The majority of FracTracker’s posts are generally considered articles. These may include analysis around data, embedded maps, summaries of partner collaborations, highlights of a publication or project, guest posts, etc.

An urgent need? Atlantic Coast Pipeline Discussion and Map

July 10, 2015/by Karen Edelstein

By Karen Edelstein, Eastern Program Coordinator

This article was originally posted on 10 July 2015, and then updated on 22 January 2016 and 16 February 2016.

Proposed Pipeline to Funnel Marcellus Gas South

In early fall 2014, Dominion Energy proposed a $5 billion pipeline project, designed provide “clean-burning gas supplies to growing markets in Virginia and North Carolina.” Originally named the “Southeast Reliability Project,” the proposed pipeline would have a 42-inch diameter in West Virginia and Virginia. It would narrow to 36 inches in North Carolina, and narrow again to 20 inches in the portion that would extend to the coast at Hampton Roads. Moving 1.5 billion cubic feet per day of gas, with a maximum allowable operating pressure of 1440 psig (pounds per square inch gage), the pipeline would be designed for larger customers (such as manufacturers and power generators) or local gas distributors supplying homes and businesses to tap into the pipeline along the route, making the pipeline a prime mover for development along its path.

The project was renamed the Atlantic Coast Pipeline (ACP) when a coalition of four major US energy companies—Dominion (45% ownership), Duke Energy (40%), Piedmont Natural Gas (15%), and AGL Resources (5%)— proposed a joint venture in building and co-owning the pipeline. Since then, over 100 energy companies, economic developers, labor unions, manufacturers, and civic groups have joined the new Energy Sure Coalition, supporting the ACP. The coalition asserts that the pipeline is essential because the demand for fuel for power generation is predicted more than triple over the next 20 years. Their website touts the pipeline as a “Path to Cleaner Energy,” and suggests that the project will generate significant tax revenue for Virginia, North Carolina, and West Virginia.

Map of Proposed Atlantic Coast Pipeline

View map fullscreen – including legend and measurement tools.

Development Background

Lew Ebert, president of the North Carolina Chamber of Commerce, optimistically commented:

Having the ability to bring low-cost, affordable, predictable energy to a part of the state that’s desperately in need of it is a big deal. The opportunity to bring a new kind of energy to a part of the state that has really struggled over decades is a real economic plus.

Unlike older pipelines, which were designed to move oil and gas from the Gulf Coast refineries northward to meet energy demands there, the Atlantic Coast Pipeline would tap the Marcellus Shale Formation in Ohio, West Virginia and Pennsylvania and send it south to fuel power generation stations and residential customers. Dominion characterizes the need for natural gas in these parts of the country as “urgent,” and that there is no better supplier than these “four homegrown companies” that have been economic forces in the state for many years.

In addition to the 550 miles of proposed pipeline for this project, three compressor stations are also planned. One would be at the beginning of the pipeline in West Virginia, a second midway in County Virginia, and the third near the Virginia-North Carolina state line. The compressor stations are located along the proposed pipeline, adjacent to the Transcontinental Pipeline, which stretches more than 1,800 miles from Pennsylvania and the New York City Area to locations along the Gulf of Mexico, as far south as Brownsville, TX.

In mid-May 2015, in order to avoid requesting Congressional approval to locate the pipeline over National Park Service lands, Dominion proposed rerouting two sections of the pipeline, combining the impact zones on both the Blue Ridge Parkway and the Appalachian Trail into a single location along the border of Nelson and Augusta Counties, VA. National Forest Service land does not require as strict of approvals as would construction on National Park Service lands. Dominion noted that over 80% of the pipeline route has already been surveyed.

Opposition to the Pipeline on Many Fronts

The path of the proposed pipeline crosses topography that is well known for its karst geology feature—underground caverns that are continuous with groundwater supplies. Environmentalists have been vocal in their concern that were part of the pipeline to rupture, groundwater contamination, along with impacts to wildlife could be extensive. In Nelson County, VA, alone, 70% of the property owners in the path of the proposed pipeline have refused Dominion access for survey, asserting that Dominion has been unresponsive to their concerns about environmental and cultural impacts of the project.

