pits are operated by Valley Water Management Corporation.
In Table 1, below, the counts of Active and Idle facilities and pits are broken down further to show the numbers of sites that are operating with or without permits. The same has been done for the operator with the most pits in Table 2, because Valley Wastewater operates nearly 9 times as many pits as the second largest operator, E & B Natural Resources Management Corporation. These two operators, along with California Resources Elk Hills LLC, all operate the same number of facilities (28). The other top 20 operators in Kern County are listed in Table 3, below.
Table 1. Wastewater Pit and Facility Counts by Category
Counts
Active
Idle
Facilities
180
201
Unpermitted Facilities
102
179
Facility Permitted prior to 1985
37
11
Individual Pits
719
369
Unpermitted Individual Pits
187
257
Pit Permitted prior to 1985
252
63
Table 2. Valley Water Wastewater Pit and Facility Counts by Category
Counts
Active
Inactive
Facilities
21
7
Unpermitted Facilities
2
2
Facility Permitted prior to 1985
9
1
Individual Pits
356
78
Unpermitted Individual Pits
5
9
Pit Permitted prior to 1985
166
35
Table 3. Top 20 Operators by Facility Count, with Pond Counts.
Rank
Operator
Pond Count
Facility Count
1
Valley Water Management Company
462
28
2
E & B Natural Resources Management Corporation
53
28
3
California Resources Elk Hills, LLC
31
28
4
Aera Energy LLC
67
25
5
California Resources Corporation
31
23
6
Chevron U.S.A. Inc.
40
14
7
Pyramid Oil Company
21
12
8
Macpherson Oil Company
14
9
9
Schafer, Jim & Peggy
8
8
10
Crimson Resource Management
20
6
11
Bellaire Oil Company
11
6
12
Howard Caywood
11
6
13
LINN Energy
10
6
14
Seneca Resources Corporation
9
6
15
Holmes Western Oil Corporation
6
6
16
Hathaway, LLC
22
5
17
Central Resources, Inc.
15
5
18
Griffin Resources, LLC
13
5
19
KB Oil & Gas
8
5
20
Petro Resources, Inc.
6
5
Maps of the Pit Locations and Details
The following maps use the Water Authority data to show the locations details of the wastewater pits. The first map shows the number of pits housed at each facility. Larger markers represent more pits. Zoom in closer using the [+] to see the activity status of the facilities. Click the link below the map to open a new webpage. View the names of the facility operators by turning on the layer in the “Layers” menu at the top of the page. The second and third maps show the activity and permit status of each facility. The fourth map allows you to view both activity status and permit status simultaneously by toggling the layers on and off (Open the map in its own webpage, then use the layers menu at the top of the screen to change views).
Map 1. Facility Pit Counts with the top 10 operators identified as well as facility status
Map 1. To view the legend and map full screen, click here.
Map 2. Facility Activity Status
Map 2. To view the legend and map full screen, click here.
Map 3. Facility Permit Status
Map 3. To view the legend and map full screen, click here.
Map 4. Facilityhttps://maps.fractracker.org/lembed/?appid=7385605f018e437691731c94bb589f0a” width=”800″ height=”500″> Map 4. To view the legend and map full screen, click here.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2015/10/Pit-Pipes-AG.jpg400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2015-10-13 10:55:392020-03-12 17:37:53Wastewater Pits Still Allowed in California
Oil, Gas, and Brine Oh My! By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance
It was just three years ago that the Ohio Geological Survey (OGS) and Department of Natural Resources (DNR) were proposing – and expanding – their bullish stance on the potential Utica Shale oil and gas production “play.” Back in April 2012 both agencies continue[d] to redraw their best guess, although as the Ohio Geological Survey’s Chief Larry Wickstrom cautioned, “It doesn’t mean anywhere you go in the core area that you will have a really successful well.”
What we found is that the OGS projections have not held up to their substantial claims. And here is why…
Background
The Geological Survey eventually parsed the Utica play into pieces:
a large oil component encompassing much of the central part of the state,
natural gas liquids from Ashtabula on the Pennsylvania border southwest to Muskingum, Guernsey, and Noble Counties, and
natural gas counties, primarily, along the Ohio River from Columbiana on the Pennsylvania-West Virginia border to Washington County in the Southeast quarter of the state.
Columbus Dispatch Utica Shale “play” map
Fast forward to the first quarter of 2015 and we have a very healthy dataset to begin to model and validate/refute these projections. Back in 2009 Wickstrom & Co. only had 53 Utica Shale laterals, while today Ohio is host to 962 laterals from which to draw our conclusions. The preponderance of producing wells are operated by Chesapeake (463), Gulfport (118), Antero Resources (62), Eclipse Resources (41), American Energy Utica (36), Consol (35), and R.E. Gas Development (34), with an additional 13 LLCs and 10 publicly traded companies accounting for the remaining 173 producing laterals. A further difference between the following analysis and the OGS one is that we looked at total production and how much oil and gas was produced on a per-day basis.
Analysis
Using an interpolative geostatistical technique known as Empirical Bayesian Kriging and the 962 lateral dataset, we modeled total and per day oil, gas, and brine production for Ohio’s Utica Shale between 2011 and Q1-2015 to determine if the aforementioned map redrawing holds up, is out-of-date, and/or is overly optimistic as is generally the case with initial O&G “moving target” projections.
Days of Activity & Brine Production
The most active regions of the Utica Shale for well pad activity has been much of Muskingum County and its border with Guernsey and Noble counties; laterals are in production every 1 in 2.1-3.4 days. Conversely, the least active wells have been drilled along the Harrison-Belmont border and the intersection between Harrison, Tuscarawas, and Guernsey counties.
Brine is a form of liquid drilling waste characterized by high salt loads and total dissolved solids. The laterals that have produced the most brine to date are located in a large section of Monroe County and at the intersection of Belmont, Monroe, and Noble counties, with total brine production amounting to 23,292 barrels or 734,000-978,000 gallons (Fig. 1).
Figure 1. Total Ohio Utica Shale Oil, Gas, and Brine Production 2011 to Q1-2015
This area is also one of the top three regions of the state with respect to Class II Injection volumes; the other two high-brine production regions are Morrow and Portage counties to the west and southwest, respectively (Fig. 2).
Figure 2. Layout & Volume (2010 to Q1-2015, Gallons) of Ohio’s Active Class II Injection Wells
However, on a per-day basis we are seeing quite a few inefficient laterals across the state, including Devon Energy’s Eichelberger and Richman Farms laterals in Ashland and Medina counties. Ashland and Medina are producing 230-270 barrels (8,453-9,923 gallons) of brine per day. In Carroll County, one of Chesapeake’s Trushell laterals tops the list for brine production at 1,843 barrels (67,730 gallons) per day. One of Gulfport’s Bolton laterals in Belmont County and EdgeMarc’s Merlin 10PPH in Washington County are generating 1,100-1,200 barrels (40,425-44,100 gallons) of brine per day.
Oil & Gas Production
Since the last time we modeled production the oil hotspots have shrunk. They have also become more discrete and migrated southward – all of this in contrast to the model proposed by the OGS in 2012. The areas of greatest productivity (i.e., >26,000 barrels of oil) are not the central part of the state, but rather Tuscarawas, Harrison, Guernsey, and Noble counties (Fig. 1). The intersection of Harrison, Tuscarawas, and Guernsey counties is where oil productivity per-day is highest – in the range of 300-630+ barrels (Fig. 3). The areas that the OGS proposed had the highest oil potential have produced <600 barrels total or <12 barrels per day.
Figure 3. Per-Day Ohio Utica Shale Oil, Gas, and Brine Production 2011 to Q1-2015
The OGS natural gas region has proven to be another area of extremely low oil productivity.
