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Oil wastewater pit

Wastewater Pits Still Allowed in California

By Kyle Ferrar, Western Program Coordinator

Above-ground, unlined, open-air sumps/ponds

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.

References

  1. USGS. 2014. Oil, Gas, and Groundwater Quality in California – a discussion of issues relevant to monitoring the effects of well stimulation at regional scales.. California Water Science Center. Accessed 10/1/15.
  2. CCST. 2015. Well Stimulation in California. California Council on Science and Technology. Accessed 9/1/15.
  3. Cart, Julie. 2/26/15. Hundreds of illicit oil wastewater pits found in Kern County . Los Angeles Times. Accessed 9/1/15.

The Curious Case of the Shrinking Utica Shale Play

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

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).

Total Ohio Utica Shale Production Days 2011 to Q1-2015

Total Ohio Utica Shale Oil Production 2011 to Q1-2015

Total Ohio Utica Shale Gas Production 2011 to Q1-2015

Total Ohio Utica Shale Brine Production 2011 to Q1-2015

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).

Layout & Volume (2010 to Q1-2015, Gallons) of Ohio’s Active Class II Injection Wells

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.

Per Day Ohio Utica Shale Oil Production 2011 to Q1-2015

Per Day Ohio Utica Shale Gas Production 2011 to Q1-2015

Per Day Ohio Utica Shale Brine Production 2011 to Q1-2015

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?

Injection wells in OH for disposing of oil and gas wastewater

Threats to Ohio’s Water Security

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.

OH Water Use

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).

Primary Southeast Ohio Counties experiencing Utica Shale and Class II 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)

Table1

Footnotes & Resources

1. In their recent “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources” (Note: Ohio’s hydraulically fractured wells are using 6% reused water vs. the 18% cited by the EPA).

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.

Northeast Ohio Class II injection wells taken via FracTracker's mobile app, May 2015

OH Class II Injection Wells – Waste Disposal and Industry Water Demand

By Ted Auch, PhD – Great Lakes Program Coordinator

Waste Trends in Ohio

Map of Class II Injection Volumes and Utica Shale Freshwater Demand in Ohio

Map of Class II Injection Volumes and Utica Shale Freshwater Demand in Ohio. Explore dynamic map

It has been nearly 2 years since last we looked at the injection well landscape in Ohio. Are existing disposals wells receiving just as much waste as before? Have new injection wells been added to the list of those permitted to receive oil and gas waste? Let’s take a look.

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

Ohio Class II Injection Well trends In- and Out-Of-State, Cumulatively, and on Per Well basis (n = 248).

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

Ohio Class II Injection Well disposal as a function of freshwater demand by the shale industry in Ohio between Q3-2010 and Q1-2015.

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.

Earthquake damage photo from Wikipedia

The Science Behind OK’s Man-made Earthquakes, Part 2

By Ariel Conn, Seismologist and Science Writer with the Virginia Tech Department of Geosciences

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.)

Virginia Tech Seismological Observatory logo

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.

Beach ball diagrams of 16 of the largest earthquakes in Oklahoma in 2014, all showing similar focal mechanisms, which is indicative of induced seismicity.

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:

  1. So many wells have injected signficiant volumes of water in close enough proximity that pointing a finger at a specific well is more challenging.
  2. 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.

WV Field Visits 2013

H 2 O Where Did It Go?

By Mary Ellen Cassidy, Community Outreach Coordinator, FracTracker Alliance

A Water Use Series

Many of us do our best to stay current with the latest research related to water impacts from unconventional drilling activities, especially those related to hydraulic fracturing.  However, after attending presentations and reading recent publications, I realized that I knew too little about questions like:

  • How much water is used by hydraulic fracturing activities, in general?
  • How much of that can eventually be used for drinking water again?
  • How much is removed from the hydrologic cycle permanently?

To help answer these kinds of questions, FracTracker will be running a series of articles that look at the issue of drilling-related water consumption, the potential community impacts, and recommendations to protect community water resources.

