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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.

Landfill disposal of drill cuttings

Has radioactivity risk from oil and gas activity been underrated?

Reviewing a Pennsylvania TENORM Study

By Juliana Henao, Communications Intern

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.

According to the EPA, ~30% of domestic oil and gas wells produce TENORM. Surveys have shown that 90% of the wells show some TENORM concentrations, while others have nothing at all. However, with increasing natural gas exploration and production in Pennsylvania’s Marcellus Shale, there is a parallel increase in TENORM. According to Dr. Marvin Resnikoff, an international expert on radiation, drilling companies and geologists locate the Marcellus Shale layer by way of its higher level of radiation.

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 potential for 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)

According to Melody Fleck from Moshannon Group- Sierra Club Executive Committee:

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.

On a federal level, there are no specific regulations governing many aspects of TENORM, such as sludge or solids containing TENORM from water treatment plants. Additionally, if concentrations of U or Th make up less than .05% by weight, they are seen as an “unimportant quantity” and are exempt from NRE regulation. Currently, 13 states regulate TENORM with varying degrees of standards. Hazardous waste facilities in each state can choose to accept TENORM materials as long as they don’t exceed certain concentrations.

Today, about 12 of PA’s 50 landfills accept such radioactive waste from oil and gas activity at a 1:50 dilution ratio (related to their other intake sources). Under RCRA’s Land Disposal Restrictions, “dilution is prohibited as treatment for both listed and characterized wastes.”

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:

  1. Filter cake [1] and its radiological environmental impact if spilled, and
  2. 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.

The Science Behind OK’s Man-made Earthquakes, Part 1

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

On April 21, the Oklahoma Geological Survey issued a statement claiming that the sharp rise in Oklahoma earthquakes — from only a couple per year to thousands — was most likely caused by wastewater disposal wells associated with major oil and gas plays. This is huge news after years of Oklahoma scientists hesitating to place blame on an industry that provides so many jobs.

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).

Rocky Mountain Arsenal fluid injection correlated to earthquake frequency

Figure 1. Rocky Mountain Arsenal fluid injection correlated to earthquake frequency

South Carolina experienced induced earthquakes after filling a reservoir

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?

Class II Injection Well. Photo by Lea Harper

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).

Triangles represent wastewater injection wells scaled to reflect maximum volume rates. Wells with high volumes are located near earthquakes.

Figure 3. Triangles represent wastewater injection wells scaled to reflect maximum volume rates. Wells with high volumes are located near earthquakes.

Triangles represent wastewater injection wells scaled to reflect maximum pressure. Wells with high pressures are not necessarily 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.

Footnote

[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.

Name that oil and gas storage container [quiz]

By Bill Hughes, WV Community Liaison

We were recently asked if there is a reliable way to determine what constituents are being housed in certain types of oil and gas storage containers. While there is not typically a simple and straightforward response to questions like this, some times we can provide educated guesses based on a few photos, placards, or a trip to the site.

One way to become better informed is to follow the trucks. The origins of the trucks will determine whether the current stage in the extraction process is drilling or fracturing (the containers cannot be for both unless they are delivering fresh water). Combine that with good side-view photos of the trucks will tell you if they are heavier going into the site or heavier leaving. Look for the clearance between the rear tires and the frame. Tanker trucks can typically carry 4000 gallons or 100 barrels.

For a quick guide to oil and gas storage containers, see the “quiz” we have compiled below:

Storage Container Quiz

1. What is in this yellow tank?

Photo 1

Q1: Photo 1

Q1: Photo 2 (same tank zoomed in)

Answer: This yellow 500-barrel wheelie storage tank in photos 1 and 2 is a portable storage tank, identified in the placard in photo 2 as having held oil base drill mud at one time. Drillers prefer to keep certain tanks identified for specific purposes if at all possible. This is especially true if they have paid extra to get a tank “certified clean” to use for fresh water storage. A certified clean tank does not mean that the water is potable (drinkable).

Other storage containers that hold fresh water are shown below:

Shark Tanks

Shark Tanks

Shark Tanks

Shark Tanks from the sky

2. What is this truck transporting?

Q2: Truck

Q2: Truck

Answer: This type of truck is normally used to haul solid waste – such as drill cuttings going to a landfill. Some trucks, however do not make it the whole way to the landfill before losing some of their contents as shown below.

Truck-spill

Truck spill in WV

3. How about these yellow tanks?

Q3: Photo 1

Q3: Photo 1

Q3: Photo 2

Q3: Photo 2

Answer: The above storage containers are 500-barrel liquid storage tanks, also called “frac” tanks.

In photo 2 you can see that at least one tank is connected to others on either side of it. In this case you need to look at the overall operation to see what process is occurring nearby — or what had just finished — to determine what might be in the container presently.

The name plate on photo 1 says “drill mud,” which means that at one time that container might have held exactly that. Now, however, that container would likely have very little to do with drilling waste or drill cuttings. The “GP” and the number on the sign refers to Great Plains and the tank’s number. These type of tanks do not have official placards on them for the purposes of DOT labeling since they are never moved with any significant liquid in them.