Natural gas productivity in the Utica Shale is far less extensive than the OGS projected back in 2012. High gas production is restricted to discreet areas of Belmont and Monroe counties to the tune of 947,000-4.1 million Mcf to date – or 5,300-18,100 Mcf per day. While the OGS projected natural gas and natural gas liquid potential all the way from Medina to Fairfield and Perry counties, we found a precipitous drop-off in productivity in these counties to <1,028 Mcf per day (<155,000 Mcf total from 2011 to Q1-2015) or a mere 6-11% of the Belmont-Monroe sweet spot.
Conclusion: A Shrinking Utica Shale Play
Simply put, the OGS 2012 estimates:
Have not held up,
Are behind the times and unreliable with respect to citizens looking to guestimate potential royalties,
Were far too simplistic,
Mapped high-yield sections of the “play” as continuous when in fact productive zones are small and discrete,
Did not differentiate between per day and total productivity, and
Did not address brine waste.
These issues should be addressed by the OGS and ODNR on a more transparent and frequent basis. Combine this analysis with the disappointing returns Ohio’s 17 publicly traded drilling firms are delivering and one might conclude that the structural Utica Shale bubble is about to burst. However, we know that when all else fails these same firms can just “lever up,” like their Rocky Mountain brethren, to maintain or marginally increase production and shareholder happiness. Will these Red Queens of the O&G industry stay ahead of the Big Bank and Private Equity hounds on their trail?
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2015/09/OH-Shrinking2-Feature.jpg400900Ted Auch, PhDhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngTed Auch, PhD2015-09-29 15:29:212020-03-12 17:39:58The Curious Case of the Shrinking Utica Shale Play
According to data published by the Pennsylvania Department of Environmental Protection (DEP), Pennsylvania’s unconventional oil and gas waste that was generated in the first half of 2015 found its way to treatment facilities, disposal wells, and landfills in eight different states. While the majority of the waste stayed in-state, neighboring Ohio, New York, and West Virginia all received significant quantities of both solid and liquid waste, and additional disposals were made in the non-contiguous states of Michigan, Texas, Utah, and Idaho.
Waste generated by Pennsylvania’s unconventional oil and gas wells was disposed of in a variety of ways and over a large geographic area. Click on a facility to learn more, or zoom in to access waste generated by individual wells. Click here to access the full screen map with a legend and additional controls.
Unconventional drillers in the state are now required to report production data monthly, rather than in six month increments, but waste quantities generated by the wells is still supposed to be reported biannually. However, a small number of operators have been reporting waste monthly, as well, and those figures have been included in this analysis, after spot-checking for duplication. Each record includes data on how the waste was processed and where it was shipped, so we were able to map the receiving facilities as well, and aggregate their waste totals.
Types of Waste
Waste generated by unconventional wells in Pennsylvania from January to June 2015 by type.
There are eight types of waste detailed in the Pennsylvania data, including:
Basic Sediment (Barrels) – Impurities that accompany the desired product
Drill Cuttings (Tons) – Broken bits of rock produced during the drilling process
Flowback Fracturing Sand (Tons) – Sand used to prop open cracks made during hydraulic fracturing that return to the surface
Fracing Fluid Waste (Barrels) – Fluid pumped into the well for hydraulic fracturing that returns to the surface. This includes chemicals that were added to the well.
Produced Fluid (Barrels) – Naturally occurring brines encountered during drilling that contain various contaminants, which are often toxic or radioactive
Servicing Fluid (Barrels) – Various other fluids used in the drilling process
Spent Lubricant (Barrels) – Oils used in engines as lubricants
General O&G Waste (Tons) – Solid waste types other than drill cuttings or fracturing sand
For the sake of simplicity, this analysis will at times aggregate the waste types into two categories, with all types reporting in tons as solid waste, while those listed in 42 gallon barrels will be considered liquid waste.
Waste Disposal
Waste disposal method for unconventional wells in PA, January to June 2015
This PA waste gets disposed of in a variety of ways. About 93 percent of all solid waste ends up in landfills. 29 of the 58 operators reporting waste during this cycle reported drill cuttings. In a separate report, the DEP has records for unconventional wells drilled by 28 different operators during the same time frame, so these results seem reasonable, since drill cuttings are generated during the drilling process, whereas other types of waste are produced throughout the life cycle of the well.
Statewide, there over 596,000 tons of drill cuttings produced during a period which saw 422 wells spudded, an average of 1,412 tons of cuttings per well. Not all operators generated the same amount of cuttings per well, however. Vantage Energy reports 3,089 tons of cuttings per well, while Hilcorp Energy manages to average just 119 tons over 23 wells drilled in the six month period. It is worth noting that some wells that were spudded just prior to the reporting period likely still generated drill cuttings during the six months in question, and some wells spudded during the cycle will continue to produce cuttings into the next one.
In terms of liquid waste, nearly two thirds of the amount reported is reused for purposes other than road spreading. This is, unfortunately, a dead end in terms of being able to follow the waste stream in the data, as there are no facilities associated with the 13.8 million barrels of waste that falls into this category. 225,000 barrels are specified as being reused for hydraulic fracturing, while the remainder is simply destined for, “Reuse without processing at a permitted facility.”
The amount used for road spreading, 147 barrels, is relatively small, and all of this waste is reported as going to private roads in Greene County. The total amount of liquid waste produced in the six month period is almost 879 million gallons, or enough to fill 1,331 Olympic-sized swimming pools.
PA Waste Receiving Facilities
Altogether, we know where roughly 7 million of the nearly 21 million barrels of reported liquid waste wound up, as well as 640,000 of the 647,000 tons of solid waste. The top ten destinations for each waste type are as follows:
Top 10 reported recipients of unconventional O&G waste produced in PA during the first half of 2015.
Six of the top destinations for liquid waste were located in-state, while seven of the top ten facilities for solid waste stayed in Pennsylvania. The only facility to appear on both lists is Patriot Water Treatment in Warren, Ohio.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2014/10/Waste-Data-Feature.png400900Matt Kelso, BAhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngMatt Kelso, BA2015-09-18 11:02:512020-03-12 13:49:50Pennsylvania’s Drilling Waste Distributed to Eight States
While I must commend the State for looking into this important issue, much more needs to be done, and I have serious concerns about the validity of several aspects of this study. Since the report is almost 200 pages long, I will summarize its findings and my critiques below.
Marcellus shale cuttings are radioactive: pgs. 17, 139, 142, 154
We do not know if there is a long term problem: pg. 19
About 30 million tons of waste in next few decades: pg. 176
Landfill liners leak: pg. 20
Owning & operating their own landfill would be expensive & risky for gas companies: pgs. 186-7
Toxicity and biotic risk from drill cuttings is uncharted territory: pg. 78
Landfill leachate is toxic to plants & invertebrates: pgs. 16, 95, 97
Other landfills also have radioactive waste: pgs. 14-15
We have no idea if this will get worse: pgs. 96, 154
If all systems at landfills work as designed, leachate might not affect ground water: pg. 41
Introduction
Drilling rig behind a wastewater pond in West Virginia
Any formal report comprised of 195 pages generated by a reputable school like Marshall University with additional input from Glenville State College – supported by over 2,300 pages of semi-raw data and graphs and charts and tables – requires some serious investigation prior to making comprehensive and final conclusions. However, some initial observations are needed to provide independent perspective and to help reflect on how sections of this report might be interpreted.
The overarching perspective that must be kept in mind is that the complete study was first limited by exactly what the legislature told the WV Department of Environmental Protection DEP to do. Secondly, the DEP then added other research guidelines and determined exactly what needed to be in the study and what did not belong. There were also budget and time constraints. The most constricting factor was the large body of existing data possessed by the DEP that was provided to the researchers and report writers. Because of the time restrictions, only a small amount of additional raw data could be added.
And most importantly, similar to the WVU Water Research Institute (WVU WRI) report from two years ago, it must be kept in mind that these types of studies, initiated by those elected to our well-lobbied legislature and funded and overseen by a state agency, do not occur in a political power vacuum. It was surely anticipated that the completed report might have the ability to affect the growing natural gas industry – which is supported by most in the political administration. Therefore, we must be cautious here. The presence and influence of political and economic factors need to be considered. Also, for universities to receive research contracts and government paid study requests, the focus must include keeping the customer satisfied.