Ceres Report

We have posted several articles on water use and scarcity in the past here, here, here and here.  This article in the series will share information primarily from Monika Freyman’s recent Ceres report, Hydraulic Fracturing & Water Stress: Water Demand by the Numbers, February 2014.  If you hunger for maps, graphs and stats, you will feast on this report. The study looks at oil and gas wells that were hydraulically fractured between January 2011 and May 2013 based on records from FracFocus.

Class 2 UI Wells

Class 2 UI Wells

Water scarcity from unconventional drilling is a serious concern. According to Ceres analysis, horizontal gas production is far more water intensive than vertical drilling.  Also, the liquids that return to the surface from unconventional drilling are often disposed of through deep well injection, which takes the water out of the water cycle permanently.   By contrast, water uses are also high for other industries, such as agriculture and electrical generation.  However, most of the water used in agriculture and for cooling in power plants eventually returns to the hydrological cycle.  It makes its way back into local rivers and water sources.

In the timeframe of this study, Ceres reports that:

  • 97 billion gallons of water were used, nearly half of it in Texas, followed by Pennsylvania, Oklahoma, Arkansas, Colorado and North Dakota, equivalent to the annual water need  of 55 cities with populations of ~ 5000 each.
  • Over 30 counties used at least one billion gallons of water.
  • Nearly half of the wells hydraulically fractured since 2011 were in regions with high or extremely high water stress, and over 55% were in areas experiencing drought.
  • Over 36% of the 39,294 hydraulically fractured wells in the study overlay regions experiencing groundwater depletion.
  • The largest volume of hydraulic fracturing water, 25 billion gallons, was handled by service provider, Halliburton.

Water withdrawals required for hydraulic fracturing activities have several worrisome impacts. For high stress and drought-impacted regions, these withdrawals now compete with demands for drinking water supplies, as well as other industrial and agricultural needs in many communities.  Often this demand falls upon already depleted and fragile aquifers and groundwater.  Groundwater withdrawals can cause land subsidence and also reduce surface water supplies. (USGS considers ground and surface waters essentially a single source due to their interconnections).  In some areas, rain and snowfall can recharge groundwater supplies in decades, but in other areas this could take centuries or longer.  In other areas, aquifers are confined and considered nonrenewable.   (We will look at these and additional impact in more detail in our next installments.)

Challenges of documenting water consumption and scarcity

Tracking water volumes and locations turns out to be a particularly difficult process.  A combination of factors confuse the numbers, like conflicting data sets or no data,  state records with varying criteria, definitions and categorization for waste, unclear or no records for water volumes used in refracturing wells or for well and pipeline maintenance.

Along with these impediments, “chain of custody” also presents its own obstacles for attempts at water bookkeeping. Unconventional drilling operations, from water sourcing to disposal, are often shared by many companies on many levels.  There are the operators making exploration and production decisions who are ultimately liable for environmental impacts of production. There are the service providers, like Halliburton mentioned above, who oversee field operations and supply chains. (Currently, service providers are not required to report to FracFocus.)  Then, these providers subcontract to specialists such as sand mining operations.  For a full cradle-to-grave assessment of water consumption, you would face a tangle of custody try tracking water consumption through that.

To further complicate the tracking of this industry’s water, FracFocus itself has several limitations. It was launched in April 2011 as a voluntary chemical disclosure registry for companies developing unconventional oil and gas wells. Two years later, eleven states direct or allow well operators and service companies to report their chemical use to this online registry. Although it is primarily intended for chemical disclosure, many studies, like several of those cited in this article, use its database to also track water volumes, simply because it is one of the few centralized sources of drilling water information.  A 2013 Harvard Law School study found serious limitations with FracFocus, citing incomplete and inaccurate disclosures, along with a truly cumbersome search format.  The study states, “the registry does not allow searching across forms – readers are limited to opening one PDF at a time. This prevents site managers, states, and the public from catching many mistakes or failures to report. More broadly, the limited search function sharply limits the utility of having a centralized data cache.”