4: What about these miscellaneous tanks?

Q4: Photo 1 – Tank farm with 103 blue tanks

Q4: Photo 2 – Red tanks with connecting hoses

Q4: Photo 3 – Red tanks, no connections

Answer: There is no way to know – unless you have been closely following the process in your neighborhood and know the current stage of the well pad’s drilling process. Tank farms are usually just for storage unless there is some type of filtering and processing equipment on site. The drilling crews (for either horizontal or vertical wells) do not mix their fluids with the fracturing crew. That does not mean that one tank farm could not store a selection of flowback brine—or produced water, or drilling fluids. They would be stored in separate tanks or tank groups that are connected together – usually with flex hoses.

Since I am in the area often, I know that the tanks in photos 1 and 2 were storing fresh water. Both sets were associated with a nearby hydraulic fracturing operation, which has very little to do with the drilling process.  You will never see big groups of tanks like this on a well pad that is currently being drilled.

The third set of tanks with no connections on an in-production well pad are probably just empty and storing air – but not fresh air. These tanks are just sitting there, waiting for their next assignment – storage only, not in use. Notice that there are no connecting pipes like in photo 2. The tanks in photo 3 could have held any of the following: fresh water, flowback, brine, mixed fracturing fluids, or condensate. Only the operator would know for certain.

The Water-Energy Nexus in Ohio, Part II

OH Utica Production, Water Usage, and Waste Disposal by County
Part II of a Multi-part Series
By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

In this part of our ongoing “Water-Energy Nexus” series focusing on Water and Water Use, we are looking at how counties in Ohio differ between how much oil and gas are produced, as well as the amount of water used and waste produced. This analysis also highlights how the OH DNR’s initial Utica projections differ dramatically from the current state of affairs. In the first article in this series, we conducted an analysis of OH’s water-energy nexus showing that Utica wells are using an ave. of 5 million gallons/well. As lateral well lengths increase, so does water use. In this analysis we demonstrate that:

  1. Drillers have to use more water, at higher pressures, to extract the same unit of oil or gas that they did years ago,
  2. Where production is relatively high, water usage is lower,
  3. As fracking operations move to the perimeter of a marginally productive play – and smaller LLCs and MLPs become a larger component of the landscape – operators are finding minimal returns on $6-8 million in well pad development costs,
  4. Market forces and Muskingum Watershed Conservancy District (MWCD) policy has allowed industry to exploit OH’s freshwater resources at bargain basement prices relative to commonly agreed upon water pricing schemes.

At current prices1, the shale gas industry is allocating < 0.27% of total well pad costs to current – and growing – freshwater requirements. It stands to reason that this multi-part series could be a jumping off point for a more holistic discussion of how we price our “endless” freshwater resources here in OH.

In an effort to better understand the inter-county differences in water usage, waste production, and hydrocarbon productivity across OH’s 19 Utica Shale counties we compiled a data-set for 500+ Utica wells which was previously used to look at differenced in these metrics across the state’s primary industry players. The results from Table 1 below are discussed in detail in the subsequent sections.

Table 1. Hydrocarbon production totals and per day values with top three producers in bold

County

# Wells

Total

Per Day

Oil

Gas

Brine

Production

Days

Oil

Gas

Brine

Ashland

1

0

0

23,598

102

0

0

231

Belmont

32

55,017

39,564,446

450,134

4,667

20

8,578

125

Carroll

256

3,715,771

121,812,758

2,432,022

66,935

67

2,092

58

Columbiana

26

165,316

9,759,353

189,140

6,093

20

2,178

65

Coshocton

1

949

0

23,953

66

14

0

363

Guernsey

29

726,149

7,495,066

275,617

7,060

147

1,413

49

Harrison

74

2,200,863

31,256,851

1,082,239

17,335

136

1,840

118

Jefferson

14

8,396

9,102,302

79,428

2,819

2

2,447

147

Knox

1

0

0

9,078

44

0

0

206

Mahoning

3

2,562

0

4,124

287

9

0

14

Medina

1

0

0

20,217

75

0

0

270

Monroe

12

28,683

13,077,480

165,424

2,045

22

7,348

130

Muskingum

1

18,298

89,689

14,073

455

40

197

31

Noble

39

1,326,326

18,251,742

390,791

7,731

268

3,379

267

Portage

2

2,369

75,749

10,442

245

19

168

228

Stark

1

17,271

166,592

14,285

602

29

277

24

Trumbull

8

48,802

742,164

127,222

1,320

36

566

100

Tuscarawas

1

9,219

77,234

2,117

369

25

209

6

Washington

3

18,976

372,885

67,768

368

59

1,268

192

Production

Total

It will come as no surprise to the reader that OH’s Utica oil and gas production is being led by Carroll County, followed distantly by Harrison, Noble, Belmont, Guernsey and Columbiana counties. Carroll has produced 3.7 million barrels of oil to date, while the latter have combined to produce an additional 4.5 million barrels. Carroll wells have been in production for nearly 67,000 days2, while the aforementioned county wells have been producing for 42,886 days. The remaining counties are home to 49 wells that have been in production for nearly 8,800 days or 7% of total production days in Ohio.