On the grassroots front, 38 conservation and environmental groups in Virginia and West Virginia have combined efforts to oppose the ACP. The group, called the Allegany-Blue Ridge Alliance (ABRA), cites among its primary concerns the ecologically-sensitive habitats the proposed pipeline would cross, including over 49.5 miles of the George Washington and Monongahela State Forests in Virginia and West Virginia. The “alternative” version of the pipeline route would traverse 62.7 miles of the same State Forests. Scenic routes, including the Blue Ridge Parkway and the Appalachian Scenic Trail would also be impacted. In addition, it would pose negative impacts on many rural communities but not offset these impacts with any longer-term economic benefits. ABRA is urging for a programmatic environmental impact statement (PEIS) to assess the full impact of the pipeline, and also evaluate “all reasonable, less damaging” alternatives. Importantly, ABRA is urging for a review that explores the cumulative impacts off all pipeline infrastructure projects in the area, especially in light of the increasing availability of clean energy alternatives.

Environmental and political opposition to the pipeline has been strong, especially in western Virginia. Friends of Nelson, based in Nelson County, VA, has taken issue with the impacts posed by the 150-foot-wide easement necessary for the pipeline, as well as the shortage of Department of Environmental Quality staff that would be necessary to oversee a project of this magnitude.

Do gas reserves justify this project?

Dominion, an informational flyer, put forward an interesting argument about why gas pipelines are a more environmentally desirable alternative to green energy:

If all of the natural gas that would flow through the Atlantic Coast Pipeline is used to generate electricity, the 1.5 billion cubic feet per day (bcf/d) would yield approximately 190,500 megawatt-hours per day (mwh/d) of electricity. The pipeline, once operational, would affect approximately 4,600 acres of land. To generate that much electricity with wind turbines, utilities would need approximately 46,500 wind turbines on approximately 476,000 acres of land. To generate that much electricity with solar farms, utilities would need approximately 1.7 million acres of land dedicated to solar power generation.

Nonetheless, researchers, as well as environmental groups, have questioned whether the logic is sound, given production in both the Marcellus and Utica Formations is dropping off in recent assessments.

Both Nature, in their article Natural Gas: The Fracking Fallacy, and Post Carbon Institute, in their paper Drilling Deeper, took a critical look at several of the current production scenarios for the Marcellus Shale offered by EIA and University of Texas Bureau of Economic Geology (UT/BEG). All estimates show a decline in production over current levels. The University of Texas report, authored by petroleum geologists, is considerably less optimistic than what has been suggested by the Energy Information Administration (EIA), and imply that the oil and gas bubble is likely to soon burst.

Natural Gas Production Projections for Marcellus Shale

David Hughes, author of the Drilling Deeper report, summarized some of his findings on Marcellus productivity:

Field decline averages 32% per year without drilling, requiring about 1,000 wells per year in Pennsylvania and West Virginia to offset.
Core counties occupy a relatively small proportion of the total play area and are the current focus of drilling.
Average well productivity in most counties is increasing as operators apply better technology and focus drilling on sweet spots.
Production in the “most likely” drilling rate case is likely to peak by 2018 at 25% above the levels in mid-2014 and will cumulatively produce the quantity that the Energy Information Administration (EIA) projected through 2040. However, production levels will be higher in early years and lower in later years than the EIA projected, which is critical information for ongoing infrastructure development plans.
The EIA overestimates Marcellus production by between 6% and 18%, for its Natural Gas Weekly and Drilling Productivity reports, respectively.
Five out of more than 70 counties account for two-thirds of production. Eighty-five percent of production is from Pennsylvania, 15% from West Virginia and very small amounts from Ohio and New York. (The EIA has published maps of the depth, thickness and distribution of the Marcellus shale, which are helpful in understanding the variability of the play.)
The increase in well productivity over time reported in Drilling Deeper has now peaked in several of the top counties and is declining. This means that better technology is no longer increasing average well productivity in these counties, a result of either drilling in poorer locations and/or well interference resulting in one well cannibalizing another well’s recoverable gas. This declining well productivity is significant, yet expected, as top counties become saturated with wells and will degrade the economics which have allowed operators to sell into Appalachian gas hubs at a significant discount to Henry hub gas prices.
The backlog of wells awaiting completion (aka “fracklog”) was reduced from nearly a thousand wells in early 2012 to very few in mid-2013, but has increased to more than 500 in late 2014. This means there is a cushion of wells waiting on completion which can maintain or increase overall play production as they are connected, even if the rig count drops further.
Current drilling rates are sufficient to keep Marcellus production growing on track for its projected 2018 peak (“most likely” case in Drilling Deeper).

