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Mariner East 2 Pipeline Route

Mariner East 2 and Watershed Risks

Mariner East 2 (ME 2) is a $2.5 billion, 350 mile-long pipeline that, if built, would be one of the largest pipeline construction projects in Pennsylvania’s history—carving a fifty-foot wide path through 17 counties. A project of Sunoco Logistics, ME 2 would have the capacity to transport 275,000 barrels a day of propane, ethane, butane, and other hydrocarbons from the shale fields of Western Pennsylvania and neighboring states to an international export terminal in Marcus Hook, located on the Delaware River.

ME 2 has sparked a range of responses from residents in Pennsylvania, however, including concerns about recent pipeline accidents, the ethics of taking land by eminent domain, and the unknown risks to sensitive ecosystems. Below we explore the watersheds that could be impacted by this proposed pipeline.

Watershed Impacts

While some components of Sunoco’s ME 2 proposal are approved, the project requires more permits from the Pennsylvania Department of Environmental Protection (DEP) before construction can begin. Among those are permits to build through and under stream and wetlands. Many of the waters threatened by ME 2 are designated by the Commonwealth as “exceptional value” (EV) or “high quality” (HQ) and are supposed to be given greater protections from harm. Water Obstruction and Encroachment Permits, also known as “Chapter 105” permits, are required for any building activities that would disrupt any body of water, including wetlands and streams. Sunoco applied for these so-called “Chapter 105” permits in the summer of 2015, but its applications were rejected as incomplete several times.

The below map shows the ME 2 route as of May 2016 relative to the watersheds and streams it will cross. Zoom into the map to see additional layers. Note that this is the most accurate representations of ME 2’s route we have seen to date. MWA provided the shapefiles for ME 2’s route to FracTracker Alliance and continues its investigations into potential watershed impacts.

Proposed ME 2 Route

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In total, ME 2’s path will include 1,227 stream crossings, 570 wetland crossings, and 11 pond crossings. Of the 1,227 stream crossings, 19 are EV and 318 are HQ, meaning that 337 crossings will disturb what DEP refers to as “special protection” waters. In addition, there are 129 exceptional value wetlands being crossed. These numbers were compiled by Mountain Watershed Association (MWA) from Sunoco’s permitting applications. MWA also identified 2 HQ streams in Washington County, and 3 HQ streams in Blair County, that are proposed to be crossed that are not acknowledged as being HQ in Sunoco’s permits.

Public Comment Period Open

People living along the proposed route are sometimes in the best position to see what the route looks like from the ground, where wetlands and streams are, and what kinds of wetlands and streams they are. The DEP is accepting public comments on Sunoco’s ME 2 Ch. 105 permit application through Wednesday, August 24. Each DEP regional office receives separate Ch. 105 applications depending on where the pipeline routes through different counties. Those wishing to comment on the project can do so through the DEP regional office websites: DEP Southwest RegionDEP South-central Region, DEP Southeast Region. For guidance on how to write comments on permits, see MWA’s Pipeline Project Information & Talking Points.


We wish to thank Mountain Watershed Association and the Clean Air Council for helping us compile data and analysis for this article.

Written by Kirk Jalbert, PhD, MFA – Manager of Community-Based Research & Engagement, FracTracker Alliance

Koontz Class II Injection Well, Trumbull County, Ohio, (41.22806065, -80.87669281) with 260,278 barrels (10,020,704 gallons) of fracking waste having been processed between Q3-2010 and Q3-2012 (Note: Q1-2016 volumes have yet to be reported!).

OH Class II Injection Wells – Waste Disposal Trends and Images From Around Ohio

By Ted Auch, PhD – Great Lakes Program Coordinator

Hydraulic Fracturing "Fracking" at a well-pad outside Barnesville, Ohio operated by Halliburton

Hydraulic Fracturing “Fracking” at a well-pad outside Barnesville, Ohio operated by Halliburton

The industrial practice of disposing of oil and gas drilling waste into Class II injection wells causes a lot of strife for people on both sides of the fracking debate. This process has exposed many “hidden [geologic] faults” across the US as a result of induced seismicity. It has been linked in recent months and years with increases in earthquake activity in states like Arkansas, Kansas, Texas, and Ohio.

Locally, there is growing evidence in counties – from Ashtabula to Washington – that Ohio Class II injection well volumes and quarterly rates of change are related to upticks in seismic activity (Figs. 1-3). But exactly how much waste are these sites receiving, and where is it coming from? Since it has been a little over a year since last we looked at the injection well landscape here in Ohio, we decided to revisit the issue here.

Figures 1-3. Ohio Class II Injection Well disposal during Q3-2010, Q2-2012, and Q2-2015

The Class II Landscape in Ohio

In Ohio 245+ Class II Salt Water Disposal (SWD) Disposal Wells are permitted to accept unconventional oil and gas waste. Their disposal capacity and number of wells served is by far the most of any state across the Marcellus and Utica Shale plays.

Ohio’s Class II Injection wells have accepted an average of 22,750 barrels per quarter per well (BPQPW) (662,632 gallons) of oil and gas wastewater over the last year. In comparison, our last analysis uncovered a higher quarterly average (29,571 BPQPW) between the initiation of frack waste injection in 2010 and Q2-2015 (Fig. 4). This shift is likely due to the significant decrease in overall drilling activity from 2012 to 2015. Between Q3-2010 and Q1-2016, however, OH’s Class II injection wells saw an exponential increase in injection activity.  In total, 109.4 million barrels (3.8-4.6 billion gallons) of waste was disposed in Ohio. From a financial perspective this waste has generated $3.4 million in revenue for the state or 00.014% of the average state budget (Note: 2.5% of ODNR’s annual budget).

The more important point is that even in slow times (i.e., Q2-2015 to the present) the trend continues to migrate from the bottom-left to the top-right, with each of Ohio’s Class II injection wells seeing quarterly demand increases of 972 BPQPW (34,017-40,821 gallons). This means that the total volume coming into our Class II Wells is increasing at a rate of 8.2-9.8 MGs per year, or the equivalent to the water demand of several high volume hydraulically fractured wells.

With respect to the source of this waste, the story isn’t as clear as we had once thought. Slightly more than half the waste came from out-of-state during the first two years for which we have data, but this statistic plummeted to as low as 32% in the last year-to-date (Fig. 5). This change is likely do to the high levels of brine being produced in Ohio as the industry migrates towards the perimeter of the Utica Shale.

Figures 4 and 5

Freshwater Demand and Brine Production

Map of Ohio Utica Brine Production and Class II Injection Well Disposal

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Ohio Class II injection well disposal and freshwater demand

Figure 6. Ohio Class II Injection Well disposal as a function of freshwater demand by the shale industry in Ohio between Q3-2010 and Q1-2015

To gain a more comprehensive understanding of what’s going on with Class II wastewater disposal in Ohio, it’s important to look into the relationship between brine and freshwater demand by the hydraulic fracturing industry. The average freshwater demand during the fracking process, accounts for 87% of the trend in brine disposal in Ohio (Fig. 6).