My comments below on the report’s methods and findings are organized into three broad and overlapping categories:
GOOD – positive aspects, good suggestions, important observations
GENERAL – general comments
FLAW – problems, flaws, limitations
MOVING FORWARD – my suggestions & recommendations
I. Water Quality: EPA Test Protocols & Datasets
Marcellus Shale (at the surface)
GENERAL It is obvious that a very smart and well-trained set of researchers put a lot of long, detailed thought into analyzing all of the available data. There must be tens of thousands of data points. Meticulous attention was put into how to assemble all of the existing years’ worth of leachate chemical and radiological information.
GOOD There is an elaborate and detailed discussion of how to best analyze everything and how to utilize the best statistical methods and generate a uniform and integrated report. This was made difficult with non-uniform time intervals, some non-detect values, and some missing items. The researchers used a credible process, explaining how they applied the various appropriate statistical analysis methods to all the data. They provided some trends and observations and draw some conclusions.
FLAW 1 The most glaring flaw and the greatest limitation pertaining to the data sets is the nature of the very data set, which was provided to the researchers from the DEP. It is to the commendable credit of the DEP that the leachate at landfills receiving black shale drill cuttings from the Marcellus and other shale formations were, from the beginning, required to start bi-monthly testing of leachate samples at landfills that were burying drill waste products. And in general, when compared to on-site disposal as done for conventional wells, it was initially a good requirement to have the drill cuttings put into some type of landfill; that way we could keep track of where the drill cuttings are located when there are future problems.
To the best of my knowledge, until the states in the Marcellus region started allowing massive quantities of black shale waste material to be put into local landfills, we have never knowingly deposited large quantities of known radioactive industrial waste products into generic municipal waste landfills. The various waste products and drill cuttings of Marcellus black shales have been known for decades by geologists and radiochemists to be radioactive. We know better than to depose of hazardous radioactive waste in an improper way. Therefore, it is very understandable that we might not know how to best solve the problems of this particular waste product. This was and still is new territory.
FLAW 2 All of the years of leachate test samples were processed for radioactivity using what is called the clean drinking water test protocols, also referred to as the EPA 900 series. Three years ago, given the unfamiliarity of regulatory agencies with the uniqueness of this waste problem, we chose the wrong test protocol for assessing leachate samples. We speculated that the commonly used and familiar clean drinking water test procedure would work. So now we have a massive set of test results all derived from using the wrong test protocol for the radiologicals. Fortunately, all of the chemistry test results should still be reasonably useful and accurate.
At first, three years ago, this was understandable and possibly not an intentional error. Now it is widely known by hydrogeologists and radiochemists, however, that the plain EPA 900 series of test methods for determining the radioactivity of contaminated liquids do not work on liquids with high TDS — Total Dissolved Solids. Method 900.0 is designed for samples with low dissolved solid like finished drinking water supplies.
Despite this major and significant limitation, the effort by Marshall University still has some utility. For example, doing comparisons between and among the various landfills accepting drill waste might provide some interesting observations and correlations. It is clearly known now, however, that the protocols that were used for all samples from the start when testing for gross alpha, gross beta and radium-226 and radium-228 in leachate, can only result in very inaccurate, under-reported data. Therefore, it is not possible to draw any valid conclusions on several very important topics, including:
surface water quality,
potential ground water contamination,
exposure levels at landfills and public health implications,
and policy and regulations considerations.
Labs certified to test for radiological compounds and elements are very familiar with the 900 series of EPA test procedures. These protocols are intended to be used on clean drinking water. They are not intended to be used on “sludgy” waters or liquids contaminated with high dissolved solids like all the many liquid wastes from black shale operations like flowback and produced water and brines and leachate. The required lab process for sample size, preparation, and testing will guarantee that the results will be incorrect.
In no place in the final 195 page report have I seen any discussion of which EPA test protocol was used for the newer samples and why was it used. It has also not yet been seen in the 2,300+ pages of supportive statistical and analytical results, either. The fact that the wrong protocol was used three years ago is very understandable. However, this conventional EPA 900 series was still being used on the additional very recent (done in fall of 2014 and spring of 2015) samples that were included in the final report. The researchers, without any justification or discussion or explanations continued to use the wrong test protocol.
The clean drinking water procedures should have been used along with the 901.1M (gamma spec) process, for comparison. It is understandable for the new data to be consistent and comparable with the very large existing dataset that a case could be made for using the incorrect protocol and the proper one also. There should have been a detailed discussion of what and why any test method was being used, however. That discussion is usually one of the first topics investigated and explained in the Methods section. Having that type of discussion and justification seems to represent a basic science method and accepted research process – and that omission is a serious flaw.
MOVING FORWARD We all know that if we want to bake an appetizing and attractive cake we must use the correct measuring cups for the ingredients. If we want to take our child’s temperature we need an accurate thermometer. When our doctor helps us understand our blood test results, we all want to be confident the right test was used at the lab. The proper test instrument, recently calibrated and designed for the specific sample, is crucial to get useable test results from which conclusions can be drawn and policy enacted.
It seems that the best suggestion so far to test high TDS liquids similar to leachate would be to use what is referred to as Gamma-ray Spectrometry with a high purity germanium instrument with at least a 21-day hold period (30 days are better), while the sample is sealed then counted for at least 16 hours. Many of the old leachate test results indicate high uncertainties that might be attributed to short hold times and short counting times. This procedure is referred to as the 901.1 M (modified). If the sample is sealed, the sample will reach about 99% equilibrium after 30 days. Radon 222 (a gas) must not be allowed to escape.
The potential environmental impacts to water quality section of this report seems to demonstrate that if you do not want to find out something, there are always justifiable options to avoid some inconvenient facts. Given the very narrow scope as defined, some the Marshall University folks did not seem to have the option to stray into important scientific foundational assumptions and, for the most part, just had to work with the stale data sets given to them. All of which, as we have known for close to a year now, have used the wrong test protocol. Therefore we have incorrect results of limited value.
II. Marcellus is Radioactive
GOOD 1 Of course, geologists have known that the Marcellus Shale is radioactive for many decades, but also for decades there has been great reluctance by the natural gas exploration and production companies to acknowledge this fact to the public. And finally we now have a public report that clearly and unambiguously states that Marcellus shale is radioactive. Interestingly enough, it was not much more than a year ago that some on the WV House of Delegates Judiciary Committee, seemed to be echoing the industry’s intentional deception by declaring that:
…it was only dirt and rock…
So this report represents progress and provides a very valuable contribution to beginning to recognize some of the potential problems with shale wastes and their disposal challenges.
GOOD 2 Another very important advance is that finally after eight years of drilling here in Wetzel County, we now have a test sample from near the horizontal bore. The WVU WRI study researchers were never given access to any samples taken from the horizontal bore material itself, however. That was, of course, what they were supposed to have been allowed to do, but they were only given access to study material from the vertical section of the well bore. This report describes how we are getting closer to actually testing good samples of the black shale. It seems that we have gotten closer – but let’s see how close.
Page 11 describes that only three Antero wells in Doddridge County were chosen as the place to try to obtain samples from the horizontal bore. Considering that over 1,000 deviated/horizontal wells or wells with laterals have been drilled in the past few years, that number represents a very small fraction of wells drilled: less than .3%. Even if a high quality sample could have been obtained it might be a challenge to extrapolate test results to the waste being produced from the other wells in WV. These limitations are completely ignored in the report, however. Given the available documentation from the DEP, this seems to be a serious flaw that compromises the reliability of the entire report.