To further complicate water accounting, state regulations on water withdrawal permits vary widely.  The 2011 study by Resources for the Future uses data from the Energy Information Agency to map permit categories.  Out of 30 states surveyed, 25 required some form of permit, but only half of these require permits for all withdrawals. Regulations also differ in states based on whether the withdrawal is from surface or groundwater.  (Groundwater is generally less regulated and thus at increased risk of depletion or contamination.)  Some states like Kentucky exempt the oil and gas industry from requiring withdrawal permits for both surface and groundwater sources.

Can we treat and recycle oil and gas wastewater to provide potable water?

WV Field Visits 2013Will recycling unconventional drilling wastewater be the solution to fresh water withdrawal impacts?  Currently, it is not the goal of the industry to recycle the wastewater to potable standards, but rather to treat it for future hydraulic fracturing purposes.  If the fluid immediately flowing back from the fractured well (flowback) or rising back to the surface over time (produced water) meets a certain quantity and quality criteria, it can be recycled and reused in future operations.  Recycled wastewater can also be used for certain industrial and agricultural purposes if treated properly and authorized by regulators.  However, if the wastewater is too contaminated (with salts, metals, radioactive materials, etc.), the amount of energy required to treat it, even for future fracturing purposes, can be too costly both in finances and in additional resources consumed.

It is difficult to find any peer reviewed case studies on using recycled wastewater for public drinking purposes, but perhaps an effective technology that is not cost prohibitive for impacted communities is in the works. In an article in the Dallas Business Journal, Brent Halldorson, a Roanoke-based Water Management Company COO, was asked if the treated wastewater was safe to drink.  He answered, “We don’t recommend drinking it. Pure distilled water is actually, if you drink it, it’s not good for you because it will actually absorb minerals out of your body.”

Can we use sources other than freshwater?

How about using municipal wastewater for hydraulic fracturing?  The challenge here is that once the wastewater is used for hydraulic fracturing purposes, we’re back to square one. While return estimates vary widely, some of the injected fluids stay within the formation.  The remaining water that returns to the surface then needs expensive treatment and most likely will be disposed in underground injection wells, thus taken out of the water cycle for community needs, whereas municipal wastewater would normally be treated and returned to rivers and streams.

Could brackish groundwater be the answer? The United States Geological Survey defines brackish groundwater as water that “has a greater dissolved-solids content than occurs in freshwater, but not as much as seawater (35,000 milligrams per liter*).” In some areas, this may be highly preferable to fresh water withdrawals.  However, in high stress water regions, these brackish water reserves are now more likely to be used for drinking water after treatment. The National Research Council predicts these brackish sources could supplement or replace uses of freshwater.  Also, remember the interconnectedness of ground to surface water, this is also true in some regions for aquifers. Therefore, pumping a brackish aquifer can put freshwater aquifers at risk in some geologies.

Contaminated coal mine water – maybe that’s the ticket?  Why not treat and use water from coal mines?  A study out of Duke University demonstrated in a lab setting that coal mine water may be useful in removing salts like barium and radioactive radium from wastewater produced by hydraulic fracturing. However, there are still a couple of impediments to its use.  Mine water quality and constituents vary and may be too contaminated and acidic, rendering it still too expensive to treat for fracturing needs. Also, liability issues may bring financial risks to anyone handling the mine water.  In Pennsylvania, it’s called the “perpetual treatment liability” and it’s been imposed multiple times by DEP under the Clean Streams Law. Drillers worry that this law sets them up somewhere down the road, so that courts could hold them liable for cleaning up a particular stream contaminated by acid mine water that they did not pollute.

More to come on hydraulic fracturing and water scarcity

Although this article touches upon some of the issues presented by unconventional drilling’s demands on water sources, most water impacts are understood and experienced most intensely on the local and regional level.   The next installments will look at water use and loss in specific states, regions and watersheds and shine a light on areas already experiencing significant water demands from hydraulic fracturing.  In addition, we will look at some of the recommendations and solutions focused on protecting our precious water resources.