As we mentioned, demand for freshwater is growing to the tune of 405-410,000 gallons PQPW in Ohio, 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.

Conclusion

Essentially, the seismic center of Ohio has migrated eastward in recent years; originally it was focused on Western counties like Shelby, Logan, Auglaize, Darke, and Miami on the Indiana border, but it has recently moved to injection well hotbed counties like Ashtabula, Trumbull, and Washington along the Pennsylvania and West Virginia borders. This growth in “induced seismicity” resulting from the uptick in frack waste disposal puts Ohio in the company of Oklahoma, Arkansas, Colorado, Kansas, New Mexico, and Texas. Each of those states have reported ≥4.0 magnitude “man-made” quakes since 2008. Between 1973 and 2008 an average of 21 earthquakes of ≥M3 were reported in the Central/Eastern US. This number jumped to 99 between 2009 and 2013, with 659 of M3+ in 2014 alone according to the USGS and Virginia Tech Seismological Observatory (VTSO). This “hockey stick moment” is exemplified in the below figure from a recent USGS publication (Fig. 7). Figure 8 illustrates the spatial relationship between recent seismic activity and Class II Injection well volumes here in Ohio. The USGS even went so far as to declare the following:

An unprecedented increase in earthquakes in the U.S. mid-continent began in 2009. Many of these earthquakes have been documented as induced by wastewater injection…We find that the entire increase in earthquake rate is associated with fluid injection wells. High-rate injection wells (>300,000 barrels per month) are much more likely to be associated with earthquakes than lower-rate wells.
– From USGS Report High-rate injection is associated with the increase in U.S. mid-continent seismicity

Figures 7 and 8

The sentiment here in Ohio regarding Class II Injection wells is best summed up by Dr. Ray Beiersdorfer, Distinguished Professor of Geology, Youngstown State University and his wife geologist Susie Beiersdorfer who jointly submitted the following quote regarding the North Star (SWIW #10) Class II Injection Well in Mahoning County, which processed 555,030 barrels (21,368,655 gallons) of fracking waste between Q4-2010 and Q4-2011[1].

The operator, D&L, and the ODNR denied the correlation in space and time between the injection of toxic fracking fluids into the well and earthquakes for over eight months in 2011. The well was shut down on December 30 and the largest seismic event, a 4.0 happened at 3:04 p.m. on December 31, 2011. Though the rules say that a “shut-in” well must be plugged after 60 days, this well is still “open” after 1656 days (July 12, 2016). This well must be plugged [and abandoned] to prevent further risks to the health and safety of the Youngstown community… According to Rick Simmers, the only thing holding this up is bankruptcy procedures. It was drilled into a fault, triggered over five hundred earthquakes, including a Magnitude 4.0 that caused damage to homes. [It is likely] that any other use of this well would trigger additional hazardous earthquakes.

Images From Across Ohio

Click on the images below to explore visual documentation and volumes disposed (as of Q1-2016) into Class II Injection wells in Ohio.

Footnote

  1. This is the infamous Lupo well which was linked to 109 tremors in Youngstown by researchers at the Lamont-Doherty Earth Observatory at Columbia University back in the Summer of 2013. The owner of the well Ben W. Lupo was subsequently charged with violating the Clean water Act.

Public Herald’s #fileroom Update

Crowdsourcing Digital PA Oil & Gas Data

FracTracker Alliance worked with Public Herald this spring to update and map oil and gas complaints filed by citizens to the Pennsylvania Department of Environmental Protection (PA DEP) as of March 2015. The result is the largest release of oil and gas records on water contamination due to fracking in PA. Additionally, Public Herald’s investigation revealed evidence of Pennsylvania state officials keeping water contamination related to fracking “off the books.”

Project Background

The mission of Public Herald, an investigative news non-profit formed in 2011, is two-fold: truth + creativity. Their work uses investigative journalism and art to empower readers and hold accountable those who put the public at risk. For this project, Public Herald aims to improve the public’s access to oil and gas information in PA by way of file reviews and data digitization. Public Herald maintains an open source website called #fileroom, where people can access a variety of digital information originally housed on paper within the PA DEP. This information is collected and synthesized with the help of donors, journalists and researchers in a collective effort with the community. To date, these generous volunteers have already donated more than 2,000 hours of their time collecting records.

The site includes complaints, permits, waste, legal cases, and gas migration investigations (GMI) conducted by the PA DEP. Additionally, there is a guide on how to conduct file reviews and how to access information through the “Right-to-Know” law at the PA DEP. They have broken down complaints and permits by county; wastes and GMI categories by cases, all of which include test results from inspections; and correspondence and weekly reports.

Some partners and contributors to the file team include Joshua Pribanic as the co-founder and Editor-in Chief, Melissa Troutman as co-founder and Executive Director, John Nicholson, who collects and researches for several databases, Nadia Steinzor as a contributor through Earthworks, and many more. Members of FracTracker working on this project include Matt Kelso, Samantha Rubright, and Kirk Jalbert.

#fileroom’s update expands the number of complaint data records collected to 18 counties – and counting!


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Landfill disposal of drill cuttings

Landfill Disposal of WV Oil and Gas Waste – A Report Review

By Bill Hughes, WV Community Liaison

As oil and gas drilling increases in West Virginia, the resulting waste stream must also be managed. House Bill 107 required the Secretary of the West Virginia Department of Environmental Protection to investigate the risks associated with landfill disposal of solid drilling waste. On July 1, 2015, a massive report was issued that details the investigation and its results: Examination of Leachate, Drill Cuttings and Related Environmental, Economic and Technical Aspects Associated with Solid Waste Facilities in West Virginia, by Marshall University.

While I must commend the State for looking into this important issue, much more needs to be done, and I have serious concerns about the validity of several aspects of this study. Since the report is almost 200 pages long, I will summarize its findings and my critiques below.

Summary of Waste Disposal Concerns in Report

The page numbers that I reference below refer to the page numbers found within the PDF version of the full study.

  1. Marcellus shale cuttings are radioactive: pgs. 17, 139, 142, 154
  2. We do not know if there is a long term problem: pg. 19
  3. About 30 million tons of waste in next few decades: pg. 176
  4. Landfill liners leak: pg. 20
  5. Owning & operating their own landfill would be expensive & risky for gas companies: pgs. 186-7
  6. Toxicity and biotic risk from drill cuttings is uncharted territory: pg. 78
  7. Landfill leachate is toxic to plants & invertebrates: pgs. 16, 95, 97
  8. Other landfills also have radioactive waste: pgs. 14-15
  9. We have no idea if this will get worse: pgs. 96, 154
  10. If all systems at landfills work as designed, leachate might not affect ground water: pg. 41

Introduction

WV Field Visits 2013

Drilling rig behind a wastewater pond in West Virginia

Any formal report comprised of 195 pages generated by a reputable school like Marshall University with additional input from Glenville State College – supported by over 2,300 pages of semi-raw data and graphs and charts and tables – requires some serious investigation prior to making comprehensive and final conclusions. However, some initial observations are needed to provide independent perspective and to help reflect on how sections of this report might be interpreted.