Combined with the state’s remaining 49 producing wells spread across 13 counties, OH’s Utica Shale has produced 8.3 million barrels of oil as well as 251,844,311 Mcf3 of natural gas and 5.4 million barrels of brine. Oil and natural gas together have an estimated value of $2.99 billion ($213 million per quarter)4 assuming average oil and natural gas prices of $96 per barrel and $8.67 per Mcf during the current period of production (2011 to Q2-2014), respectively.

Potential Revenue at Different Severance Tax Rates:

  • Current production tax, 0.5-0.8%: $19 million ($1.4 Million Per Quarter (MPQ). At this rate it would take the oil and gas industry 35 years to generate the $4.6 billion in tax revenue they proposed would be generated by 2020.
  • Proposed, 1% gas and 4% oil: At Governor Kasich’s proposed tax rate, $2.99 billion translates into $54 million ($3.9 MPQ). It would still take 21 years to return the aforementioned $4.6 billion to the state’s coffers.
  • Proposed, 5-7%: Even at the proposed rate of 5-7% by Policy Matters OH and northeastern OH Democrats, the industry would only have generated $179 million ($12.8 MPQ) to date. It would take 11 years to generate the remaining $4.42 billion in tax revenue promised by OH Oil and Gas Association’s (OOGA) partners at IHS “Energy Oil & Gas Industry Solutions” (NYSE: IHS).5

The bottom-line is that a production tax of 11-25% or more ($24-53 MPQ) would be necessary to generate the kind of tax revenue proposed by the end of 2020. This type of O&G taxation regime is employed in the states of Alaska and Oklahoma.

From an outreach and monitoring perspective, effects on air and water quality are two of the biggest gaps in our understanding of shale gas from a socioeconomic, health, and environmental perspective. Pulling out a mere 1% from any of these tax regimes would generate what we’ll call an “Environmental Monitoring Fee.” Available monitoring funds would range between $194,261 and $1.8 million ($16 million at 55%). These monies would be used to purchase 2-21 mobile air quality devices and 10-97 stream quantity/quality gauges to be deployed throughout the state’s primary shale counties to fill in the aforementioned data gaps.

Per-Day Production

On a per-day oil production basis, Belmont and Columbiana (20 barrels per day (BPD)) are overshadowed by Washington (59 BPD) and Muskingum (40 BPD) counties’ four giant Utica wells. Carroll is able to maintain such a high level of production relative to the other 15 counties by shear volume of producing wells; Noble (268 BPD), Guernsey (147 BPD), and Harrison (136 BPD) counties exceed Carroll’s production on a per-day basis. The bottom of the league table includes three oil-free wells in Ashland, Knox, and Medina, as well as seventeen <10 BPD wells in Jefferson and Mahoning counties.

With respect to natural gas, Harrison (1,840 Mcf per day (MPD)) and Guernsey counties are replaced by Monroe (7,348 MPD) and Jefferson (2,447 MPD) counties’ 26 Utica wells. The range of production rates for natural gas is represented by the king of natural gas producers, Belmont County, producing 8,578 MPD on the high end and Mahoning and Coshocton counties in addition to the aforementioned oil dry counties on the low end. Four of the five oil- or gas-dry counties produce the least amount of brine each day (BrPD). Coshocton, Medina, and Noble county Utica wells are currently generating 267-363 barrels of BrPD, with an additional seven counties generating 100-200 BrPD. Only four counties – 1.2% of OH Utica wells – are home to unconventional wells that generate ≤ 30 BrPD.

Water Usage

Freshwater is needed for the hydraulic fracturing process during well stimulation. For counties where we had compiled a respectable sample size we found that Monroe and Noble counties are home to the Utica wells requiring the greatest amount of freshwater to obtain acceptable levels of productivity (Figure 1). Monroe and Noble wells are using 10.6 and 8.8 million gallons (MGs) of water per well. Coshocton is home to a well that required 10.8 MGs, while Muskingum and Washington counties are home to wells that have utilized 10.2 and 9.5 MGs, respectively. Belmont, Guernsey, and Harrison reflect the current average state of freshwater usage by the Utica Shale industry in OH, with average requirements of 6.4, 6.9, and 7.2 MGs per well. Wells in eight other counties have used an average of 3.8 (Mahoning) to 5.4 MGs (Tuscarawas). The counties of Ashland, Knox, and Medina are home to wells requiring the least amount of freshwater in the range of 2.2-2.9 MGs. Overall freshwater demand on a per well basis is increasing by 220,500-333,300 gallons per quarter in Ohio with percent recycled water actually declining by 00.54% from an already trivial average of 6-7% in 2011 (Figure 2).

Water and production (Mcf and barrels of oil per day) in OH’s Utica Shale.

Figure 1. Average water usage (gallons) per Utica well by county

Average water usage (gallons) on a per well basis by OH’s Utica Shale industry, shown quarterly between Q3-2010 and Q2-2014.

Figure 2. Average water usage (gallons) on per well basis by OH Utica Shale industry, shown quarterly between Q3-2010 & Q2-2014.