Class II Oil and Gas Wastewater Injection and Seismic Hazards in CA

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance Shake Ground Cover

In collaboration with the environmental advocacy groups Earthworks, Center for Biological Diversity, and Clean Water Action, The FracTracker Alliance has completed a proximity analysis of the locations of California’s Class II oil and gas wastewater injection wells to “recently” active fault zones in California. The results of the analysis can be found in the On Shaky Ground report, available for download at www.ShakyGround.org.1

Production of oil and natural gas results in a large and growing waste stream. Using current projections for oil development, the report projects a potential 9 trillion gallons of wastewater over the lifetime of the Monterey shale. In California the majority of wastewater is injected deep underground for disposal in wells deemed Class II wastewater injection.  The connection between seismic activity and underground injections of fluid has been well established, but with the current surge of shale resource development the occurrence of earthquakes in typically seismically inactive regions has increased, including a recent event in Ohio covered by the LA Times.   While both hydraulic fracturing and wastewater injection wells have been linked to the induction of seismic activity, the impacts of underground injection wells used for disposal are better documented and linked to larger magnitude earthquakes.

Therefore, while hydraulic fracturing of oil and gas wells has also been documented to induce seismic activity, the focus of this report is underground injection of waste fluids.

Active CA Faults

A spatial overview of the wastewater injection activity in California and recently active faults can be viewed in Figure 1, below.


Figure 1. California’s Faults and Wastewater Injection Wells. With this and all maps on this page, click on the arrows in the upper right hand corner of the map to view it fullscreen and to see the legend and more details.

The focus of the On Shaky Ground report outlines the relationship between does a thorough job reviewing the literature that shows how the underground injection of fluids induces seismic activity.  The proximity analysis of wastewater injection wells, conducted by The FracTracker Alliance, provides insight into the spatial distribution of the injection wells.  In addition, the report M7.8 earthquake along the San Andreas fault could cause 1,800 fatalities and nearly $213 billion in economic damages.2  To complement the report and provide further information on the potential impacts of earthquakes in California, FracTracker created the maps in Figure 2 and Figure 3.

Shaking Assessments

Figure 2 presents shaking amplification and shaking hazards assessments. The dataset is generated from seismic evaluations.  When there is an earthquake, the ground will amplify the seismic activity in certain ways.  The amount of amplification is typically dependent on distance to the earthquake event and the material that comprises the Earth’s crust.  Softer materials, such as areas of San Francisco built on landfills, will typically shake more than areas comprised of bedrock at the surface.  The type of shaking, whether it is low frequency or high frequency will also present varying hazards for different types of structures.  Low frequency shaking is more hazardous to larger buildings and infrastructure, whereas high frequency events can be more damaging to smaller structure such as single family houses.  Various assessments have been conducted throughout the state, the majority by the California Geological Survey and the United States Geological Survey.


Figure 2. California Earthquake Shaking Amplification and Class II Injection Wells

Landslide Hazards

Below, Figure 3. Southern California Landslide and Hazard Zones expands upon the map included in the On Shaky Ground report; during an earthquake liquefaction of soil and landslides represent some of the greatest hazards.  Liquefaction refers to the solid earth becoming “liquid-like”, whereas water-saturated, unconsolidated sediments are transformed into a substance that acts like a liquid, often in an earthquake. By undermining the foundations of infrastructure and buildings, liquefaction can cause serious damage. The highest hazard areas shown by the liquefaction hazard maps are concentrated in regions of man-made landfill, especially fill that was placed many decades ago in areas that were once submerged bay floor. Such areas along the Bay margins are found in San Francisco, Oakland and Alameda Island, as well as other places around San Francisco Bay. Other potentially hazardous areas include those along some of the larger streams, which produce the loose young soils that are particularly susceptible to liquefaction.  Liquefaction risks have been estimated by USGS and CGS specifically for the East Bay, multiple fault-slip scenarios for Santa Clara and for all the Bay Area in separate assessments.  There are not regional liquefaction risk estimate maps available outside of the bay area, although the CGS has identified regions of liquefaction and landslide hazards zones for the metropolitan areas surrounding the Bay Area and Los Angeles.  These maps outline the areas where liquefaction and landslides have occurred in the past and can be expected given a standard set of conservative assumptions, therefore there exist certain zoning codes and building requirements for infrastructure.