The overarching perspective that must be kept in mind is that the complete study was first limited by exactly what the legislature told the WV Department of Environmental Protection DEP to do. Secondly, the DEP then added other research guidelines and determined exactly what needed to be in the study and what did not belong. There were also budget and time constraints. The most constricting factor was the large body of existing data possessed by the DEP that was provided to the researchers and report writers. Because of the time restrictions, only a small amount of additional raw data could be added.

And most importantly, similar to the WVU Water Research Institute (WVU WRI) report from two years ago, it must be kept in mind that these types of studies, initiated by those elected to our well-lobbied legislature and funded and overseen by a state agency, do not occur in a political power vacuum. It was surely anticipated that the completed report might have the ability to affect the growing natural gas industry – which is supported by most in the political administration. Therefore, we must be cautious here. The presence and influence of political and economic factors need to be considered. Also, for universities to receive research contracts and government paid study requests, the focus must include keeping the customer satisfied.

My comments below on the report’s methods and findings are organized into three broad and overlapping categories:

  • GOOD  –  positive aspects, good suggestions, important observations
  • GENERAL  –  general comments
  • FLAW  –  problems, flaws, limitations
  • MOVING FORWARD  – my suggestions & recommendations

I. Water Quality: EPA Test Protocols & Datasets

Marcellus Shale (at the surface)

Marcellus Shale (at the surface)

GENERAL  It is obvious that a very smart and well-trained set of researchers put a lot of long, detailed thought into analyzing all of the available data. There must be tens of thousands of data points. Meticulous attention was put into how to assemble all of the existing years’ worth of leachate chemical and radiological information.

GOOD  There is an elaborate and detailed discussion of how to best analyze everything and how to utilize the best statistical methods and generate a uniform and integrated report. This was made difficult with non-uniform time intervals, some non-detect values, and some missing items. The researchers used a credible process, explaining how they applied the various appropriate statistical analysis methods to all the data. They provided some trends and observations and draw some conclusions.

FLAW 1  The most glaring flaw and the greatest limitation pertaining to the data sets is the nature of the very data set, which was provided to the researchers from the DEP. It is to the commendable credit of the DEP that the leachate at landfills receiving black shale drill cuttings from the Marcellus and other shale formations were, from the beginning, required to start bi-monthly testing of leachate samples at landfills that were burying drill waste products. And in general, when compared to on-site disposal as done for conventional wells, it was initially a good requirement to have the drill cuttings put into some type of landfill; that way we could keep track of where the drill cuttings are located when there are future problems.

To the best of my knowledge, until the states in the Marcellus region started allowing massive quantities of black shale waste material to be put into local landfills, we have never knowingly deposited large quantities of known radioactive industrial waste products into generic municipal waste landfills. The various waste products and drill cuttings of Marcellus black shales have been known for decades by geologists and radiochemists to be radioactive. We know better than to depose of hazardous radioactive waste in an improper way. Therefore, it is very understandable that we might not know how to best solve the problems of this particular waste product. This was and still is new territory.

FLAW 2  All of the years of leachate test samples were processed for radioactivity using what is called the clean drinking water test protocols, also referred to as the EPA 900 series. Three years ago, given the unfamiliarity of regulatory agencies with the uniqueness of this waste problem, we chose the wrong test protocol for assessing leachate samples. We speculated that the commonly used and familiar clean drinking water test procedure would work. So now we have a massive set of test results all derived from using the wrong test protocol for the radiologicals. Fortunately, all of the chemistry test results should still be reasonably useful and accurate.

At first, three years ago, this was understandable and possibly not an intentional error. Now it is widely known by hydrogeologists and radiochemists, however, that the plain EPA 900 series of test methods for determining the radioactivity of contaminated liquids do not work on liquids with high TDS — Total Dissolved Solids. Method 900.0 is designed for samples with low dissolved solid like finished drinking water supplies.

Despite this major and significant limitation, the effort by Marshall University still has some utility. For example, doing comparisons between and among the various landfills accepting drill waste might provide some interesting observations and correlations. It is clearly known now, however, that the protocols that were used for all samples from the start when testing for gross alpha, gross beta and radium-226 and radium-228 in leachate, can only result in very inaccurate, under-reported data. Therefore, it is not possible to draw any valid conclusions on several very important topics, including:

  • surface water quality,
  • potential ground water contamination,
  • exposure levels at landfills and public health implications,
  • and policy and regulations considerations.

Labs certified to test for radiological compounds and elements are very familiar with the 900 series of EPA test procedures. These protocols are intended to be used on clean drinking water. They are not intended to be used on “sludgy” waters or liquids contaminated with high dissolved solids like all the many liquid wastes from black shale operations like flowback and produced water and brines and leachate. The required lab process for sample size, preparation, and testing will guarantee that the results will be incorrect.

In no place in the final 195 page report have I seen any discussion of which EPA test protocol was used for the newer samples and why was it used. It has also not yet been seen in the 2,300+ pages of supportive statistical and analytical results, either. The fact that the wrong protocol was used three years ago is very understandable. However, this conventional EPA 900 series was still being used on the additional very recent (done in fall of 2014 and spring of 2015) samples that were included in the final report. The researchers, without any justification or discussion or explanations continued to use the wrong test protocol.

The clean drinking water procedures should have been used along with the 901.1M (gamma spec) process, for comparison. It is understandable for the new data to be consistent and comparable with the very large existing dataset that a case could be made for using the incorrect protocol and the proper one also. There should have been a detailed discussion of what and why any test method was being used, however. That discussion is usually one of the first topics investigated and explained in the Methods section. Having that type of discussion and justification seems to represent a basic science method and accepted research process – and that omission is a serious flaw.

MOVING FORWARD  We all know that if we want to bake an appetizing and attractive cake we must use the correct measuring cups for the ingredients. If we want to take our child’s temperature we need an accurate thermometer. When our doctor helps us understand our blood test results, we all want to be confident the right test was used at the lab. The proper test instrument, recently calibrated and designed for the specific sample, is crucial to get useable test results from which conclusions can be drawn and policy enacted.

It seems that the best suggestion so far to test high TDS liquids similar to leachate would be to use what is referred to as Gamma-ray Spectrometry with a high purity germanium instrument with at least a 21-day hold period (30 days are better), while the sample is sealed then counted for at least 16 hours. Many of the old leachate test results indicate high uncertainties that might be attributed to short hold times and short counting times. This procedure is referred to as the 901.1 M (modified). If the sample is sealed, the sample will reach about 99% equilibrium after 30 days. Radon 222 (a gas) must not be allowed to escape.