Belmont County’s 30+ Utica wells are the least efficient with respect to oil recovery relative to freshwater requirements, averaging 7,190 gallons of water per gallon of oil (Figure 3). A distant second is Jefferson County’s 14 wells, which have required on average 3,205 gallons of water per gallon of oil. Columbiana’s 26 Utica wells are in third place requiring 1,093 gallons of freshwater. Coshocton, Mahoning, Monroe, and Portage counties are home to wells requiring 146-473 gallons for each gallon of oil produced.

Belmont County’s 14 Utica wells are the least efficient with respect to natural gas recovery relative to freshwater requirements (Figure 4). They average 1,306 gallons of water per Mcf. A distant second is Carroll County’s 250+ wells, which have injected 520 gallons of water 7,000+ feet below the earth’s service to produce a single Mcf of natural gas. Muskingum’s Utica well and Noble County’s 39 wells are the only other wells requiring more than 100 gallons of freshwater per Mcf. The remaining nine counties’ wells require 15-92 gallons of water to produce an Mcf of natural gas.

Water and production (Mcf and barrels of oil per day) in OH’s Utica Shale – Average Water Usage Per Unit of Oil Produced (Gallons of Water Per Gallon of Oil).

Figure 3. Average water usage (gallons) per unit of oil (gallons) produced across 19 Ohio Utica counties

Water and production (Mcf and barrels of oil per day) in OH’s Utica Shale – Average Water Usage Per Unit of Gas Produced (Gallons of Water Per MCF of Gas)

Figure 4. Average water usage (gallons) per unit of gas produced (Mcf) across 19 Ohio Utica counties

Waste Production

The aforementioned Jefferson wells are the least efficient with respect to waste vs. product produced. Jefferson wells are generating 12,728 gallons of brine per gallon of oil (Figure 5).6 Wells from this county are followed distantly by the 32 Belmont and 26 Columbiana county wells, which are generating 5,830 and 3,976 gallons of brine per unit of oil.5 The remaining counties (for which we have data) are using 8-927 gallons of brine per unit of oil; six counties’ wells are generating <38 gallons of brine per gallon of oil.

Water and production (Mcf and barrels of oil per day) in OH’s Utica Shale – Average Brine Production Per Unit of Oil Produced (Gallons of Brine Per Gallon of Oil)

Figure 5. Average brine production (gallons) per gallon of oil produced per day across 19 Ohio Utica Counties

The average Utica well in OH is generating 820 gallons of fracking waste per unit of product produced. Across all OH Utica wells, an average of 0.078 gallons of brine is being generated for every gallon of freshwater used. This figure amounts to a current total of 233.9 MGs of brine waste produce statewide. Over the next five years this trend will result in the generation of one billion gallons (BGs) of brine waste and 12.8 BGs of freshwater required in OH. Put another way…

233.9 MGs is equivalent to the annual waste production of 5.2 million Ohioans – or 45% of the state’s current population. 

Due to the low costs incurred by industry when they choose to dispose of their fracking waste in OH, drillers will have only to incur $100 million over the next five years to pay for the injection of the above 1.0 BGs of brine. Ohioans, however, will pay at least $1.5 billion in the same time period to dispose of their municipal solid waste. The average fee to dispose of every ton of waste is $32, which means that the $100 million figure is at the very least $33.5 million – and as much as $250.6 million – less than we should expect industry should be paying to offset the costs.

Environmental Accounting

In summary, there are two ways to look at the potential “energy revolution” that is shale gas:

  1. Using the same traditional supply-side economics metrics we have used in the past (e.g., globalization, Efficient Market Hypothesis, Trickle Down Economics, Bubbles Don’t Exist) to socialize long-term externalities and privatize short-term windfall profits, or
  2. We can begin to incorporate into the national dialogue issues pertaining to watershed resilience, ecosystem services, and the more nuanced valuation of our ecosystems via Ecological Economics.

The latter will require a more real-time and granular understanding of water resource utilization and fracking waste production at the watershed and regional scale, especially as it relates to headline production and the often-trumpeted job generating numbers.

We hope to shed further light on this new “environmental accounting” as it relates to more thorough and responsible energy development policy at the state, federal, and global levels. The life cycle costs of shale gas drilling have all too often been ignored and can’t be if we are to generate the types of energy our country demands while also stewarding our ecosystems. As Mark Twain is reported to have said “Whiskey is for drinking; water is for fighting over.” In order to avoid such a battle over the water-energy nexus in the long run it is imperative that we price in the shale gas industry’s water-use footprint in the near term. As we have demonstrated so far with this series this issue is far from settled here in OH and as they say so goes Ohio so goes the nation!

A Moving Target

ODNR projection map of potential Utica productivity from Spring, 2012

Figure 6. ODNR projection map of potential Utica productivity from spring 2012

OH’s Department of Natural Resources (ODNR) originally claimed a big red – and nearly continuous – blob of Utica productivity existed. The projection originally stretched from Ashtabula and Trumbull counties south-southwest to Tuscarawas, Guernsey, and Coshocton along the Appalachian Plateau (See Figure 6).