Figure 3. California Liquefaction/Landslide Hazards and Class II Injection Wells

Press Contacts

For more information about this report, please reach out to one of the following media contacts:

Alan Septoff
Earthworks
(202) 887-1872 x105
aseptoff@earthworksaction.org
Patrick Sullivan
Center for Biological Diversity
(415) 632-5316
psullivan@biologicaldiversity.org
Andrew Grinberg
Clean Water Action
(415) 369-9172
agrinberg@cleanwater.org

References

  1. Arbelaez, J., Wolf, S., Grinberg, A. 2014. On Shaky Ground. Earthworks, Center for Biological Diversity, Clean Water Action. Available at ShakyGround.org
  2. Jones, L.M. et al. 2008. The Shakeout Scenario. USGS Open File Report 2008-1150. U.S. Department of the Interior, U.S. Geological Survey.

 

Ohio Production and Injection Well Firms Map

Our latest Ohio-focused map shows the many companies involved in directional drilling in the state and the contact information for these firms.

Layer Descriptions

1. UNIVERSAL WELL SERVICES

Universal Well Services Inc. is a major firm involved in all manner of directional drilling services with an office in Wooster, OH, one in Allen, KY, six in Pennsylvania, six in Texas, and one in West Virginia

2. LLC & MLP’s

This is an inventory of 410 Ohio directional drilling affiliated LLC and MLP firms and contact information. Seventy-eight percent of these firms are domiciled in Ohio. The other primary states that house these firms are Pennsylvania (22), Texas (23), and West Virginia (9). The Economist wrote of these types of firms:

The move away from the C corporation began in earnest in 1975. Wyoming, that vibrant business hub, adopted a new entity structure, the limited-liability company (LLC). Imported from Panama, it provided the tax treatment of a partnership while preserving the corporate protection from individual liability for company debts and litigation. Other states followed in adopting the model. Businesses were quick to see the advantages. The various new types of firm that have risen in the wake of the LLC… make similar use of partnership structures. They have tended to be industry- or sector-specific, at least to begin with. The energy business has a lot of MLPs not only because it needs capital but because it is an easy place to set them up: since 1987, tax law has allowed “mineral or natural resource” companies to operate as listed partnerships, while withholding that privilege from others. But as with other pass-through structures, the constraints are being lowered and circumvented.

3. DRILLING FIRMS

This is an inventory of 393 Ohio Department of Natural Resources permitted directional and injection drilling firms with single locations and their contact information. Seventy-six percent of these firms are domiciled in Ohio with the other primary states of incorporation being Pennsylvania (15), Texas (14), Michigan (11), and West Virginia (9). Only 3 of these firms listed in the Ohio RBDMS Microsoft Access Database contained correct contact information or addresses. According to ODNR staff – and primary FOIA contact:

… it looks like the [active drillers] list [doesn’t contain] much information on the companies in general…We have mailing information for the operating companies, but a lot of the time they subcontract out to get their drillers. We do not require the information of the drillers they contract.

4. ADDITIONAL DRILLERS

This is an inventory of the 40 known locations for six firms permitted to drill in Ohio. The same lack of contact and address data for these firms were true for this data. The primary firms are Butch’s Rathole and Nomac Drilling Corporation. Given that the ODNR RBDMS does not indicate the actual location from which these companies migrated into the Ohio shale industry we decided to include all known locations for these firms.

5. CANADIAN FIRMS

This is an inventory of the 14 known locations for the 5 Canadian drilling firms permitted in Ohio. The primary firm is Savannah Drilling, which is composed of 10 locations across Alberta and Saskatchewan.