The potential environmental impacts to water quality section of this report seems to demonstrate that if you do not want to find out something, there are always justifiable options to avoid some inconvenient facts. Given the very narrow scope as defined, some the Marshall University folks did not seem to have the option to stray into important scientific foundational assumptions and, for the most part, just had to work with the stale data sets given to them. All of which, as we have known for close to a year now, have used the wrong test protocol. Therefore we have incorrect results of limited value.

II. Marcellus is Radioactive

GOOD 1  Of course, geologists have known that the Marcellus Shale is radioactive for many decades, but also for decades there has been great reluctance by the natural gas exploration and production companies to acknowledge this fact to the public. And finally we now have a public report that clearly and unambiguously states that Marcellus shale is radioactive. Interestingly enough, it was not much more than a year ago that some on the WV House of Delegates Judiciary Committee, seemed to be echoing the industry’s intentional deception by declaring that:

…it was only dirt and rock…

So this report represents progress and provides a very valuable contribution to beginning to recognize some of the potential problems with shale wastes and their disposal challenges.

GOOD 2  Another very important advance is that finally after eight years of drilling here in Wetzel County, we now have a test sample from near the horizontal bore. The WVU WRI study researchers were never given access to any samples taken from the horizontal bore material itself, however. That was, of course, what they were supposed to have been allowed to do, but they were only given access to study material from the vertical section of the well bore. This report describes how we are getting closer to actually testing good samples of the black shale. It seems that we have gotten closer – but let’s see how close.

Page 11 describes that only three Antero wells in Doddridge County were chosen as the place to try to obtain samples from the horizontal bore. Considering that over 1,000 deviated/horizontal wells or wells with laterals have been drilled in the past few years, that number represents a very small fraction of wells drilled: less than .3%. Even if a high quality sample could have been obtained it might be a challenge to extrapolate test results to the waste being produced from the other wells in WV. These limitations are completely ignored in the report, however. Given the available documentation from the DEP, this seems to be a serious flaw that compromises the reliability of the entire report.

III. Samples From Vertical vs. Horizontal Well Bores

FLAW  The actual samples tested from at least two of the three wells used in the study do not seem to be from the horizontal bore material. The sample from the third well might have come from the horizontal bore, but just barely. There is no way to know for sure. I will try to show this within the below chart using information provided by Antero to DEP Office of Oil & Gas. This information is in state records on Antero’s well plats, which become part of the well work application and also part of the final permit.

Table 1. Details about the samples taken from three Antero wells in Doddridge County, WV – and my concerns about the sampling process*

Antero well ID API # Sample’s drilling depth Marcellus depth** Horizontal bore length** Comments / Issues
Morton 1H 47-017-06559 6,856 ft. 7,900 TVD*** 10,600 ft. ~1,044 ft. short of reaching Marcellus formation
McGee 2H 47-017-06622 6,506 ft. 6,900 TVD 8,652 ft. ~394 ft. short of reaching Marcellus
Wentz1 H 47-017-06476 8,119 ft. 7,900 TVD 8,300 ft. Just drilled into Marcellus by 219 ft.
* Original chart found on page 11 of report
** Based on information from Antero’s well plat
*** TVD = Total Vertical Depth

Antero is an active driller in Doddridge County. If any company knows where to find the Marcellus formation it is that company. Well plats are very detailed, technical documents provided to the DEP by the operator regarding the well location, watershed, and leased acres and property boundaries. We need to trust that the information on those plats is accurate and has been reviewed and approved by the permitting agency. Those plats also give the depth of the Marcellus and the length and heading of the lateral or horizontal bore. The Marshall University report gives the drilling depth when the sample was taken on the surface. Using these available well plat records from the DEP it appears that at two of the wells the sample (and its test results included in the report) came from material produced when the experienced drilling operator was not yet into the shale formation.

On the third well, Wentz 1H, the numbers seem to indicate that the sample was taken when the driller said that they were just barely within the shale layer – by 219 feet. Since the drill cuttings take some time to return to the surface from over 7,000 feet down, drilling just a few hundred feet would not at all guarantee that the returned cuttings were totally from the black shale. The processing of the drill cuttings at the shaker table and separator and centrifuge and the mixing in the tubs all cast some doubt on whether the sample, wherever it was taken from, was truly from the horizontal bore material.

On page 11 there is a clear and unambiguous statement:

Three representative sets of drill cuttings from the horizontal drilling activities within the Marcellus Shale formation were collected.

A successful attempt to get three such samples might have then allowed an appropriate waste characterization to be done as needed to accomplish the five required research topics listed in the report’s cover letter. Only an accurate chemical and radiological waste characterization would have allowed scientifically justifiable conclusions to be formulated and then allow for accurate legislation and regulations. It does not seem that West Virginia yet has the required scientific data upon which to confidently formulate laws and regulations to protect public health with regard to shale waste disposal.

Would it not seem prudent – if one wanted a good, representative sample – to make absolutely sure that the operator was, in fact, drilling in the black shale and that the cuttings returning to the surface were, in fact, from the Marcellus bore? That approach would have been eminently defensible and easily accomplished by just waiting for drilling to progress into the lateral bore far enough that the drill cuttings returning to the surface were in fact from the black shale. There might be plausible explanations for this apparent inconsistency or error. Of course, it might be speculated that the Antero-provided information on the well plats is incorrect and not intended to be accurate, or perhaps the driller is not really sure yet where the Marcellus layer starts. There may be many other possible scenarios of explanations. Time will tell.

IV. Research Observations Review

Landfill disposal of drill cuttings

Landfill disposal of drill cuttings

GOOD There are a number of recommendations and suggestions in the study on landfills and leachate related conditions. It seems that a number of these proposals are very accurate and should be implemented. For example:

The report clearly restates that drill cuttings are known to contain radioactive compounds. Since all landfill liners will eventually leak, and since landfills already have ground water test wells for monitoring for potential ground water contamination due to leaking liners, then the well samples should be tested for radiological isotopes. Good idea. They are not required to do that now, but this recommendation should be implemented immediately (pgs. 17 and 21).

GOOD The report recommends that the Publicly Owned Treatment Works (POTW) or in the case of Wetzel County, the on-site wastewater treatment plants, should also test their effluent for radioactive isotopes. This is very important since there is no way to efficiently filter out many of the radioactive isotopes. Such contaminants will pass through traditional wastewater treatment plants.

It is also very useful that the report recommends that all the National Pollution Discharge Elimination System (NPDES) limits at the POTWs be reviewed and required to take into consideration the significantly more challenging chemical and radiological makeup of the shale waste products.