However, our analysis demonstrates that (Figures 7 and 8):

  1. This is a rapidly moving target,
  2. The big red blob isn’t as big – or continuous – as once projected, and
  3. It might not even include many of the counties once thought to be the heart of the OH Utica shale play.

This last point is important because counties, families, investors, and outside interests were developing investment and/or savings strategies based on this map and a 30+ year timeframe – neither of which may be even remotely close according to our model.

An Ohio Utica Shale oil production model for Q1-2013 using an interpolative Geostatistical technique called Empirical Bayesian Kriging.

Figure 7a. An Ohio Utica Shale oil production model using Kriging6 for Q1-2013

An Ohio Utica Shale oil production model for Q2-2014 using an interpolative Geostatistical technique called Empirical Bayesian Kriging.

Figure 7b. An Ohio Utica Shale oil production model using Kriging for Q2-2014

An Ohio Utica Shale gas production model for Q1-2013 using an interpolative Geostatistical technique called Empirical Bayesian Kriging.

Figure 8a. An Ohio Utica Shale gas production model using Kriging for Q1-2013

An Ohio Utica Shale gas production model for Q2-2014 using an interpolative Geostatistical technique called Empirical Bayesian Kriging.

Figure 8b. An Ohio Utica Shale gas production model using Kriging for Q2-2014


Footnotes

  1. $4.25 per 1,000 gallons, which is the current going rate for freshwater at OH’s MWCD New Philadelphia headquarters, is 4.7-8.2 times less than residential water costs at the city level according to Global Water Intelligence.
  2. Carroll County wells have seen days in production jump from 36-62 days in 2011-2012 to 68-78 in 2014 across 256 producing wells as of Q2-2014.
  3. One Mcf is a unit of measurement for natural gas referring to 1,000 cubic feet, which is approximately enough gas to run an American household (e.g. heat, water heater, cooking) for four days.
  4. Assuming average oil and natural gas prices of $96 per barrel and $8.67 per Mcf during the current period of production (2011 to Q2-2014), respectively
  5. IHS’ share price has increased by $1.7 per month since publishing a report about the potential of US shale gas as a job creator and revenue generator
  6. On a per-API# basis or even regional basis we have not found drilling muds data. We do have it – and are in the process of making sense of it – at the Solid Waste District level.
  7. An interpolative Geostatistical technique formally called Empirical Bayesian Kriging.
Digging into Waste Data

Digging into Waste Data

By Katie Mattern, FracTracker Summer Intern

Seeing is believing, as the saying goes. Without physically observing the amount of waste generated from hydraulic fracturing of unconventional oil and gas wells, it is difficult to comprehend the volume and scope of the waste produced.

The Pennsylvania Department of Environmental Protection (PADEP) makes a considerable amount of waste production data publicly available, speaking to the quantities of fluids and solids produced by 25 oil and gas operators across 25 counties. This figure, however, is only about 40% of all of the operators according to StateImpactPA. Also, complete data is not available for the 25 companies that are included, but let’s dig into some waste data simply as an exercise.

Dig Into Basic Cabot Waste Statistics

In order to gain a sense for industry trends we decided to look at data pertaining to Cabot Oil and Gas Corporation, specifically, whose entire 2013 inventory of oil and gas wells were in Susquehanna County and the surrounding region. The first and second halves of 2013 contain fairly complete records for Cabot – such as well location, waste facility location, waste type, waste quantity, and disposal method. It is interesting to note that in the comments section, all but a few of the well permit sites read “Entire water fraction of waste stream recycled at a centralized treatment plant for reuse by Cabot,” even for drill cuttings that were taken to a landfill.

The following analysis focuses on the waste generated by 264 Cabot wells during this period. All of Cabot’s unconventional oil and gas wells in Pennsylvania during 2013 were in Susquehanna County and the surrounding region.

Waste Produced

In the first 6 months of 2013 (Period 1), liquid waste – consisting of produced fluid, servicing fluid, hydraulic fracturing fluid (frac fluid) waste, and drilling fluid waste – totaled 745,898 barrels (Bbl) or over 30,000,000 gallons. Solid waste – or drill cuttings – totaled 51,981 tons.1 To put this into perspective, 745,898 Bbls is equivalent to the water usage requirements of about 4 wells in West Virginia.2 The 51,981 tons of drill cuttings weighs about the same as the average amount of garbage produced by 65,029 Americans per year, or 1.5 times the population of Susquehanna County. The fluid waste is also enough to fill approximately 48 Olympic swimming pools.

Period 2 (July through December) of 2013, consisting of 319 reporting wells, experienced a 77% increase in liquid waste, climbing past the 1 million Bbl mark to 1,340,143 Bbl. This figure is the equivalent of filling almost 85 Olympic swimming pools. Similarly, drill cuttings increased to 96,165 tons, almost double the amount generated in Period 1. The total amount of waste generated by Cabot for the entire year yields more than 2 million Bbl of liquid waste and nearly 150,000 tons of solid waste from drill cuttings1 – more than 130 Olympic swimming pools worth of water and a weight of solid waste equivalent to the average waste generated by more than 120,000 American per year- over 2.8 times the population pf Susquehanna County (see infographic below).