Post Carbon Institute estimates that Marcellus predictions overstate actual production by 45-142%. Regardless of the model we consider, production starts to drop off within a year or two after the proposed Atlantic Coast Pipeline would go into operation. This downward trend leads to some serious questions about whether moving ahead with the assumption of three-fold demand for gas along the Carolina coast should prompt some larger planning questions, and whether the availability of recoverable Marcellus gas over the next twenty years, as well as the environmental impacts of the Atlantic Coast Pipeline, justify its construction.

Next steps

The Federal Energy Regulatory Commission, FERC, will make a final approval on the pipeline route later in the summer of 2015, with a final decision on the pipeline construction itself expected by fall 2016.

UPDATE #1: On January 19, 2016, the Richmond Times-Dispatch reported that the United States Forest Service had rejected the pipeline, due to the impact its route would have on habitats of sensitive animal species living in the two National Forests it is proposed to traverse.

UPDATE #2: On February 12, 2016, Dominion Pipeline Company released a new map showing an alternative route to the one recently rejected by the United States Forest Service a month earlier. Stridently condemned by the Dominion Pipeline Monitoring Coalition as an “irresponsible undertaking”, the new route would not only cross terrain the Dominion had previously rejected as too hazardous for pipeline construction, it would–in avoiding a path through Cheat and Shenandoah Mountains–impact terrain known for its ecologically sensitive karst topography, and pose grave risks to water quality and soil erosion.

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

July 9, 2015/by Ted Auch, PhD

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. 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

Figure 1. Ohio Class II Injection Well trends In- and Out-Of-State, Cumulatively, and on Per Well basis (n = 248).

For every gallon of freshwater used in the fracking process here in Ohio the industry is generating .03 gallons of brine (On average, Ohio’s 758 Utica wells use 6.88 million gallons of freshwater and produce 225,883 gallons of brine per well).

Back in August of 2013 the rate at which brine volumes were increasing was approaching 150,000 BPQPW (Learn more, Fig 5), however, that number has nearly doubled to +279,586 BPQPW (Note: 1 barrel of brine equals 32-42 gallons). Furthermore, Ohio’s Class II Injection wells are averaging 37,301 BPQPW (1.6 MGs) per quarter over the last year vs. 12,926 barrels BPQPW – all of this between the initiation of frack waste injection in 2010 and our last analysis up to and including Q2-2013. Finally, between Q3-2010 and Q1-2015 the exponential increase in injection activity has resulted in a total of 81.7 million barrels (2.6-3.4 billion gallons) of waste disposed of here in Ohio. From a dollars and cents perspective this waste has generated $2.5 million in revenue for the state or 00.01% of the average state budget (Note: 2.5% of ODNR’s annual budget).

Freshwater Demand Growing

Figure 2. Ohio Class II Injection Well disposal as a function of freshwater demand by the shale industry in Ohio between Q3-2010 and Q1-2015.

The relationship between brine (waste) produced and freshwater needed by the hydraulic fracturing industry is an interesting one; average freshwater demand during the fracking process accounts for 87% of the trend in brine disposal here in Ohio (Fig. 2). The more water used, the more waste produced. Additionally, the demand for OH freshwater is growing to the tune of 405-410,000 gallons PQPW, which means brine production is growing by roughly 12,000 gallons PQPW. This says nothing for the 450,000 gallons of freshwater PQPW increase in West Virginia and their likely demand for injection sites that can accommodate their 13,500 gallons PQPW increase.

Where will all this waste go? I’ll give you two guesses, and the first one doesn’t count given that in the last month the ODNR has issued 7 new injection well permits with 9 pending according to the Center For Health and Environmental Justice’s Teresa Mills.