III. Samples From Vertical vs. Horizontal Well Bores
FLAW The actual samples tested from at least two of the three wells used in the study do not seem to be from the horizontal bore material. The sample from the third well might have come from the horizontal bore, but just barely. There is no way to know for sure. I will try to show this within the below chart using information provided by Antero to DEP Office of Oil & Gas. This information is in state records on Antero’s well plats, which become part of the well work application and also part of the final permit.
Table 1. Details about the samples taken from three Antero wells in Doddridge County, WV – and my concerns about the sampling process*
Antero well ID
API #
Sample’s drilling depth
Marcellus depth**
Horizontal bore length**
Comments / Issues
Morton 1H
47-017-06559
6,856 ft.
7,900 TVD***
10,600 ft.
~1,044 ft. short of reaching Marcellus formation
McGee 2H
47-017-06622
6,506 ft.
6,900 TVD
8,652 ft.
~394 ft. short of reaching Marcellus
Wentz1 H
47-017-06476
8,119 ft.
7,900 TVD
8,300 ft.
Just drilled into Marcellus by 219 ft.
* Original chart found on page 11 of report
** Based on information from Antero’s well plat
*** TVD = Total Vertical Depth
Antero is an active driller in Doddridge County. If any company knows where to find the Marcellus formation it is that company. Well plats are very detailed, technical documents provided to the DEP by the operator regarding the well location, watershed, and leased acres and property boundaries. We need to trust that the information on those plats is accurate and has been reviewed and approved by the permitting agency. Those plats also give the depth of the Marcellus and the length and heading of the lateral or horizontal bore. The Marshall University report gives the drilling depth when the sample was taken on the surface. Using these available well plat records from the DEP it appears that at two of the wells the sample (and its test results included in the report) came from material produced when the experienced drilling operator was not yet into the shale formation.
On the third well, Wentz 1H, the numbers seem to indicate that the sample was taken when the driller said that they were just barely within the shale layer – by 219 feet. Since the drill cuttings take some time to return to the surface from over 7,000 feet down, drilling just a few hundred feet would not at all guarantee that the returned cuttings were totally from the black shale. The processing of the drill cuttings at the shaker table and separator and centrifuge and the mixing in the tubs all cast some doubt on whether the sample, wherever it was taken from, was truly from the horizontal bore material.
On page 11 there is a clear and unambiguous statement:
Three representative sets of drill cuttings from the horizontal drilling activities within the Marcellus Shale formation were collected.
A successful attempt to get three such samples might have then allowed an appropriate waste characterization to be done as needed to accomplish the five required research topics listed in the report’s cover letter. Only an accurate chemical and radiological waste characterization would have allowed scientifically justifiable conclusions to be formulated and then allow for accurate legislation and regulations. It does not seem that West Virginia yet has the required scientific data upon which to confidently formulate laws and regulations to protect public health with regard to shale waste disposal.
Would it not seem prudent – if one wanted a good, representative sample – to make absolutely sure that the operator was, in fact, drilling in the black shale and that the cuttings returning to the surface were, in fact, from the Marcellus bore? That approach would have been eminently defensible and easily accomplished by just waiting for drilling to progress into the lateral bore far enough that the drill cuttings returning to the surface were in fact from the black shale. There might be plausible explanations for this apparent inconsistency or error. Of course, it might be speculated that the Antero-provided information on the well plats is incorrect and not intended to be accurate, or perhaps the driller is not really sure yet where the Marcellus layer starts. There may be many other possible scenarios of explanations. Time will tell.
IV. Research Observations Review
Landfill disposal of drill cuttings
GOOD There are a number of recommendations and suggestions in the study on landfills and leachate related conditions. It seems that a number of these proposals are very accurate and should be implemented. For example:
The report clearly restates that drill cuttings are known to contain radioactive compounds. Since all landfill liners will eventually leak, and since landfills already have ground water test wells for monitoring for potential ground water contamination due to leaking liners, then the well samples should be tested for radiological isotopes. Good idea. They are not required to do that now, but this recommendation should be implemented immediately (pgs. 17 and 21).
GOOD The report recommends that the Publicly Owned Treatment Works (POTW) or in the case of Wetzel County, the on-site wastewater treatment plants, should also test their effluent for radioactive isotopes. This is very important since there is no way to efficiently filter out many of the radioactive isotopes. Such contaminants will pass through traditional wastewater treatment plants.
It is also very useful that the report recommends that all the National Pollution Discharge Elimination System (NPDES) limits at the POTWs be reviewed and required to take into consideration the significantly more challenging chemical and radiological makeup of the shale waste products.
V. Economic Considerations on an Industry Supported Mono-Fill
The legislature asked that the DEP evaluate the feasibility of the natural gas industry to build, own, or operate its own landfill solely for the disposal of the known radioactive waste. This request seems to be a very reasonable approach, since for decades we have only put known radioactive waste products into dedicated landfills that are exclusively and specifically designed for the long term storage of the special waste material.
The discussion of the economic considerations is extremely complete and detailed. They are given in Appendix I and take into consideration a very thorough economic feasibility study of such a proposed endeavor. This section seems to have been compiled by a very talented professional team.
FLAW However, some of the basic assumptions are a bit askew. For example:
The initial Abstract of the financial analysis states that two new landfills would be needed because we do not want to have the well operators to drive any further than they do now. Interesting. This seems to be not too different than a homeowner while in search for privacy and quiet, builds a home far out into the country and then expects the public sewage lines to be extended miles to his new home so he would not have to incur the cost of a septic system. Homebuilders in rural settings should know they will have to incur expenses for their waste disposal needs. Should gas companies expect that communities to provide cheap waste disposal for them?
More than 15 pages later, the most important aspect is clearly stated that, “…the most salient benefit of establishing a separate landfill sited specifically to receive (radioactive) drill cuttings would be the preservation of existing disposal capacity of existing fills for future waste disposal”. Meaning for my (our) grandchildren. See page 175.
Comprehensive and sound financial details later explain that having the natural gas operators build, operate, and eventually close their own radioactive waste depository landfill would involve a lot of their capital and involve some risk to them. It is stated that their money would be better used drilling more wells. The conclusion then seems to be that, all around, it is simply cheaper and less risky for the gas industry to put all their waste products into our Municipal Waste Landfills, and later residents should incur the costs and risk to build another land fill for their household garbage when needed.
VI. Report Omissions
Within the report section dealing with the leachate test results, it is casually mentioned that not only do the landfills receiving shale waste materials have radioactive contaminated leachate, but the other tested landfills do, as well. However, rather than raising a very red flag and expressing concern over a problem that no one has looked into, the report implies we should not worry about any radioactive waste because it might be in all landfills (pg. 139).
Nowhere within the radiological discussion is there any mention of what might be called speciation of radioactive isotopes. The report does state that the test for both gross alpha and gross beta, are considered a “scanning procedure.” The speciation process is sort of a slice and dice procedure, showing exactly what isotopes are responsible for the activity that is being indicated. This process, however, does not seem to have been done on the landfill leachate test samples. The general scanning process cannot do that. Appendix H, pages 141-142, contains detailed facts on radiation dose, risk, and exposure. This might have been a good place to also discuss the proper EPA testing protocols, used or not used, and why.
A short discussion of the DEP-required landfill entrance radiation monitors is included on page 146. The installed monitors are the goalpost type. Trucks drive between them at the entrance and when they cross the scales. It seems that the report should have emphasized that that type of monitor will primarily only detect high-energy gamma radiation. However what is omitted on page 144 is that the primary form of decay for radium-226 is releasing alpha particles. The report is ambiguous in saying the decay products of radium-226 include both alpha particles and some gamma radiation, but radium-266 is not a strong gamma emitter. It is very unlikely that a normal steel enclosed roll-off box would ever trip the alarm setting with a load of drill cuttings. However those monitors are still useful since they will detect the high-energy gamma radiation from a truck carrying a lot of medical waste (pg. 17).