6. AMERICAN SUPPORTING CO.

This is an inventory of 1,837 Ohio energy firms operating in the Utica and Marcellus shale or servicing it in a secondary or tertiary fashion. Seventy-five percent (1,386) of these firms are domiciled in Ohio with secondary hotspots in Texas (76), West Virginia (65), Pennsylvania (49), Michigan (34), Colorado (27), Illinois (22), Oklahoma (21), California (16), New York and New Jersey (27), Kentucky (14).

7. ADDITIONAL SUPPORTING CO.

This shows an inventory of 10 Ohio energy firms operating in the Utica and Marcellus shale or servicing it in a secondary or tertiary fashion extracted from the ODNR RBDMS that did not contain locational or contact information.

8. CANADIAN SUPPORTING CO.

This is an inventory of 5 (1 company Mar Oil Company was not found) Canadian energy firms operating in the Utica and Marcellus shale or servicing it in a secondary or tertiary fashion.

9. BRINE HAULERS

This is an inventory of 505 ODNR permitted brine haulers active in the transport and disposal of hydraulic fracturing waste either via injection or waste landfill disposal. Seventy-six percent of these firms are domiciled in Ohio with the primary cities being Zanesville (18), Cambridge, Wooster, and Millersburg (12 each), Canton and Marietta (11 each), Columbus (9), Jefferson (9), Logan (8), and North Canton and Newark (7 each). Pennsylvania and West Virginia are home to 84 and 32 brine haulers, respectively.

DEP Calls on Natural Gas Drillers to Stop Giving Treatment Facilities Wastewater

Reposted from the Department of Environmental Protection website:

HARRISBURG — At the direction of Governor Tom Corbett, acting Department of Environmental Protection Secretary Michael Krancer today called on all Marcellus Shale natural gas drilling operators to cease by May 19 delivering wastewater from shale gas extraction to 15 facilities that currently accept it under special provisions of last year’s Total Dissolved Solids (TDS) regulations.

“While the prior administration allowed certain facilities to continue to take this wastewater, conditions have changed since the implementation of the TDS regulations,” Krancer said. “We now have more definitive scientific data, improved technology and increased voluntary wastewater recycling by industry. We used to have 27 grandfathered facilities; but over the last year, many have voluntarily decided to stop taking the wastewater and we are now down to only 15. More than half of those facilities are now up for permit renewal. Now is the time to take action to end this practice.”

Read the full article»

Below is a snapshot creating by John Detwiler using FracTracker’s DataTool. It shows the wastewater treatment facilities mentioned in DEP’s ‘voluntary’ advisory of April 19, 2011. The larger the star, the greater the facility’s permitted wastewater flow (mgd).

To close the legend on the left, click the compass.

Greene County Man Charged with Wastewater Dumping

Archived

This article has been archived and is provided for reference purposes only.

 

The Pennsylvania Attorney General’s office released a statement yesterday, saying that criminal charges have been filed against Robert Allen Shipman from Green County and his company, Allen’s Waste Water Services, Inc., for allegedly dumping millions of gallons of waste, including gas drilling waste, in six southwestern Pennsylvania counties between 2003 and 2009. There are 98 charges against him personally, and an addtional 77 counts against his company.

The grand jury and Acting Pennsylvania Attorney General William H. Ryan, Jr. allege that Mr. Shipman’s company operated in the following manner:

  • Drivers were instructed to mix several waste types, obscuring the actual contents, allowing for easier disposal
  • Destroying original manifests with forged ones, in order to overcharge customers
  • Leaving valves open on trucks at gas wells after dark or in rainy periods, in order to illegally dump wastewater onto the ground
  • Dumping into a drain at a Allan’s Waste Water Services facility, which drains directly into a stream

According to the Post Gazette, Mr. Shipman has posted a $50,000 bond, and Allan’s Waste Water Services is open for business.

If convicted, Mr. Shipman could face jail time and fines up to $1.5 million and another $1.2 million for his company. According to the Post-Gazette article, Mr. Shipman’s operation earned him up to $7 million per year.

A preliminary hearing has been set for March 25th in Greene County.