Unconventional Drilling Activity Down In Pennsylvania

July 8, 2015/by Matt Kelso, BA

By Matt Kelso, Manager of Data & Technology

Wells Spudded (Drilled)

The number of newly drilled unconventional wells in Pennsylvania peaked in 2011.

Figure 1: Newly drilled unconventional wells in Pennsylvania peaked in 2011.

Unconventional oil and gas drilling is well established in Pennsylvania, with over 9,200 drilled wells, an additional 7,200 permitted locations that have not yet been drilled, and 5,300 violations all happening since the turn of the millennium. It took a while for the industry to gather steam, with just one unconventional well drilled in 2002, and only eight in 2005. But by 2010, that figure had ballooned to 1,599 wells, which was greater than the previous eight years combined. There were 1,956 wells drilled in 2011, representing the peak for unconventional drilling activity in Pennsylvania (Figure 1).

None of the three full years since then, however, have seen more than 70% of the 2011 total. Halfway through 2015, the industry is on pace to drill only 842 unconventional wells statewide, which would be the lowest total since 2009, and only 43% of the 2011 total.

Pennsylvania Shale Viewer. Click here to access the full screen view with a legend, layer details, and other tools.

Taken cumulatively, the footprint on the state is immense, as is shown in the map above, and impacts remain for some time. Of Pennsylvania’s 9,234 unconventional wells 8,187 (89%) are still active. Only 474 wells have been permanently plugged so far, with 570 given an inactive status, and one well listed as “proposed but never materialized,” despite being included on the spud report.

Permits & Violations

The number of permits and violations issued have been declining over the past five years as well.

Figure 2: Five years of unconventional oil and gas activity in Pennsylvania, July 2010 through June 2015.

Figure 2 shows the monthly totals of permits, wells, and violations over the last 60 months. Linear trendlines were added to the chart to give a visual representation of changes over time if we ignore the noise of the peaks and troughs of activity, which is an inherent attribute of the industry. Each of the three trendlines has a negative slope¹, showing downward trends in each category.

In fact, permits for new wells are declining more rapidly than the drilled wells, and violations issued are declining at a still faster rate. Over the course of five years, these declines are substantial. In July 2010, the smoothed totals that are “predicted” by the trendline show 304 permits issued, 159 wells drilled, and 128 violations issued per month. 60 months later, one would expect 213 permits, 81 wells drilled, and just 12 violations issued².

Location of Drilling Activity

The oil and gas industry has been more selective about where unconventional wells are being drilled in recent years, as well. Altogether, there are unconventional wells in 39 different counties, with 32 counties seeing action in both 2010 and 2011. That number is down to 22 for both 2014 and the first half of 2015. There has been drilling in 443 different municipalities since 2002, with a maximum of 241 municipal regions in 2011, which shrank to 161 last year, and just 88 in the first half of 2015.

Summary of unconventional wells drilled in each Pennsylvania county by year, through June 30, 2015. Click here to access the full screen view with a legend, layer details, and other tools

Clicking on any of the counties above will show the number of unconventional wells drilled in that county by year since the first unconventional well was spudded in Pennsylvania back in 2002. The color scheme shows the year that the maximum number of unconventional wells were drilled in each county, with blues, greens, and yellows showing counties where the activity has already peaked, oranges showing a peak in 2014, and red showing a peak in 2015, despite only six months of activity. 30 of the 39 counties with unconventional wells in the state saw a peak in activity in 2013 or before.

Notes

The equations for the three trendlines are as follows:
- Permits: y = -1.5128x + 303.81
- Wells: y = -1.2939x + 158.95
- Violations: y = -1.9334x + 127.53
The lowest actual value for each category are as follows:
- Permits: 117, in July 2012
- Wells: 43, in February 2015
- Violations: 16, in August 2014.

Explore a Fracking Operation – Virtually

June 30, 2015/by FracTracker Alliance

Offshore Oil and Gas Drilling: Risks to the Sea Otter

June 30, 2015/by FracTracker Alliance

By Emily Watson, FracTracker Summer Intern

Sea otters, an endangered keystone species, are at risk due to offshore oil and gas drilling spills. Along the west coast of the U.S., this marine mammal’s habitat is commonly near offshore drilling sites, specifically in California and Alaska.