It is stated on page 144 that the greatest health risk due to the presence of radium-226 is the fact that its daughter product is radon-222. Radium-226 has a half-life of 1,600 years, compared to radon’s 3.8 days. This difference might seem to imply that radon is less of a concern. Given the multitude of radium-226 going into our landfills means that we will be producing radon for a very long time.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2015/05/Drill-cuttings-at-landfill-3894-crop-e1432757459333.jpg400899FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2015-08-18 09:06:432020-03-12 14:04:17Landfill Disposal of WV Oil and Gas Waste – A Report Review
Ohio waterways face headwinds in the form of hydraulic fracturing water demand and waste disposal
By Ted Auch, PhD – Great Lakes Program Coordinator, and Elliott Kurtz, GIS Intern and University of Michigan Graduate Student
In just 44 of its 88 counties, Ohio houses 1,134 wells – including those producing oil and natural gas and Class II injection wells into which the industry’s waste is disposed. Last month we wrote about Ohio’s disturbing fracking waste disposal trend and the disproportionate influence of neighboring states. (Prior to that Ariel Conn at Virginia Tech outlined the relationship between Class II Injection Wells and induced seismicity on FracTracker.) This time around, we are digging deeper into how water demand is related to Class II disposal trends.
Ohio’s Utica oil and gas wells are using 7 million gallons of freshwater – or 2.4-2.8 million more than the average well cited by the US EPA.1 Below we explore the inter-county differences of the water used in these oil and gas wells, and how demand compares to residential water demand and wastewater production.
Please refer to Table 1 at the end of this article regarding the following findings.
Utica Shale Freshwater Demand
Data indicate that there may be serious threats to Ohio’s water security on the horizon due to the oil and gas industry.
The counties of Guernsey and Monroe are next up with water demand and waste water generation at rates of 14.6 and 10.3 million gallons per year. However, the 11.4 million gallons of freshwater demand and fracking waste produced by these two counties 114 Utica and Class II wells still accounts for roughly 81% of residential water demand.
The wells within the six-county region including Meigs, Washington, Athens, and Belmont along the Ohio River use 73 million gallons of water and generate 51 million gallons of wastewater per year, while the hydraulic fracturing industry’s water-use footprint ranges between 48 and 17% of residential demand in Coshocton and Athens, respectively. Class II Injection well disposal accounts for a lion’s share of this footprint in all but Belmont County, with injection well activities equaling 77 to 100% of the industry’s water footprint (see Figure 1 for county locations and water stress).
Figure 1. Primary Southeast Ohio counties experiencing Utica Shale and Class II water stress
The next eight-county cohort is spread across the state from the border of Pennsylvania and the Ohio River to interior Appalachia and Central Ohio. Residential water demand there equals 428 million gallons, while the eight county’s 92 Utica and 90 Class II wells have accounted for 15 million gallons of water demand and disposal. Again the injection well component of the industry accounts for 5.8% of the their 7.7% footprint relative to residential demand. The range is nearly 10% in Vinton and 5.3% in Jefferson County.
The next cohort includes twelve counties that essentially surround Ohio’s Utica Shale region from Stark and Mahoning in the Northeast to Pickaway, Hocking, and Gallia along the southwestern perimeter of “the play.” These counties’ residents consume 405 million gallons of water and generate 329 million gallons of wastewater annually. Meanwhile the industry’s 69 Class II wells account for 53 million gallons – a 2.8% water footprint.
Finally, the 11 counties with the smallest Utica/Class II footprint are not suprisingly located along Lake Erie, as well as the Michigan and Indiana border, with water demand and wastewater production equalling nearly 117 billion gallons per year. Meanwhile the region’s 3 Utica and 18 Class II wells have utilized 59 million gallons. These figures equate to a water footprint of roughly 00.15%, more aligned with the 1% of total annual water use and consumption for the hydraulic fracturing industry cited by the US EPA this past June.
Future Concerns and Projections
Industry will see their share of the region’s hydrology increase in the coming months and years given that injection well volumes and Utica Shale demand is increasing by 1.04 million gallons and 405-410 million gallons per quarter per well, respectively. The number of people living in these 42 counties is declining by 0.6% per year, however, 1.4% in the 10 counties that have seen the highest percentage of their water resources allocated to Utica and Class II operations. Additionally, hydraulic fracturing permitting is increasing by 14% each year.2
Table 1. Residential, Utica Shale, and Class II Injection well water footprint across forty-two Ohio Counties (Note: All volumes are in millions of gallons)
2. Auch, W E, McClaugherty, C, Gallemore, C, Berghoff, D, Genshock, E, Kurtz, E, & Jurjus, R. (2015). Ramification of current and future production, resource utilization, and land-use change in the Ohio Utica Shale Basin. Paper presented at the National Environmental Monitoring Conference, Chicago, IL.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2015/08/InjectionWells-Feature.jpg400900Ted Auch, PhDhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngTed Auch, PhD2015-08-11 10:42:442020-03-12 14:04:43Threats to Ohio’s Water Security
Waste disposal is an issue that causes quite a bit of consternation even amongst those that are pro-fracking. The disposal of fracking waste into injection wells has exposed many “hidden geologic faults” across the US as a result of induced seismicity, and it has been linked recently with increases in earthquake activity in states like Arkansas, Kansas, Texas, and Ohio. Here in OH there is growing evidence – from Ashtabula to Washington counties – that injection well volumes and quarterly rates of change are related to upticks in seismic activity.
Origins of Fracking Waste
Furthermore, as part of this analysis we wanted to understand the ratio of Ohio’s Class II waste that has come from within Ohio and the proportion of waste originating from neighboring states such as West Virginia and Pennsylvania. Out of 960 Utica laterals and 245+ Class II wells, the results speak to the fact that a preponderance of the waste is coming from outside Ohio with out-of-state shale development accounting for ≈90% of the state’s hydraulic fracturing brine stream to-date. However, more recently the tables have turned with in-state waste increasing by 4,202 barrels per quarter per well (BPQPW). Out-of-state waste is only increasing by 1,112 BPQPW. Such a change stands in sharp contrast to our August 2013 analysis that spoke to 471 and 723 BPQPW rates of change for In- and Out-Of-State, respectively.
Brine Production
Figure 1. Ohio Class II Injection Well trends In- and Out-Of-State, Cumulatively, and on Per Well basis (n = 248).
For every gallon of freshwater used in the fracking process here in Ohio the industry is generating .03 gallons of brine (On average, Ohio’s 758 Utica wells use 6.88 million gallons of freshwater and produce 225,883 gallons of brine per well).
Back in August of 2013 the rate at which brine volumes were increasing was approaching 150,000 BPQPW (Learn more, Fig 5), however, that number has nearly doubled to +279,586 BPQPW (Note: 1 barrel of brine equals 32-42 gallons). Furthermore, Ohio’s Class II Injection wells are averaging 37,301 BPQPW (1.6 MGs) per quarter over the last year vs. 12,926 barrels BPQPW – all of this between the initiation of frack waste injection in 2010 and our last analysis up to and including Q2-2013. Finally, between Q3-2010 and Q1-2015 the exponential increase in injection activity has resulted in a total of 81.7 million barrels (2.6-3.4 billion gallons) of waste disposed of here in Ohio. From a dollars and cents perspective this waste has generated $2.5 million in revenue for the state or 00.01% of the average state budget (Note: 2.5% of ODNR’s annual budget).
Freshwater Demand Growing
Figure 2. Ohio Class II Injection Well disposal as a function of freshwater demand by the shale industry in Ohio between Q3-2010 and Q1-2015.
The relationship between brine (waste) produced and freshwater needed by the hydraulic fracturing industry is an interesting one; average freshwater demand during the fracking process accounts for 87% of the trend in brine disposal here in Ohio (Fig. 2). The more water used, the more waste produced. Additionally, the demand for OH freshwater is growing to the tune of 405-410,000 gallons PQPW, which means brine production is growing by roughly 12,000 gallons PQPW. This says nothing for the 450,000 gallons of freshwater PQPW increase in West Virginia and their likely demand for injection sites that can accommodate their 13,500 gallons PQPW increase.