Digging into waste data infographic

Waste Composition

According to Cabot’s waste data, most of the liquid waste is made up of produced fluid,1 which is the saline water that returns to the surface as a byproduct of the drilling process. This fluid can be up to 10 times saltier than ocean water and can also be radioactive.3 Frac fluid waste3 contributed to the next largest amount of waste, followed by drilling fluid waste and servicing fluid. Produced fluid tripled from Period 1 to Period 2, while frac fluid waste remained fairly steady, and drilling fluid waste decreased slightly. However, the amount of servicing fluid waste generated between the first and second half of 2013 increased more than 12 times.1 Overall, the following increases were seen between Period 1 and Period 2 in 2013:

  • Fluid waste from hydraulic fracturing rose by nearly 80%
  • Solid waste rose by 85%
  • The number of unconventional oil and gas reporting wells only increased by about 20%, from 264 to 319.

Examining the data from FracFocus that is available for these reporting wells,4 it is interesting to note that the average true vertical depth of the wells decreased by about 100 feet between the two periods. Therefore, it is difficult to understand why the amount of drill cuttings increased by 85% in Period 2. Why is there such a large increase in both solid and liquid waste between these two periods when there was only a 20% increase in the number of wells? There are various theories that could result in such a dramatic increase in period 2 compared to the 6 months prior, including but not limited to:

  1. The use of more liquids for the construction or drilling processes,
  2. Longer lateral distances per horizontal well,
  3. More lax operating procedures,
  4. More detailed reporting by Cabot, and/or
  5. Stricter reporting/enforcement by the PADEP.
Dig into waste date. Waste Impoundment - Photo by Pete Stern 2013

Waste Impoundment – Photo by Pete Stern 2013

Waste Produced Means Waste Transported

Although Cabot is responsible for producing large amounts of waste, they also are recycling their liquid waste (as is listed for every site in the Period 2 data). To do so, the company transports their waste to a centralized treatment plant. There, the water is filtered so that it can be mixed with more freshwater and chemicals and be reused at another well site. However, hauling so much fluid to the centralized treatment plant requires numerous trips by tanker trucks, as well as dump trucks and trailer trucks taking drill cuttings to landfills. Some treatment facilities for PA waste are located as far away as Ohio, West Virginia, and New York. Cabot trucks travelled approximately 114,000 miles5 in Period 1 of 2013, and over 1,122,000 miles were travelled in Period 2 of 2013. The total miles travelled to transport Cabot’s waste is equivalent to almost 50 times around the earth – for one company in one state, operating in only two counties.1

Additional Considerations

Further analysis should examine the air pollution and carbon footprint generated from such extensive traffic. The miles make a difference, considering that a highly efficient tractor trailor only gets ~10 miles per gallon.

While reusing the majority of liquid waste in an effort to reduce the amount of fresh water needed for hydraulic fracturing is a positive step, transporting recycling water by truck still results in fuel used, pollutants emitted, and traffic impacts.

Cabot Oil and Gas Corp. was the second largest unconventional shale gas producer in PA behind Chesapeake Appalachia LLC, which had more than 809 reporting wells in Period 2 of 2013. With a total of 62 companies operating in PA at this time,6 the cumulative effects of waste transportation undoubtedly add up. Serious efforts should be made on the part of all oil and gas companies to reduce their waste and provide accurate and timely waste reports.


References and Resources

  1. Data obtained from the PA DEP Oil and Gas Reporting Website
  2. Data originally posted on FracTracker.org
  3. Data obtained from New York State Water Resources Institute
  4. True vertical depth measurements are missing for many of the sites in Period 1. Data obtained from FracFocus
  5. Miles calculated in Microsoft Excel using formula obtained from Blogspot.com
  6. Data obtained from StateImpact Pennsylvania

Utica Shale Drill Cuttings Production – Back of the Envelope Recipe

By Ted Auch, OH Program Coordinator, FracTracker Alliance

Ohio is the only shale gas state in the Marcellus and/or Utica Shale Basin that has decided to go “all in.” i.e. The state is moving forward with shale gas production, Class II Injection Well disposal of brine waste from fracking, and more recently the processing and disposal of drill cuttings/muds via the state’s Solid Waste Disposal (SWD) districts and waste landfills. The latter would fall under the joint ODNR, ODH, and EPA’s September 18, 2012  Solidification and Disposal Activities Associated with Drilling-Related Wastes advisory. It occurred to us that it might be time to try to estimate how much of these materials are produced here in Ohio on a per-well basis using basic math, data gleaned from Ohio’s current inventory of Utica wells and the current inventory of PLAT maps, and some broad assumptions as to the density of Ohio’s geology.