Sea Otters – a Keystone Species

Sea otter numbers used to range from several hundred thousand to more than a million. Today, there are estimated to be just over 106,000 in existence worldwide, with fewer than 3,000 living in California. Their habitats range from Canada, Russia, Japan, California and Washington, but the majority of all wild sea otters are found in Alaskan waters.

Sea otters play a significant role in their local environments, and a much greater ecosystem role than any other species in their habitat area. Sea otters are predators, critical to maintaining the balance of the near-shore kelp ecosystems, and are referred to as keystone species. Without this balancing act, coastal kelp forests in California would be devoured by other aquatic life. Sea otter predation helps to ensure that the kelp community continues to provide cover and food for many of the marine animals. Additionally, kelp plays a tremendous role in capturing carbon in the coastal ecosystems. In that sense, sea otters also inadvertently help to reduce levels of atmospheric carbon dioxide.

Oil Spills and their Health Implications

Recently, Alaska and California, home to a wide variety of marine life, have been popular areas for offshore oil and gas drilling, which may include the use of fracking to extract hydrocarbons. Oil spills are a great concern for the sea otter; unlike other marine animals that may be able to eventually rid themselves of the oil, contact with the oil causes the sea otters fur to mat, preventing insulation, which can lead to hypothermia. Additionally, the ingestion of toxic oil chemicals while cleansing their fur can cause liver and kidney failure, as well as severe damage to their lungs and eyes.

Because their numbers are low and their geographic location area is rather small compared to other sea otter populations, the California sea otter is especially vulnerable, and could be devastated by oil contamination.

Prince William Sound, Alaska

Exxon Valdez cleanup. Photograph by Natalie Fobes, National Geographic

On March 24, 1989, the tanker vessel Exxon Valdez ran aground on Bligh Reef in Prince William Sound, Alaska, spilling an estimated 42 million liters of Prudhoe Bay crude oil. This incident affected marine life throughout western Prince William Sound, the Gulf of Alaska, and lower Cook Inlet. An estimated 3500–5500 otters from a total population of about 30,000 may have died as a direct result of the oil spill. Oiling and ingestion of oil-contaminated shellfish may have affected reproduction and caused a variety of long-term sublethal effects. Necropsies of sea otter carcasses indicated that most deaths of sea otters were attributed to the oil, and pathologic and histologic changes were associated with oil exposure in the lung, liver, and kidney. Studies of long-term effects indicate that the sea otter population in the Prince William Sound area suffered from chronic effects of oil exposure at least through 1991. While some populations may recover after a spill, it would seem that the threat of oil pollution impacts is intensified for populations in deteriorating habitats and to those that are in decline.

Santa Barbara Coast, California

LA Santa Barbara Oil Spill Cleanup – Photo by: Brian van der Brug / Los Angeles Times

On Tuesday, May 19, 2015, a pipeline was found to be leaking into the Santa Barbara Coast in California. This broken pipeline, owned by Plains All American, spilled approximately 105,000 gallons of crude oil into the ocean, according to various news reports, stretching out into a 4-mile radius along the central California coastline.

These waters are home to an array of shore birds, seals, sea lions, otters and whales. Numerous amounts of marine life have been found washed up on the shore, including crabs, octopuses, fish, birds, and dolphins. Elephant seals, sea lions, and other marine wildlife have been taken to Seaworld in San Diego for treatment and recovery.

The Santa Barbara accident occurred on the same stretch of coastline as spill in 1969 that – at the time – was the largest ever incident in U.S. waters and contributed to the rise of the American environmental movement. Several hundred-thousand gallons spilled from a blowout on an oil platform, and thousands of seabirds were killed and numerous ocean wildlife, including sea lions, elephant seals, and fish perished.

Conclusion

Overall, the ocean is home to a great diversity of marine wildlife, all of which are vulnerable to oil contamination. Offshore gas drilling is a significant threat to the survival of sea otters and other marine life, wherein spills and accidents could cause health problems, toxicity, and even death. Oil spills are exceptionally problematic for sea otters, due to the vulnerable state of this animal and its endangered species state. Keeping keystone species healthy is instrumental to maintaining a well flourished ecosystem, while protecting habitats for a large array of marine and wildlife. The potential impacts on CA sea otters and other marine life due to events such as the 2015 oil spill in California should not be taken lightly.