Where will all this waste go? I’ll give you two guesses, and the first one doesn’t count given that in the last month the ODNR has issued 7 new injection well permits with 9 pending according to the Center For Health and Environmental Justice’s Teresa Mills.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2015/07/Injection-Feature.jpg400900Ted Auch, PhDhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngTed Auch, PhD2015-07-09 14:54:002020-07-21 10:30:05OH Class II Injection Wells – Waste Disposal and Industry Water Demand
Technologically-enhanced, naturally-occurring radioactive materials, also known as TENORM, are produced when radionuclides deep in the earth are brought to the surface by human activity such as oil and gas drilling. The radioactive materials, which include uranium (U), thorium (th), potassium-40 (K-40) and their decay products, occur naturally in the environment. These materials are known to dissolve in produced water, or brine, from the hydraulic fracturing process (e.g. fracking), can be found in drilling muds, and can accumulate in drilling equipment over time.
Bringing more of this TENORM to the surface has the potential to greatly impact public health and the environment. Since 2013, the Pennsylvania Department of Environmental Protection (PA DEP) has been gathering raw data on TENORM associated with oil and gas activity in the state. The study was initiated due to the volume of waste containing high TENORM concentrations in the state’s landfills, something that is largely unregulated at the state and federal level. In January 2015, the PA DEP released a report that outlined their findings and conclusions, including potential exposures, TENORM disposal practices, and possible environmental impacts.
Radioactivity Study Overview
Drilling mud being collected on the well pad
This review touches on the samples tested, the findings, and the conclusions drawn after analysis. The main areas of concern included potential exposure to workers, members of the public, and the environment.
The samples gathered by the DEP came from 38 well sites, conventional and unconventional, by testing solids, liquids, ambient air, soils, and natural gas near oil and gas activity in Pennsylvania. All samples contained TENORM or were in some way impacted by TENORM due to oil and gas operations. The samples were mainly tested for radioactive isotopes, specifically radium, through radiological surveys.
The PA DEP concluded in the cases of well sites, wastewater treatment plants (POTW), centralized wastewater treatment plants, zero liquid discharge plants, landfills, natural gas in underground storage, natural gas fired power plants, compressor stations, natural gas processing plants, radon dosimetry (the calculation and assessment of the radiation dose received by the human body), and oil and gas brine-treated roads that there is little potential for internal radiation exposure to workers and members of the public. In spite of this, each section of the report typically concluded with: however, there is a potentialfor radiological environmental impacts…
Examples of these findings include:
There is little potential for radiological exposure to workers and members of the public from handling and temporary storage of produced water on natural gas well sites. However, there is a potential for radiological environmental impacts from spills of produced water from unconventional natural gas well sites and from spills that could occur from the transportation of this fluid.
There is little potential for radiological exposure to workers and members of the public from sediment-impacted soil at landfills that accepted O&G waste for disposal. However, there may be a radiological environmental impact to soil from the sediments from landfill leachate treatment facilities that treat leachate from landfills that accept O&G waste for disposal.
Radium 226 was detected within the hydraulic fracturing fluid ranging from 64.0-21,000 pCi/L. Radium-228 was also detected ranging from 4.5-1,640 pCi/L. The hydraulic fracturing fluid was made up of a combination of fresh water, produced water, and reuse flowback fluid. There is little potential impact for radiological exposure to workers and members of the public from handling and temporary storage of flowback fluid on natural gas well sites. However, there is a potential for radiological environmental impacts from spills of flowback fluid on natural gas well sites and from spills that could occur from the transport of this fluid.
Nine influent and seven effluent leachate samples were collected at the nine selected landfills. Radium was detected in all of the leachate samples. Radium-226 concentrations were detected in produced water samples ranging from 40.5 – 26,600 pCi/L. Radium-228 concentrations were also detected ranging from 26.0 – 1,900 pCi/L. The Ra-226 activity in unconventional well site produced water is approximately 20 times greater than that observed in conventional well site produced water. The ratio of Ra-226 to Ra-228 in unconventional well site produced water is approximately eight times greater than that found in conventional well site produced water. (Sections 3.3.4 and 3.6.3) (PA DEP TENORM study report section 9.0)
While the report comprehensively covers the processes from drilling to end users, the number of samples collected and analyzed are very sparse for a state-wide study. Just to give an idea, only 8 well sites were sampled during the flowback phase and of the 8 only 4 had enough volume to analyze. Of 14 drill mud samples collected, only 5 were analyzed as liquids, and alpha & beta analysis was only done on one sample.
Obtaining the proper sample size is often a major barrier for field studies. Additional research needs to be conducted with a larger sample size and more rigorous exposure monitoring to determine specific risk metrics for workers and the public.
Current Handling of TENORM
From drilling to distribution, there are many topics of concern associated with TENORM; however, we will focus on the current treatment of TENORM waste, the release of data, and the transparency of this issue.
According to the DEP report, hydraulic fracturing produces an enormous stream of waste by-products. Safe disposal of this waste has not yet been devised. A few of the conclusions concerning TENORM disposal and treatment in the report listed some areas of concern, identified below:
Filter cake[1] and its radiological environmental impact if spilled, and
The amount of radioactive waste entering the landfills in PA, which reached 430,317 tons in the first 10 months of 2014.
In unison with the conclusions were recommendations, where the report “recommends considering limiting radioactive effluent discharge from landfills, and adding radium-226 and radium-228 to annual sample analysis of leachate from landfills.” Additionally, the report states that if something such as filter cake spills, it will bring into question the safety of long-term disposal and suggest a protocol revision.
Public Health Concerns
The report identified two places where there is a higher than average radioactive exposure risk for workers and community members of the public: specifically at centralized wastewater treatment plants and zero liquid discharge plants that treat oil and gas wastewater. An additional unknown is whether there is a potential inhalation or ingestion hazard from fixed alpha and beta surface radioactivity if materials are disturbed. As a general precaution, they recommend the evaluation of worker’s use of protective equipment under certain circumstances.
Although research has not come to a consensus regarding a safe level of radiation exposure, it should not be assumed that any exposure is safe. Past research has evaluated two types of radiation exposure: stochastic and non-stochastic, both of which have their own risks and are known to be harmful to the human body. The EPA has defined stochastic effects as those associated with long-term, low level exposure to radiation, while non-stochastic effects are associated with short-term, high-level exposure. From past scientific research, radiation is known to cause cancer and alter DNA, causing genetic mutations that can occur from both stochastic and non-stochastic exposure. Radiation sickness is also common, which involves nausea, weakness, damage to the central nervous system, and diminished organ function. Exposure levels set by the EPA and other regulatory agencies fall at 100 millirem (mrem) per year to avoid acute health effects. As a point of reference, medical X-rays deliver less than 10 mrem, and yearly background exposure can be about 300 mrem.
In the report, Radiological Dose and Risk Assessment of Landfill Disposal of TENORM in North Dakota, Argonne National Laboratory researchers suggest that the exposure to workers be limited and monitored. In many of their studies, they found the doses exceed the 100 mrem/year level in the workers when the appropriate attire is not worn during working hours, which raised some concern.
The DEP deems certain radiation levels “allowable”, but it should be noted that allowable doses are set by federal agencies and may be arbitrary. Based on the PA DEP’s report, consumers of produced gas can get up to 17.8% of their yearly radiation allowance, while POTW workers could get up to 36.3% of their yearly allowable dose. According to the Nuclear Information and Resource Service, radiation bio-accumulates in ecosystems and in the body, which introduces a serious confounder in understanding the risk posed by a dose of 17.8% per year.