Developing the Estimate

1) Start with a 341 Actual Utica well lateral dataset generated utilizing the ODNR Ohio Oil & Gas Well Database PLAT inventory or the current inventory of 1,137 permitted Utica wells. Generate a Straight Line lateral dataset by converting this data from “XY To Line” with the following summary statistics:

Variable

Actual

Straight Line

#

341

1,137

Minimum

186

50

Maximum

20,295

12,109

Sum

2,196,856

7,190,889

Mean

6,442 ±1,480

6,386 ±1,489

Median

6,428

6,096

2) Average Vertical Depth for 109 Utica wells utilizing data from the ODNR RBDMS Microsoft Access database = 6,819 feet (207,843 centimeters)

Average Lateral + Vertical Footage = 13,205-13,261 total feet (402,488-404,195 centimeters) (Figure 1)

Ohio Utica Shale Actual Vs Straight Line Lateral Lengths

Fig. 1. An example of Actual and Straight Line Utica well laterals in Southeast Carroll County, Ohio

3) We assume a rough diameter of 8″ down to 5″ (20-13 centimeters) for all of 1) and 14″ to 8″ (36-20 centimeters) for the entirety of 2)

4) The density of 1) is roughly 2.61 g cm3 assuming the average of seven regional shale formations (Manger, 1963)

5) None of the materials being drilled through are igneous or metamorphic (limestone, siltstone, sandstone, and coal) thus the density of 2) is all going to be
≈2.75 g cm3

6) The volume of the above is calculated assuming the volume of a cylinder
(i.e., V = hπr2):

    1. Σ of Actual Lateral Length 49,205,721 cm3 * 2.61 g = 128,180,904 g
    2. Σ of Actual Lateral Length 153,991,464 cm3 * 2.75 g = 423,476,526 g

Average Lateral + Vertical Volume = 551,657,430 grams = 1,216,195 pounds =
608 tons of drill cuttings per Utica well * 829 drilled, drilling, or producing wells = 504,113 million tons

To put these numbers into perspective, the average Ohio household of 2.46 people generates about 3,933 pounds of waste per year or 1.78 metric tons.

7) Caveats include:

    • The coarse assumptions as to density of materials and the fact that these materials experience significant increases in surface area once they have been drilled through.
    • The assumptions as to pipe diameter could be over or underestimating drill cuttings due to the fact that we know laterals taper as they near their endpoint. We assume 45% of the vertical depth is comprised of 14″ diameter pipe, 40% 11″ diameter pipe, and 15% 8″ pipe. Similarly we assume the same percentage distribution for 8″, 6.5″, and 5″ lateral pipe.

Ohio Drilling Mud Generation and Processing

Caroll-Columbiana-Harrison Ohio Solid Waste District Drilling Muds Processed (January, 2011-April, 2014)

Fig. 2. Month-to-month and cumulative drilling muds processed by CCHSWD, one of six OH SWDs charged with processing shale gas drilling waste from OH, WV, and PA.

Ohio’s primary SWDs responsible for handling the above waste streams – from in state as well as from Pennsylvania and West Virginia – are the six southeastern SWDs along with the counties of Portage and Mahoning according to several anonymous sources. However, when attempting to acquire numbers that speak to the flows/stocks of fracking related SWD waste (i.e., drilling muds) the only district that keeps track of this data is the Carroll-Columbiana-Harrison Solid Waste District (CCHSWD). The CCHSWD’s Director of Administration was generous enough to provide us with this data. According to a month-over-month analysis they have processed 636,450 tons generating a fixed fee of $3.5 per ton or $2.23 million to date (Figure 2). This trend translates into a 1,046-1,571 ton monthly increase depending on how you fit your trend line to the data (i.e., linear Vs power functions) or put another way annual drilling mud increases of 12,546-18,847 tons.

 

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.

 

PA Production and Waste Data Updated

Every six months, the Pennsylvania Department of Environmental Protection (PADEP) publishes production and waste data for all unconventional wells drilled in the Commonwealth.  These data are self-reported by the industry to PADEP, and in the past, there have been numerous issues with the data not being reported in a timely fashion.  Therefore, the early versions of these two datasets are often incomplete.  For that reason, I now like to wait a few weeks before analyzing and mapping this data, so as to avoid false conclusions.  That time has now come.


This map contains production and waste totals from unconventional wells in Pennsylvania from July to December, 2013. Based on data downloaded March 6, 2014. Also included are facilities that received the waste produced by these wells. To access the legend and other map controls, please click the expanding arrows icon at the top-right corner of the map.

Production

Top 20 unconventional gas producers in PA, from July to December 2013.  The highest values in each column are highlighted in red.

Table 1: Top 20 unconventional gas producers in PA, from July to December 2013. Highest values in each column are highlighted in red.

Production values can be summarized in many ways. In this post, we will summarize the data, first by operator, then by county. For operators, we will take a look at all operators on the production report, and see which operator has the highest total production, as well as production per well (Table 1).

It is important to note that not all of the wells on the report are actually in production, and not all of the ones that are produce for the entire cycle. However, there is some dramatic variance in the production that one might expect from an unconventional well in Pennsylvania that correlates strongly with which operator drilled the well in question.  For example, the average Cabot well produces ten times the gas that the average Atlas well does.  Even among the top two producers, the average Chesapeake well produces 2.75 times as much as the average Range Resources well.