V. Economic Considerations on an Industry Supported Mono-Fill

The legislature asked that the DEP evaluate the feasibility of the natural gas industry to build, own, or operate its own landfill solely for the disposal of the known radioactive waste. This request seems to be a very reasonable approach, since for decades we have only put known radioactive waste products into dedicated landfills that are exclusively and specifically designed for the long term storage of the special waste material.

The discussion of the economic considerations is extremely complete and detailed. They are given in Appendix I and take into consideration a very thorough economic feasibility study of such a proposed endeavor. This section seems to have been compiled by a very talented professional team.

FLAW  However, some of the basic assumptions are a bit askew. For example:

The initial Abstract of the financial analysis states that two new landfills would be needed because we do not want to have the well operators to drive any further than they do now. Interesting. This seems to be not too different than a homeowner while in search for privacy and quiet, builds a home far out into the country and then expects the public sewage lines to be extended miles to his new home so he would not have to incur the cost of a septic system. Homebuilders in rural settings should know they will have to incur expenses for their waste disposal needs. Should gas companies expect that communities to provide cheap waste disposal for them?

More than 15 pages later, the most important aspect is clearly stated that, “…the most salient benefit of establishing a separate landfill sited specifically to receive (radioactive) drill cuttings would be the preservation of existing disposal capacity of existing fills for future waste disposal”. Meaning for my (our) grandchildren. See page 175.

Comprehensive and sound financial details later explain that having the natural gas operators build, operate, and eventually close their own radioactive waste depository landfill would involve a lot of their capital and involve some risk to them. It is stated that their money would be better used drilling more wells. The conclusion then seems to be that, all around, it is simply cheaper and less risky for the gas industry to put all their waste products into our Municipal Waste Landfills, and later residents should incur the costs and risk to build another land fill for their household garbage when needed.

VI. Report Omissions

  1. Within the report section dealing with the leachate test results, it is casually mentioned that not only do the landfills receiving shale waste materials have radioactive contaminated leachate, but the other tested landfills do, as well. However, rather than raising a very red flag and expressing concern over a problem that no one has looked into, the report implies we should not worry about any radioactive waste because it might be in all landfills (pg. 139).
  2. Nowhere within the radiological discussion is there any mention of what might be called speciation of radioactive isotopes. The report does state that the test for both gross alpha and gross beta, are considered a “scanning procedure.” The speciation process is sort of a slice and dice procedure, showing exactly what isotopes are responsible for the activity that is being indicated. This process, however, does not seem to have been done on the landfill leachate test samples. The general scanning process cannot do that. Appendix H, pages 141-142, contains detailed facts on radiation dose, risk, and exposure. This might have been a good place to also discuss the proper EPA testing protocols, used or not used, and why.
  3. A short discussion of the DEP-required landfill entrance radiation monitors is included on page 146. The installed monitors are the goalpost type. Trucks drive between them at the entrance and when they cross the scales. It seems that the report should have emphasized that that type of monitor will primarily only detect high-energy gamma radiation. However what is omitted on page 144 is that the primary form of decay for radium-226 is releasing alpha particles. The report is ambiguous in saying the decay products of radium-226 include both alpha particles and some gamma radiation, but radium-266 is not a strong gamma emitter. It is very unlikely that a normal steel enclosed roll-off box would ever trip the alarm setting with a load of drill cuttings. However those monitors are still useful since they will detect the high-energy gamma radiation from a truck carrying a lot of medical waste (pg. 17).
  4. It is stated on page 144 that the greatest health risk due to the presence of radium-226 is the fact that its daughter product is radon-222. Radium-226 has a half-life of 1,600 years, compared to radon’s 3.8 days. This difference might seem to imply that radon is less of a concern. Given the multitude of radium-226 going into our landfills means that we will be producing radon for a very long time.

VII. Resource Referenced in Article

Examination of Leachate, Drill Cuttings and Related Environmental, Economic and Technical Aspects Associated with Solid Waste Facilities in West Virginia, by Marshall University.

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.

Bird’s eye view of a sand mine in Wisconsin. Photo by Ted Auch 2013.

West Central Wisconsin’s Landscape and What Silica Sand Mining Has Done to It

By Ted Auch, Great Lakes Program Coordinator, and Elliott Kurtz, GIS Intern

The Great Lakes may see a major increase in the number of sand mines developed in the name of fracking. What impacts has the area already seen, and does future development mean for the region’s ecosystem and land use?

Introduction

Sand is a necessary component of today’s oil and gas extraction industry for use in propping open the cracks that fracking creates. Silica sand is a highly sought after proppant for this purpose and often found in Wisconsin and Michigan. At the present time here in Ohio our Utica laterals are averaging 4,300-5,000 tons of silica sand or “proppant” with demand increasing by 85+ tons per lateral per quarter.

Wisconsin’s 125+ silica sand mines and processing facilities are spread out across 15,739 square miles of the state’s West Central region, adjacent to the Minnesota border in the Northern Mississippi Valley. These mines have dramatically altered the landscape while generating proppant for the shale gas industry; approximately 2.5 million tons of sand are extracted per mine. The length of the average shale gas lateral well grows by > 50 feet per quarter, so we expect silica sand usage will grow from 5,500 tons to > 8,000 tons per lateral. To meet this increase in demand, additional mines are being proposed near the Great Lakes.

Migration of the sand industry from the Southwest to the Great Lakes in search of this silica sand has had a large impact on regional ecosystem productivity and watershed resilience[1]. The land in the Great Lakes region is more productive, from a soil and biomass perspective; much of the Southwest sandstone geology is dominated by scrublands that have accrue plant biomass at much slower rates, while the Great Lakes host productive forests and agricultural land. Great Lakes ecosystems produce 1.92 times more soil organic matter and 1.46 times more perennial biomass than Southwestern ecosystems.

Effects on the Great Lakes

Quantifying what the landscape looks like now will serve as a baseline for understanding how the silica sand industry will have altered the overall landscape, much like Appalachia is doing today in the aftermath of strip-mining and Mountaintop Removal Mining[2]. West Central Wisconsin (WCW) has a chance to learn from the admittedly short-cited and myopic mistakes of their brethren across the coalfields of Appalachia.

Herein we aim to present numbers speaking to the diversity and distribution of WCW’s “working landscape” across eight types of land-cover. We will then present numbers speaking to how the silica mining industry has altered the region to date and what these numbers mean for reclamation. The folks at UC Berkeley’s Department of Environmental Science, Policy , and Management describe “Working Landscapes” as follows:

a broad term that expresses the goal of fostering landscapes where production of market goods and ecosystem services is mutually reinforcing. It means working with people as partners to create landscapes and ecosystems that benefit humanity and the planet… A goal is finding management and policy synergies—practices and policies that enhance production of multiple ecosystem services as well as goods for the market…Collaborative management processes can help discover synergies and create better decisions and policy. Incentives can help private landowners support management that benefits society.