Transparency of Radiation Risk
The DEP has been gathering data for their TENORM report since 2012. In July of 2014, Delaware Riverkeeper Network filed a Right-to Know request to obtain the information that the DEP had collected in order for their expert to analyze the raw data. The department refused to release the information, insisting that “the release of preliminary invalidated data, including sample locations, could likely result in a substantial and demonstrable risk of physical harm, pose a security risk and lead to erroneous and/or misleading characterizations of the levels and effects of the radioactive risks.” Essentially, the DEP was equating the risks of radioactive material to the risks of releasing raw data — two incomparable risks. DRN appealed, claiming that they simply sought the raw information, which is presumed public unless exempt, and would have no risk on the public. PA DEP was ordered to release their records to DRN within 30 days.
Conclusion
One observation that you could take from this report is the lack of regulatory advancement. The study is filled with suggestions, like:
Radium should be added to the PA spill protocol to ensure cleanups are adequately characterized,
A limited potential was found for recreationists on roads with oil and gas brine from conventional natural gas wells–further study should be conducted, and
More testing is needed to identify areas of contamination and any area should be cleaned up.
Intent doesn’t make the changes; action does. Will any regulations change, at least in Pennsylvania where radioactive materials are returning to the surface on a daily basis? There seems to be no urgency when it comes to regulating TENORM and its many issues at the state level. Are workers, citizens, and the environment truly being protected or will we wait for a disaster to spur action?
Footnotes:
[1] This is the residue deposited on a permeable medium when a slurry, such as a drilling fluid, is forced against the medium under pressure. Filtrate is the liquid that passes through the medium, leaving the cake on the medium.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2015/05/Drill-cuttings-at-landfill-3894-crop-e1432757459333.jpg400899FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2015-06-16 09:00:402020-03-12 14:09:05Has radioactivity risk from oil and gas activity been underrated?
Oklahoma has made news recently because its earthquake story is so dramatic. The state that once averaged one to two magnitude 3 earthquakes per year now averages one to two per day. This same state, which never used to be seismically active, is now more seismically active than California. In terms of understanding the connection between wastewater disposal wells and earthquakes, though, it may be more helpful to look at other states first. Let us explore this issue further in Man-made Earthquakes, Part 2.
How other states handle induced seismicity
In 2010 and 2011, Arkansas experienced a swarm of earthquakes near the town of Greenbrier that culminated in a magnitude 4.7 earthquake. Officials in Arkansas ordered a moratorium on all disposal wells in the area, and earthquake activity quickly subsided.
In late 2011, Ohio experienced small earthquakes near a disposal well that culminated in a magnitude 4 earthquake that shook and startled residents. The disposal well was shut down, and the earthquakes subsided. Subsequent research into the earthquake confirmed that the disposal well in question had, in fact, triggered the earthquake. A swarm of earthquakes last year in Ohio shut down another well, and again, after the wastewater injection ceased, the earthquakes subsided.
Similarly in Kansas, after two earthquakes of magnitudes 4.7 and 4.9 shook the state in late 2014, officials ordered wells in two southern counties to decrease the volume of water injected into the ground. Again, earthquake activity quickly subsided.
A seismologist’s toolbox
A favorite saying among scientists is that correlation does not equal causation, and it’s easy to apply that phrase to the correlations seen in Ohio, Arkansas, and Kansas. Yet scientists remain certain that wastewater disposal wells can trigger earthquakes. So what are some of the techniques they use to come to these conclusions? At the Virginia Seismological Observatory (VTSO), two of the tools we used to determine a connection were cross-correlation programs and beach ball diagrams.
Cross-correlation
The VTSO research, which was funded by the National Energy Technology Laboratory, looked specifically at earthquake swarms that have popped up a couple times near a wastewater disposal well in West Virginia. We used a cross-correlation program to distinguish earthquakes that were likely triggered by the nearby well from events that might be natural or related to mining activity.
A seismic station records all of the vibrations that occur around it as squiggly lines. When an earthquake wave passes through, its squiggly lines take on a specific shape, known as a waveform, that seismologists can easily recognize (as an example, the VTSO logo in Fig. 1 was designed using a waveform from one of West Virginia’s potentially induced earthquakes.)
Figure 1. Virginia Tech Seismological Observatory logo w/waveform
For naturally occurring earthquakes, the waveforms will have some variation in shape because they come from different faults in different locations. When an injection well triggers earthquakes, it typically activates faults that are within close proximity, resulting in greater similarities between waveforms. A cross-correlation program is simply a computer program that can run through days, weeks, or months of data from a seismometer to find those similar waveforms. When matching waveforms indicate that earthquake activity is occurring near an injection well – and especially in regions that don’t have a history of seismic activity – we can conclude the earthquakes are triggered by human activity.
Beach Balls
Any earthquake fault, whether it’s active or ancient, is stressed to its breaking point. The difference is that, in places like California that are active, the natural forces against the faults often change, which triggers earthquakes. Ancient faults are still highly stressed, but the ground around them has become more stabilized. However at any point in time, if an unexpected force comes along, it can still trigger an earthquake.
Figure 2. Beach ball diagrams of 16 of the largest earthquakes in Oklahoma in 2014, all showing similar focal mechanisms, which is indicative of induced seismicity.
Earthquake faults don’t all point in the same direction, which means different forces will affect faults differently. Depending on their orientation, some faults might shift in a north-south direction, some might shift in an east-west direction, some might be tilted at an angle, while others are more upright, etc. Seismologists use focal mechanisms to describe the movement of a fault during an earthquake, and these focal mechanisms are depicted by beach ball diagrams (Figure 2). The beach ball diagrams look, literally, like black and white beach balls. Different quadrants of the “beach ball” will be more dominant depending on what type of fault it was and how it moved (See USGS definition of Focal Mechanisms and the “beach ball” symbol).
When an earthquake is triggered by an injection well, it means that the fluid injected into the ground is essentially the straw that broke the camel’s back. Earthquake theory predicts that the forces from an injection well won’t trigger all faults, but only those that are oriented just right. Since we expect that only certain faults with just the right orientation will get triggered, that means we also expect the earthquakes to have similar focal mechanisms, and thus, similar beach ball diagrams. And that’s exactly what we see in Oklahoma.
Cross-correlation programs and beach ball diagrams are only two tools we used at the VTSO to confirm which earthquakes were induced, but seismologists have many means of determining if an earthquake is induced or natural.
Limitations of science?
With so much strong scientific evidence, why can people in industry still claim there isn’t enough science to officially confirm that an injection well triggered an earthquake? In some cases, these claims are simply wrong. In other cases, though, especially in Oklahoma, the problem is that no one was monitoring the disposal wells and the earthquakes from the start. Well operators were not required to publicly track the volumes of water they injected into wells until recently, and no one monitored for nearby earthquake activity. The big problem is not a lack of scientific evidence, but a lack of data from industry to perform sufficient research. Scientists need information about the history, volume, and pressure of fluid injection at a disposal well if they’re to confirm whether or not earthquakes are triggered by it. Often, that information is proprietary and not publically available, or it may not exist at all.
At this point though, two other factors make direct correlations between injection wells and earthquakes in Oklahoma even more difficult:
So many wells have injected signficiant volumes of water in close enough proximity that pointing a finger at a specific well is more challenging.
A large number of wells have injected water for so many years, that the earthquakes are migrating farther and farther from their original source. Again, pointing a finger at a specific well gets harder with time.
What we know
We know what induced seismicity is and why it occurs. We know that if a wastewater injection well disposes of large volumes of fluids deep underground in a region that has existing faults, it will likely trigger earthquakes. We know that if a region previously had few earthquakes, and then sees an uptick in earthquakes after wastewater injection begins, the earthquakes are likely induced. We know that if we want to understand the situation better, we need more seismic stations near disposal wells so we can more accurately monitor the area for seismicity both before and after the well becomes active.
What don’t we know?
We don’t know how big an induced earthquake can get. Oklahoma’s largest earthquake, which was also the largest induced earthquake ever recorded in the United States, was a magnitude 5.6. That’s big enough to cause millions of dollars of damage. Worldwide, the largest earthquake suspected to be induced occurred near the Koyna Dam in India, where a magnitude 6.3 earthquake killed nearly 200 people in 1967.