The location of the well is the primary factor in regards to production values.  74 percent of Atlas’ wells are in Greene and Fayette counties, in southwestern Pennsylvania, while 99 percent of Cabot’s wells are in Susquehanna County.  Similarly, 79 percent of Range Resources’ wells are in the its southwestern PA stronghold of Washington County, while 62 percent of Chesapeake’s wells are in Bradford county, in the northeast.

Pennsylvania unconventional gas production by county, from July to December 2013.

Table 2: PA unconventional gas production by county, from July to December 2013

Altogether, there are unconventional wells drilled in 38 Pennsylvania counties, 33 of which have wells that are producing (see Table 2).  And yet, fully 1 trillion cubic feet (Tcf) of t he 1.7 Tcf produced by unconventional wells during the six month period in Pennsylvania came from the three northeastern counties of Susquehanna, Bradford, and Lycoming.

While production in Greene County does not compare to production in Susquehanna, this disparity still does not account for the really poor production of Atlas wells, as that operator averages less than one fourth of the typical well in the county.  Nor can we blame the problem on inactive wells, as 84 of their 85 wells in Greene County are listed as being in production.  There is an explanation, however.  All of  these Atlas wells were drilled from 2006 through early 2010, so none of them are in the peak of their production life cycles.

There is a different story in Allegheny County, which has a surprising high per well yield for a county in the southwestern part of the state.  Here, all of the wells on the report were drilled between 2008 and 2013, and are therefore in the most productive part of the well’s life cycle.  Only the most recent of these wells is listed as not being in production.

Per well production during the last half of 2013 for unconventional wells in Pennsylvania by year drilled.

Table 3: Per well production during last half of 2013 for PA unconventional wells by spud year

Generally speaking, the further back a well was originally drilled, the less gas it will produce (see Table 3). At first glance, it might be surprising to note that the wells drilled in 2012 produced more gas than those drilled in 2013, however, as the data period is for the last half of 2013, there were a number of wells drilled that year that were not in production for the entire data cycle.

In addition to gas, there were 1,649,699 barrels of condensate and 182,636 barrels of oil produced by unconventional wells in Pennsylvania during the six month period. The vast majority of both of these resources were extracted from Washington County, in the southwestern part of the state.  540 wells reported condensate production, while 12 wells reported oil.

Waste

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 as proppants 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
Method of disposing of waste generated from unconventional wells in Pennsylvania from July to December 2013.

Table 4: Method of disposing of waste generated from unconventional wells in PA from July to December 2013

Solid and liquid waste disposal for the top 20 producers of unconventional liquid waste in Pennsylvania during the last half of 2013.

Table 5: Solid & liquid waste disposal for top 20 producers of PA unconventional liquid waste during last half of 2013

This table shows solid and liquid waste totals for the ten counties that produced the most liquid waste over the six month period.

Table 6: Solid & liquid waste totals for the 10 counties that produced the most liquid waste over the 6 month period

There are numerous methods for disposing of drilling waste in Pennsylvania (see Table 4). Some of the categories include recycling for future use, others are merely designated as stored temporarily, and others are disposed or treated at a designated facility.  One of the bright points of the state’s waste data is that it includes the destination of that waste on a per well basis, which has allowed us to add receiving facilities to the map at the top of the page.

As eight data columns per table is a bit unwieldy, we have aggregated the types by whether they are solid (reported in tons) or liquid (reported in 42 gallon barrels).  Because solid waste is produced as a result of the drilling and fracturing phases, it isn’t surprising that the old Atlas wells produced no new solid waste (see Table 5).  Chevron Appalachia is more surprising, however, as the company spudded 46 wells in 2013, 12 of which were started during the last half of the year.  However, Chevron’s liquid waste totals were significant, so it is possible that some of their solid waste was reported, but miscategorized.

As with production, location matters when it comes to the generation of waste from these wells. But while the largest gas producing counties were led by three counties in the northeast, liquid waste production is most prolific in the southwest (see Table 6).

Table 7: PA Unconventional operators with the most wells that produced gas, oil, and/or condensate, but no amount of waste.  The column on the right shows total number of wells that are indicated as producing, for that same operator, regardless of waste production.

Table 7: PA unconventional operators with the most wells that produced gas, oil, and/or condensate, but no amount of waste.

Finally, we will take a look at the 359 wells that are indicated as in production, yet were not represented on the waste report as of March 6th.  These remarkable wells are run by 38 different operators, but some companies are luckier with the waste-free wells than their rivals.  As there was a six-way tie for 10th place among these operators, as sorted by the number or wells that produce gas, condensate, or oil but not waste, we can take a look at the top 15 operators in this category (see Table 7). Of note, gas quantity only includes production from these wells. Column on the right shows total number of wells that are indicated as producing, for that same operator, regardless of waste production.

114 of Southwestern Energy’s 172 producing wells were not represented on the waste report as of March 6th, representing just under two thirds of the total.  In terms of the number of waste-free wells, Atlas was second, with 55.  As for the highest percentage, Dominon, Hunt, and Texas Keystone all managed to avoid producing any waste at all for each of their seven respective producing wells, according to this self-reported data.