Methods

We used the 1993 WISCLAND satellite imagery to determine how WCW’s landscape is partitioned and then we applied these data to an updated inventory of silica sand mine boundaries to determine what existed within their boundaries prior to mining. The point locations of Wisconsin’s current inventory of silica sand mines was determined using the “Geocode Address” function in ArcMap 10.2 using the Composite_US Address Locator. Addresses were drawn from mine inventory information originally maintained by the West Central WI Regional Planning Commission (WCWRPC) and now managed by the WI Department of Natural Resources’ Mines, pits and quarries division. Meanwhile current mine extent boundary polygons were determined using one of three satellite data-sets:

  1. 2013 imagery from the USDA National Agriculture Imagery Program (NAIP),
  2. 2014 ArcMap 10.2 World Imagery, and
  3. 2014 Google Satellite.

What We Found

Land Cover Types Replaced by Silica Sand Mining

Sand-LandEffects

Fig 1. Square mileage of various land cover types replaced by silica sand mining in WCW

Thirty-nine percent of the WCW landscape is currently allocated to forests, 43% to agriculture broadly speaking, and 13% is occupied by various types of wetlands. Open waters occupy 2.6% of the landscape with tertiary uses including barren lands (1.3%), golf courses (0.03%), high and low-density urban areas (0.9%), and miscellaneous shrublands (0.6%) (See Figure 1).

Effects by Land Cover Type

Figure 2. Forest Cover in WCW

Fig 2. Forest Cover in WCW

Figure 3. Agricultural Cover

Fig 3. Agricultural Cover

Figure 4. Open Water & Wetland Cover

Fig 4. Open Water & Wetland Cover

Figure 5. Forested Wetland Cover

Fig 5. Forested Wetland Cover

Figure 6. Lowland Shrub Wetland Cover

Fig 6. Lowland Shrub Wetlands

Figure 7. Miscellaneous Cover

Fig 7. Miscellaneous Cover

Figure 2. The wood in these forests has a current stumpage value of $253-936 million and by way of photosynthesis accumulates 63 to 131 million tons of CO2 and has accumulated 4.8-9.8 billion tons of CO2 if we assumed that on average forests in this region are 65-85 years old. Putting a finer point on WCW forest cover and associated quantifiables is difficult because most of these tracts (2.7 million acres) fall within a catchall category called “Mixed Forest”. Pine (2.3% of the region), Aspen (4.7%), and Oak (3.8%) most of the remaining 1.2 million forested acres with much less sugar (Acer saccharum) and soft (Acer rubrum) maple acreage than we expected scattered in a horseshoe fashion across the Northeastern portion of the study area.

Figure 3. Seven different agricultural land-uses occupy 4.3 million WCW acres with forage crops and grasslands constituting 29% of the region followed by 1.4 million acres of row crops and miscellaneous agricultural activities. Additionally, 2% of WI’s 19,700 cranberry bog acres are within the study area generating $4.02 million worth of cranberries per year. The larger agricultural categories generate $3.2 billion worth of commodities.

Figure 4. Nearly 16% of WCW is characterized by open waters or various types of wetlands with a total area of 2,396 square miles clustered primarily in two Northeast and one Southeast segment. Open waters occupy 398 square miles with forested wetlands – possibly vernal pool-type systems – amounting to 5.4% of the region or 841 square miles. Lowland shrub and emergent/wet meadows occupy 540 and 618 square miles, respectively.

Figure 5. Of the nine types of wetlands present in this region the forested broad-leaved deciduous and emergent/wet meadow variety constitute the largest fraction of the region at 1,107 square miles (7.1% of region). Some percentage of the former would likely be defined by Wisconsin DNR as vernal pools, which do the following according to their Ephemeral Pond program. The WI DNR doesn’t include silica sand mining in its list of 14 threats to vernal pools or potential conservation actions, however.

These ponds are depressions with impeded drainage (usually in forest landscapes), that hold water for a period of time following snowmelt and spring rains but typically dry out by mid-summer…They flourish with productivity during their brief existence and provide critical breeding habitat for certain invertebrates, as well as for many amphibians such as wood frogs and salamanders. They also provide feeding, resting and breeding habitat for songbirds and a source of food for many mammals. Ephemeral ponds contribute in many ways to the biodiversity of a woodlot, forest stand and the larger landscape…they all broadly fit into a community context by the following attributes: their placement in woodlands, isolation, small size, hydrology, length of time they hold water, and composition of the biological community (lacking fish as permanent predators).

Figure 6. Broad-leaved evergreen lowland shrub wetlands constitute ≈2.1% of the region or 319 square miles with most occurring around the Legacy Boggs silica mines and several cranberry operations turned silica mines in Jackson County. Meanwhile broad-leaved deciduous and needle-leaved lowland shrub wetlands are largely outside the current extent of silica sand mining in the region occupying 1.9% of the region with 293 square miles spread out within the northeastern 1/5th of the study area.

Figure 7. Finally, miscellaneous land-covers include 200 square miles of barren land, 145 square miles of low/high intensity urban areas including the cities of Eau Claire (Pop. 67,545) and Stevens Point (Pop. 26,670) as well as towns like Marshfield, Wisconsin Rapids, Merrill, and Rib Mountain-Weston. WCW also hosts 3,204 acres (0.03% of region) worth of golf courses which amounts to roughly 21 courses assuming the average course is 157 acres. Shrublands broadly defined occur throughout 0.6% of the region scattered throughout the southeast corner and north-central sixth of the region, with the both amalgamations poised to experience significant replacement or alteration as they are adjacent to two large silica mine groupings.

Producing Mine Land-Use/Land-Cover Change

To date we have established the current extent of land-use/land-cover change associated with 25 producing silica mines occupying 12 square miles of WCW. These mines have displaced 3 square miles of forests and 7 square miles of agricultural land-cover. These forested tracts accumulated 31,446-64,610 tons of CO2 per year or 2.4-4.9 million tons over the average lifespan of a typical Wisconsin forest. These values equate to the emissions of 144,401-295,956 Wisconsinites or 2.5-5.1% of the state’s population. The annual wood that was once generated on these parcels would have had a market value of $126,097-197,084 per year. Meanwhile the above agricultural lands would be generating roughly $1.5-3.3 million in commodities if they had not been displaced.

However, putting aside measurable market valuations it turns out the most concerning result of this analysis is that these mines have displaces 871 acres of wetlands which equals 11% of all mined lands. This alteration includes 158 acres of formerly forested wetlands, 352 acres of lowland shrub wetlands, and 361 acres of emergent/wet meadows. As we mentioned previously, the chance that these wetlands will be reconstituted to support their original plant and animal assemblages is doubtful.