Ohio’s Shale Oil and Gas Firms Disappoint Shareholders

June 24, 2015/by Ted Auch, PhD

By Ted Auch, Great Lakes Program Coordinator

A financial crisis seems to have been averted as the price of crude oil is beginning to stabilize – at least for now. One must wonder how such a volatile market affects oil and gas’ Wall Street, private equity, and pension fund followers, however. We have found that many oil and gas (O&G) shares have experienced steep valuation declines in the last few years for companies operating in Ohio.

Share[d] Values

To approach such a broad question, we focused our assessment on Ohio and looked at the share performance of the 17 publicly traded firms operating in the Ohio Utica region since the date of their respective first Utica permits. The Date of First Permit (DFP) ranges between 12/23/2010 for Chesapeake Energy to 3/20/2013 for BP.

Across these 17 companies there are, quite expectedly, winners and losers. On average their shares have experienced 3.75% declines in their valuation or -00.81% per year in the last several years, however. This might be why many of Wall Street and The City’s major banks have limited – or ended – their lines of credit with energy firms from Ohio to the Great Plains. Others are still picking off the highly leveraged losers one by one for pennies on the dollar (Corkery and Eavis, 2015; Staff, 2014). This cutoff of credit and disturbingly high levels of debt/leverage may explain why we found, in a separate analysis, that while cumulative producing oil and gas wells have increased by 349% and 171%, respectively, the rate of permitting needed to maintain and/or incrementally increase these production rates has been 589%.

Cross-Company Comparisons

Ohio Utica Shale Publicly Traded Companies Return

Figure 2. Annual change in share price (%) for 17 publicly traded firms operating in the Ohio Utica shale since their date of first permit

The biggest losers in Ohio’s oil and gas world include Chesapeake Energy. Chesapeake (CHK) is also the largest player in the Buckeye State based on total permits and total producing laterals, accounting for 41% and 55%, respectively. CHK has seen its shares decline on average by 9.1% each year since their DFP (Figure 2). Antero (-10.7% per year), Consol Energy (-7.8%), and Enervest (-12.1%) have experienced similar annual declines, with investors in these firms having seen their position shrink by an average of 37%. Eclipse shares have declined in value by nearly 20% per year, which pales in comparison to the 30-33% annual declines in the share price of Halcon, Atlas Noble, and XTO Energy.

Conversely, the biggest winners are clearly Carrizo (+49% per year), PDC Energy (+41%), and to a lesser degree smaller players like EQT (+22%), Hess Ohio (+8.4%), and Anadarko (+7.9%). Interestingly, the second most active firm operating in Ohio is Gulfport Energy, and their performance has been somewhere in the middle – with annual returns of 10.3%.

Out of State – The Bigger Picture

But before the big winners light up celebratory cigars, it is worth putting their performance into perspective relative to the rest of the field as it were. In an effort to be as fair as possible we chose the Dow Jones Industrial Average and S&P 500 – two indices that everyone has heard of because they are viewed as broad indicators of US economic growth. Incidentally, the DJIA includes the O&G companies Exon and Chevron. Exon is a multinational firm not involved in Ohio’s Utica development, while Chevron is involved. Additionally, the S&P 500 includes those two firms, as well as 39 other energy firms. Nine of those currently operate in Ohio. To assess these companies’ performance with the most energy-centric indices we have compared Ohio Utica players to the S&P 500’s Energy Index, which strips away all other components of its more famous metric, as well as the Vanguard Energy Index Fund. The latter is described by Vanguard as the following on the Mutual Funds portion of its website:

This low-cost index fund offers exposure to the energy sector of the U.S. equity market, which includes stocks of companies involved in the exploration and production of energy products such as oil, and natural gas. The fund’s main risk is its narrow scope—it invests solely in energy stocks. An investor should expect high volatility from the fund, which should be considered only as a small portion of an already well-diversified portfolio.