Can an earthquake that large occur in the central U.S.? The best guess right now: yes.
Seismologists suspect that an induced earthquake could get as big as the size of the fault. If a fault is big enough to trigger a magnitude 7 or 8 earthquake, then that is potentially how large an induced earthquake could be. In the early 1800s, three earthquakes between magnitudes 7 and 8 struck along the New Madrid Fault Zone near St. Louis, Missouri. Toward the end of the 1800s, a magnitude 7 earthquake shook Charleston, South Carolina. In those two areas, injection wells could potentially trigger very large earthquakes.
We have no historic record of earthquakes that large in Oklahoma, so right now, the best guess is that the largest an earthquake could get there would be between a magnitude 6 and 6.5. That would be big enough to cause significant damage, injuries, and possibly death.
The solution
What’s the take-home message from all of this?
First, the science exists to back up the conclusion that wastewater injection wells trigger earthquakes.
Second, if we want to get a better feel for which wells are more problematic, we need funding, seismic stations, and staff to monitor seismic activity around all high-volume injection wells, along with a history of injection times, volumes and pressures at the well.
Third, this is a problem that, if left unchecked, has the potential to result in major damage, incredible expense, and possibly loss of life.
Induced earthquakes are a real phenomenon. While more research is necessary to help us better understand the intricacies of these events and to identify correlations in complex cases, the general cause of the earthquake swarms in Oklahoma and other states is not a mystery. They are man-made problems, backed up by decades of scientific research. They have the potential to create significant damage, but we have the wherewithal to prevent them. We don’t need to go to the extreme of shutting down all wells, but rather, we just need to be able to monitor the wells and ensure that they don’t trigger earthquakes. If a well does trigger an earthquake, then at that point, the well operators can either experiment with significantly decreasing the volume of water that’s injected, or the well can be shut down completely. Understanding and acknowledging the connection between injection wells and earthquakes will make induced seismicity a much easier problem to solve.
Now, seismologists from around the country — including Oklahoma — are convinced that these earthquakes are the result of human activity, also known as induced or triggered seismicity. Yet many people, especially those in the oil industry, still refute such an argument. Just what is the science that has seismologists so convinced that the earthquakes are induced and not natural?
Hidden Faults
Over the last billion years (give or take a couple hundred million), colliding tectonic plates have created earthquake zones, just as we see today in California, Japan, Chile and Nepal. As geologic processes occurred, these zones shifted and moved and were covered up, and the faults that once triggered earthquakes achieved a state of equilibrium deep in the basement rocks of the earth’s crust. But the faults still exist. If the delicate balance that keeps these fault systems stable ever shifts, the ancient faults can still move, resulting in earthquakes. Because these inactive faults are so deep, and because they can theoretically exist just about anywhere, they’re incredibly difficult to map or predict – until an earthquake occurs.
Thanks to historic reports of earthquakes in the central and eastern United States, we know there are some regions, far away from tectonic plate boundaries, that occasionally experience large earthquakes. Missouri and South Carolina, for example, suffered significant and damaging earthquakes in the last 200 hundred years, yet these states lie nowhere near a plate boundary. We know that fault zones exist in these locations, but we have no way of knowing about dormant faults in regions of the country that haven’t experienced earthquakes in the last couple hundred years.
What is induced seismicity?
As early as the 1930s, seismologists began to suspect that extremely large volumes of water could impact seismic activity, even in those regions where earthquakes weren’t thought to occur. Scientists found that after certain reservoirs were built and filled with water, earthquake swarms often followed. This didn’t happen everywhere, and when it did, the earthquakes were rarely large enough to be damaging. These quakes were large enough to be felt, however, and they represented early instances of human activity triggering earthquakes.[1]
Research into induced seismicity really picked up in the 1960s. The most famous example of man-made earthquakes occurred as a result of injection well activity at the Rocky Mountain Arsenal. The arsenal began injecting wastewater into a disposal well 12,000 feet deep in March of 1962, and by April of that year, people were feeling earthquakes. Researchers at the arsenal tracked the injections and the earthquakes. They found that each time the arsenal injected large volumes of water (between 2 and 8 million gallons per month, or 47,000 to 190,000 barrels), earthquakes would start shaking the ground within a matter of weeks (Figure 1).
Figure 1. Rocky Mountain Arsenal fluid injection correlated to earthquake frequency
Figure 2. South Carolina experienced induced earthquakes after filling a reservoir
When the injections ended, the earthquakes also ceased, usually after a similar time delay, but some seismicity continued for a while. The well was active for many years, and the largest earthquake thought to be induced by the injection well actually occurred nearly a year and a half after injection officially ended. That earthquake registered as a magnitude 5.3. Scientists also noticed that over time, the earthquakes moved farther and farther away from the well.
Research at a reservoir in South Carolina produced similar results; large volumes of water triggered earthquake swarms that spread farther from the reservoir with time (Figure 2).
When people say we’ve known for decades that human activity can trigger earthquakes, this is the research they’re talking about.
Why now? Why Oklahoma?
Injection Well in Ohio. Photo by Ted Auch
Seismologists have known conclusively and for quite a while that wastewater injection wells can trigger earthquakes, yet people have also successfully injected wastewater into tens of thousands of wells across the country for decades without triggering any earthquakes. So why now? And why in Oklahoma?
The short answers are:
At no point in history have we injected this much water this deep into the ground, and
It’s not just happening in Oklahoma.
One further point to clarify: General consensus among seismologists is that most of these earthquakes are triggered by wastewater disposal wells and not by hydrofracking (or fracking) wells. That may be a point to be contested in a future article, but for now, the largest induced earthquakes we’ve seen have been associated with wastewater disposal wells and not fracking. This distinction is important when considering high-pressure versus high-volume wells. A clear connection between high-pressure wells and earthquakes has not been satisfactorily demonstrated in our research at the Virginia Tech Seismological Observatory (VTSO) (nor have we seen it demonstrated elsewhere, yet). High-volume wastewater disposal wells, on the other hand, have been connected to earthquakes.
At the VTSO, we looked at about 8,000 disposal wells in Oklahoma that we suspected might be connected to induced seismicity. Of those, over 7,200 had maximum allowed injection rates of less than 10,000 barrels per month, which means the volume is low enough that they’re unlikely to trigger earthquakes. Of the remaining 800 wells, only 300 had maximum allowed injection rates of over 40,000 barrels per month — and up to millions of barrels per year for some wells. These maximum rates are on par with the injection rates seen at the Rocky Mountain Arsenal, and our own plots indicate a correlation between high-volume injection wells and earthquakes (Figure 3-4).
Figure 3. Triangles represent wastewater injection wells scaled to reflect maximum volume rates. Wells with high volumes are located near earthquakes.
Figure 4. Triangles represent wastewater injection wells scaled to reflect maximum pressure. Wells with high pressures are not necessarily near earthquakes.
This does not mean that all high-volume wells will trigger earthquakes, or that lower-volume wells are always safe, but rather, it’s an important connection that scientists and well operators should consider.
Starting in 2008 and 2009, with the big oil and gas plays in Oklahoma, a lot more fluid was injected into a lot more wells. As the amount of fluid injected in Oklahoma has increased, so too have the number of earthquakes. But Oklahoma is not the only state to experience this phenomenon. Induced earthquakes have been recorded in Arkansas, Colorado, Kansas, New Mexico, Ohio, West Virginia and Texas.
In the last four years, Arkansas, Kansas, Ohio and Texas have all had “man-made” earthquakes larger than magnitude 4, which is the magnitude at which damage begins to occur. Meanwhile, in that time period, Colorado experienced its second induced earthquake that registered larger than magnitude 5. Oklahoma may have the most induced and triggered earthquakes, but the problem is one of national concern.
[1] Induced seismicity actually dates back to the late 1800s with mining, but the connection to high volumes of fluid was first recognized in the 1930s. However, the extent to which it was documented is unknown.