We know that the St. Peter Sandstone formation is the primary target of the silica sand industry with respect to providing proppant for the shale gas industry. We also know that this formation extend across seven states and approximately 8,884 square miles, with all 91 square miles overlain by wetlands in Wisconsin. To this end carbon-rich grasslands soils or Mollisols, which we discussed earlier, sit atop 36% of the St. Peter Sandstone and given that these soils are alread endangered from past agricultural practices as well as current O&G exploration this is just another example of how soils stand to be dramatically altered by the full extent of the North American Hydrocarbon Industrial Complex. The following IFs would undoubtedly have a dramatic effect on the ability of the ecosystems overlying the St. Peter Sandstone to capture and store CO2 to the extent that they are today not to mention dramatically alter the landscape’s ability to capture, store, and purify precipitation inputs.

  • IF silica sand mining continues at the rate it is on currently
  • IF reclamation continues to result in “very poor stand of grass with some woody plants of very poor quality and little value on the whole for wildlife. Some areas may be reclaimed as crop land, however it is our opinion that substantial inputs such as commercial fertilizer as well as irrigation will be required in most if not all cases in order to produce an average crop.”
  • IF the highly productive temperate forests described above are not reassembled on similar acreage to their extent prior to mining and reclamation is largely to the very poor stands of grass mentione above
    • For example: Great Lakes forests like the ones sitting atop the St. Peter Sandstone capture 20.9 tons of CO2 per acre per year Vs their likely grass/scrublands replacement which capture 10.6-12.8 tons of CO2 per acre per year… You do the math!
  • “None two sites are capable of supporting the growing of food. They grow trees and some cover grass, but that is all. General scientific research says that the reclaimed soils lose up to 75% of their agricultural productivity.”

Quote from a concerned citizen:

I often wonder what it was like before the boom, before fortunes were built on castles of sand and resultant moonscapes stretched as far as the eye could see. In the past few years alone, the nickname the “Silica Sand Capital of the World” has become a curse rather than a blessing for the citizens of LaSalle County, Illinois. Here, the frac sand industry continues to proliferate and threaten thewellbeing of our people and rural ecosystem.

Additional Testimonials

References & Resources

  1. The US Forest Service defined Watershed Resilience as “Over time, all watersheds experience a variety of disturbance events such as fires and floods [and mining]. Resilient watersheds have the ability to recover promptly from such events and even be renewed by them. Much as treating forests can make them more resilient to wildfire, watershed restoration projects can improve watershed resilience to both natural and human disturbances.”
  2. Great example: Virginia Tech’s Powell River Project
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.

Mess is near Stone Lantz pad, WV. - Photo by Bill Hughes

Stream Crossings – Oil and water don’t mix

By Bill Hughes, WV Community Liaison, FracTracker Alliance

West Virginia has generously allowed the shale gas industry to occupy parts of our private land (for profit), namely the Lewis Wetzel Wildlife Management Area (LWWMA). This area is known for 13,500 acres of slopes, trails and forests, providing its inhabitants with great opportunities to hunt, fish, hike and camp.

The state of West Virginia does not own the mineral rights for the LWWMA, and the citizens of West Virginia can only manage so much; therefore, it is the responsibility of the Department of Natural Resources, on behalf of all WV citizens, to care for and manage public lands like LWWMA. With much surprise, the DNR has not only allowed oil and gas occupation of LWWMA, but has not been permitted to impose any regulation, supervision, or any other type of state-initiated enforcements. This approach is primarily due to the lack — or absence of inspectors in the Office of Oil and Gas — division of the Department of Environmental Protection. Often the inspectors that are available are simply playing catch up since the industry and market made some unexpected changes, according to DEP spokeswoman, Kathy Cosco.

Where is the reclamation?

I have been of the impression that once drilling and fracturing is done and the wells are put into production, that some form of reclamation must occur. To my dismay, no part of the drilling industry has taken responsibility for stream crossings, and clearly has no intention in doing so. Everybody has ostensibly packed their bags and gone home, leaving a mess of abandoned stream crossings behind. It is very apparent that no improvements will be done voluntarily by the companies that have created all the well pads in the area. Now the question remains: are we stuck with the stream crossings the way they are now? Or can the state order that these abandoned, inadequate stream crossings be removed?

How Not to Do Stream Crossings

The four photos below depict the deplorable, unacceptable, and disgraceful conditions of the stream crossings left behind by the drilling industry. The DNR and the State of WV have known about these conditions for years, yet have not required that any improvements to be made. Click on each poor stream crossing image to enlarge it:

Near Dry Ridge, API 47-103-02433. All of the water is flowing around the pipes.

Near Dry Ridge, WV. API 47-103-02433

Near Sees Run at Buffalo Run, WV

Near Sees Run at Buffalo Run, WV

Stone Energy well pad on Buffalo Run near Lantz Farm and LWWMA

Stone Energy well pad on Buffalo Run near Lantz Farm & LWWMA

Mess is near Stone Lantz pad, WV

Stream crossing mess near Stone Lantz pad, WV

These examples might be why some folks are more than just a little incredulous when the DNR said that it was going to lease public lands under the river for drillers to take advantage of, promising and assuring that they protect the Ohio River from any drilling-related problems. If the DNR cannot handle the size of the stream water flow, or find a better way to enforce responsible behavior from the drillers, then the Ohio River and the citizens of West Virginia are surely in trouble.

In Need of Higher Standards

The picture below is a depiction of a good stream crossing, installed by someone other than a drilling company. Is there any hope that we will ever expect drillers to do this quality of reclamation to the places we cherish and call home? From an enforcement standpoint, it is clear that these actions will not be voluntary. West Virginia’s DEP has several divisions that focus on land reclamation, environmental remediation and land restoration; however, all of these encourage voluntary action, something we don’t expect to see from drilling companies in the near future.

Buffalo Run crossing going to the William WGGS compressor station. This is what all the permanent stream crossings should look like.

Buffalo Run crossing going to the William WGGS compressor station. This is what all the permanent stream crossings should look like.

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.

The Water-Energy Nexus in Ohio, Part I

OH Utica Production, Water Usage, and Changes in Lateral Length
Part I of a Multi-part Series
By Ted Auch, OH Program Coordinator, FracTracker Alliance

As shale gas expands in Ohio, how too does water use? We conducted an analysis of 500+ Utica wells in an effort to better understand the water-energy nexus in Ohio between production, water usage, and lateral length across 500+ Utica wells. The following is a list of the primary findings from this analysis:

Lateral Length

Modified EIA.gov Schematic Highlighting the Lateral Portion of the Well

Figure 1. Modified EIA schematic highlighting the lateral portion of the unconventional well

In unconventional oil and gas drilling, often operators need to drill both vertically and then laterally to follow the formation underground. This process increases the amount of shale that the well contacts (see the modified EIA schematic in Figure 1). As a general rule Ohio’s Utica wells transition to the horizontal or lateral phase at around 6,800 feet below the earth’s surface.