In reviewing these four indices we found that they have outperformed the 17 oil and gas firms here in Ohio or the Ohio Energy Complex (OEC), with annual rates of return (ROR) exceeding 35% (Figure 3). This ROR value was not approached or exceeded by any of the 17 OEC firms except for PDC Energy and Carrizo. However, these two companies only account for 2.8% of all Utica permits and 4.4% of all producing Utica laterals to date. Even if we remove the broader indicators of economic growth and just focus on the two energy indices we see the US energy space ROR has experienced annual growth rates of 33% or 7% below the broader US economy but impressive nonetheless. With such growth in the number of companies drilling for oil and gas, it is likely that we will see significant consolidation soon; some of the world’s largest multinationals like Exxon and Total may step in when all of the above are priced to perfection, which is something Exxon’s Chariman and CEO, Rex Tillerson, eluded to in a speech in Cleveland last June.

US Economic Performance and Energ Industry Metrics

Figure 3. Annual % Return of Two Broad Economic and Two Energy Specific Indices.

The performance of the OEC indicates investors and/or lenders will not tolerate such a performance for much longer. Just like our country’s Too-Big-To-Fail banks, boards, CEOs, and shareholders were bailed out, it seems as though a similar bubble is percolating in the O&G world; the same untouchables will be protected by way of explicit or implicit taxpayer bailouts. Will Ohioans be made whole, too, or will they be left to pick up the pieces after yet another natural resource bubble bursts?

References

Corkery, M., Eavis, P., 2015. Slump in Oil Prices Brings Pressure, and Investment Opportunity, The New York Times, New York, NY.

Staff, 2014. Shale oil in a Bind: Will falling oil prices curb America’s shale boom?, The Economist, London, UK.

Utica Drilling in Pennsylvania

June 23, 2015/by Matt Kelso, BA

In Pennsylvania, the vast majority of unconventional oil and gas activity is focused on the Marcellus Shale formation, a Devonian period deposit of black shale with a high hydrocarbon content, which requires horizontal drilling and large scale hydraulic fracturing to produce enough oil and gas to make the drilling economically viable. This formation was created about 390 million years ago, when organic-rich deposits accumulated in what is now the Appalachian Mountains, but was at that time a shallow sea. Down below the base of the Marcellus lies the Utica Shale, an Ordovician period formation, with almost the same geographic extent as the Marcellus, but the deposits were placed there about 65 million years earlier.

Utica permits and violations in Pennsylvania. Click here to access the legend and other map tools.

In neighboring Ohio, it is the Utica that gets most of the attention, with 937 permitted wells, as opposed to just 20 for the Marcellus. In Pennsylvania, the reverse is true: there are 16,110 permitted Marcellus wells, but only 279 permits for Utica wells. Part of the reason for this is because the subsurface characteristics of these formations vary widely, especially in terms of thickness and depth. With changes in depth come changes in temperature and pressure, which are key criteria in hydrocarbon formation. In other words, the same formation that produces considerable quantities of gas and valuable liquid hydrocarbons in eastern Ohio may be economically unviable just a county or two over in western Pennsylvania.

Utica shale permits, drilled wells, violations, and violations per well for Pennsylvania, through June 19, 2015.

Utica drilling permits have been issued in 19 different counties in Pennsylvania, with wells having been drilled in 15 of those. The violations per well (VpW) score for Utica wells in the Keystone State is 0.9, meaning that there are nine violations issued for every 10 wells that have been drilled. It is worth noting, however, that only 36 of the 114 drilled wells have received violations, meaning that some wells have been cited on multiple occasions.

Of particular note is Bradford county, the site of only one Utica well, but 19 items on the compliance report. The problematic Bayles 1 well was run by three different operators before being permanently plugged. This well also has two “Drill Deeper” permits, and as a result, it is likely that the first six violations assessed to this well were issued before it was associated with the Utica Shale, as they precede the most recent spud date for the well in June, 2005. Most of the violations for this well seem to be for pit violations and discharges to the ground and nearby stream.

Wells drilled into the Utica Formation in Pennsylvania, by year and current status.