1. The average Utica lateral is increasing in length by 51-55 feet per quarter, up from an average of 6,369 feet between Q3-2010 and Q2-2011 to 6,872 feet in the last four quarters. Companies’ lateral length growth varies, for example:

    • Gulfport is increasing by 46 feet (+67,206 gallons of water),
    • R.E. Gas Development and Antero 92 feet (+134,412 gallons of water), and
    • Chesapeake 28 feet (+40,908 gallons of water).

2. An increase in lateral length accounts for 40% of the increase in the water usage, as we have discussed in the past.

3. As a general rule, every foot increase in lateral length equates to an increase of 1,461 gallons of freshwater.

Regional and County-Level Trends

This section looks into big picture of shale gas drilling in OH. Herein we summarize the current state of water usage by the Utica shale industry relative to hydrocarbon production, as a percentage of residential water usage, as well as long-term water usage and waste production forecasts.

1. Freshwater Use

    • Across 516 wells, we found that the average OH Utica well utilizes 5.04-5.69 million gallons of freshwater per well.
    • This figure includes a ratio of 12:1 freshwater to recycled water used on site.
    • Water usage is increasing by 221-330,000 gallons per well per quarter.
      • Note: In neighboring – and highly OH freshwater reliant-West Virginia, the average Marcellus well uses 6.1-6.6 million gallons per well, with a trend increase of 189-353,000 gallons per quarter per well.
      • Water usage is up from 4.88 million gallons per well between 2010 and the summer of 2011 to 7.27 million gallons today.
    • Over the next five years, we will likely see 18.5 billion gallons of freshwater used for shale gas drilling in OH.
    • On average, drilling companies use 588 gallons of water to get a gallon of oil.
      • Average: 338 gallons of water required to get 1 MCF of gas
      • Average: 0.078 gallons of brine produced per gallon of water

2. Residential Water Allocation

    • A portion of residential water (3.8-6.1% of usage) is being allocated to the Utica drilling boom.
      • This figure is as high as 81% of residential water requirements in Carroll County.
      • And amounts to 2.2-3.5% of the available water in the Muskingum River Watershed.
    • The allocation will increase over time to amount to 8.2-10.5% of residential usage or 4.4-5.6% of Muskingum River available water.

3. Permitted Wells Potential

    • If all permitted Utica wells were to come online (active), we could expect 299.7 million gallons of additional brine to be produced and an additional 220 million gallons of freshwater a year to be used.
    • This trend amounts to 1.1 billion gallons of fracking brine waste looking for a home within 5 years.

4. Waste Disposal

    • Stallion Oilfield Services has recently purchased several Class II Injection wells in Portage County.
    • These waste disposal sites are increasing their intake at a rate of 2.13 million gallons per quarter, 4.76 times that of the rest of OH Class II wells.

Water Usage By Company

The data trends we have reviewed vary significantly depending on the company that is assessed. Below we summarize the current state of water usage by the major players in Ohio’s Utica shale industry relative to hydrocarbon production. 

1. Overall Statistics

    • The 15 biggest Water-To-Oil offenders are currently averaging 16,844 Gallons of Water per gallon of oil (PGO) (i.e., Shugert 2-12H, Salem-Grubbs 1H, Stutzman 1 and 3-14H, etc).
    • Removing the above 15 brings the Water-To-Oil ratio down from 588 to 52 gallons of water PGO.
    • The 9 biggest Water-To-Gas offenders are currently averaging 16,699 gallons of water per MCF of gas.
    • Removing the above 9 brings the Water-To-Gas ratio down from 338 to 27 gallons of water per MCF of gas.

Company differences are noticeable (Figure 2):

Water Usage by Hydraulic Fracturing Industry in Ohio

Figure 2. Average Freshwater Use Among OH Utica Operators

    • Antero and Anadarko used an average of 9.5 and 8.8 MGs of water per well during the course of the 45-60 drilling process, respectively (Note: HG Energy has the wells with the highest water usage but a limited sample size, with 9.8 MGs per well).
    • Six companies average in the middle with 6.7-8.1 MGs of water per well.
    • Four companies average 5 MGs per well, including Chesapeake the biggest player here in OH.
    • Devon Energy is the one firm using less than 3 MGs of freshwater for each well it drills.

2. Water-to-Oil Ratios

Water-Energy Nexus in Ohio: Water-to-Oil Ratios Among OH Utica Operators

Figure 3. Water-to-Oil Ratios Among OH Utica Operators

Freshwater usage is increasing by 3.6 gallons per gallon of oil. Companies vary less in this metric, except for Gulfport (Figure 3):

    • Gulfport is by far the least efficient user of freshwater with respect to oil production, averaging 3,339 gallons of water to extract one gallon of oil.
    • Intermediate firms include American Energy and Hess, which required 661 and 842 gallons of freshwater to produce a gallon of oil.
    • The remaining eleven firms used anywhere from 6 (Atlas Noble) to 130 (Chesapeake) gallons of freshwater to get a unit of oil.

3. Water-to-Gas Ratios (Figure 4)

Water-Energy Nexus in Ohio: Water-to-Gas Ratio Among OH Utica Operators

Figure 4. Water-to-Gas Ratio Among OH Utica Operators

    • American Energy is also quite inefficient when it comes to natural gas production utilizing >2,200 gallons of freshwater per MCF of natural gas produced
    • Chesapeake and CNX rank a distant second, requiring 437 and 582 gallons of freshwater per MCF of natural gas, respectively.
    • The remaining firms for which we have data are using anywhere from 13 (RE Gas) to 81 (Gulfport) gallons of freshwater per MCF of natural gas.

4. Brine Production (Figure 5)

Water-Energy Nexus in Ohio: Brine-to-Oil Ratios among Ohio Utica Operators

Figure 5. Brine-to-Oil Ratios among Ohio Utica Operators

    • With respect to the relationship between hydrocarbon and waste generation, we see that no firm can match Oklahoma City-based Gulfport’s inefficiencies with an average of 2,400+ gallons of brine produced per gallon of oil.
    • American Energy and Hess are not as wasteful, but they are the only other firms generating more than 750 gallons brine waste per unit of oil.
    • Houston-based Halcon and OH’s primary Utica player Chesapeake Energy are generating slightly more than 400 gallons of brine per gallon of oil.
    • The remaining firms are generating between 17 (Atlas Noble and RE Gas) and 160 (Anadarko) gallons of brine per unit of oil.

Part II of the Series

In the next part of this series we will look into inter-county differences as they relate to water use, production, and lateral length. Additionally, we will also examine how the OH DNR’s initial Utica projections differ dramatically from the current state of affairs.

Water and Production in Ohio's Utica Shale - Water Per Well

Water and Production in Ohio’s Utica Shale – Water Per Well

 

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