In terms of drilling activity, it appears to have peaked in 2012, calling into question whether the industry considers the formation to be economically viable in Pennsylvania. Of the 28 wells drilled since the beginning of 2014, Tioga County has seen the most activity with 11 wells drilled, followed by five wells in Butler County, then three in Lawrence County. If we think of drilling activity as a sort of positive feedback from the industry – meaning that they like what they see and want to keep exploring – then only Tioga County seems to be holding the attention of the various operators who have been active in the Utica Shale. Given the Utica activity in Ohio, one might have thought that counties on the western edge of the state – especially Beaver, Lawrence, and Mercer – would have shown the most promise, but this appears not to be the case.

Has radioactivity risk from oil and gas activity been underrated?

June 16, 2015/by FracTracker Alliance

Reviewing a Pennsylvania TENORM Study

By Juliana Henao, Communications Intern

Technologically-enhanced, naturally-occurring radioactive materials, also known as TENORM, are produced when radionuclides deep in the earth are brought to the surface by human activity such as oil and gas drilling. The radioactive materials, which include uranium (U), thorium (th), potassium-40 (K-40) and their decay products, occur naturally in the environment. These materials are known to dissolve in produced water, or brine, from the hydraulic fracturing process (e.g. fracking), can be found in drilling muds, and can accumulate in drilling equipment over time.

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

Bringing more of this TENORM to the surface has the potential to greatly impact public health and the environment. Since 2013, the Pennsylvania Department of Environmental Protection (PA DEP) has been gathering raw data on TENORM associated with oil and gas activity in the state. The study was initiated due to the volume of waste containing high TENORM concentrations in the state’s landfills, something that is largely unregulated at the state and federal level. In January 2015, the PA DEP released a report that outlined their findings and conclusions, including potential exposures, TENORM disposal practices, and possible environmental impacts.

Radioactivity Study Overview

Drilling mud being collected on the well pad

This review touches on the samples tested, the findings, and the conclusions drawn after analysis. The main areas of concern included potential exposure to workers, members of the public, and the environment.

The samples gathered by the DEP came from 38 well sites, conventional and unconventional, by testing solids, liquids, ambient air, soils, and natural gas near oil and gas activity in Pennsylvania. All samples contained TENORM or were in some way impacted by TENORM due to oil and gas operations. The samples were mainly tested for radioactive isotopes, specifically radium, through radiological surveys.

The PA DEP concluded in the cases of well sites, wastewater treatment plants (POTW), centralized wastewater treatment plants, zero liquid discharge plants, landfills, natural gas in underground storage, natural gas fired power plants, compressor stations, natural gas processing plants, radon dosimetry (the calculation and assessment of the radiation dose received by the human body), and oil and gas brine-treated roads that there is little potential for internal radiation exposure to workers and members of the public. In spite of this, each section of the report typically concluded with: however, there is a potential for radiological environmental impacts…

Examples of these findings include:

There is little potential for radiological exposure to workers and members of the public from handling and temporary storage of produced water on natural gas well sites. However, there is a potential for radiological environmental impacts from spills of produced water from unconventional natural gas well sites and from spills that could occur from the transportation of this fluid.
There is little potential for radiological exposure to workers and members of the public from sediment-impacted soil at landfills that accepted O&G waste for disposal. However, there may be a radiological environmental impact to soil from the sediments from landfill leachate treatment facilities that treat leachate from landfills that accept O&G waste for disposal.
Radium 226 was detected within the hydraulic fracturing fluid ranging from 64.0-21,000 pCi/L. Radium-228 was also detected ranging from 4.5-1,640 pCi/L. The hydraulic fracturing fluid was made up of a combination of fresh water, produced water, and reuse flowback fluid. There is little potential impact for radiological exposure to workers and members of the public from handling and temporary storage of flowback fluid on natural gas well sites. However, there is a potential for radiological environmental impacts from spills of flowback fluid on natural gas well sites and from spills that could occur from the transport of this fluid.
Nine influent and seven effluent leachate samples were collected at the nine selected landfills. Radium was detected in all of the leachate samples. Radium-226 concentrations were detected in produced water samples ranging from 40.5 – 26,600 pCi/L. Radium-228 concentrations were also detected ranging from 26.0 – 1,900 pCi/L. The Ra-226 activity in unconventional well site produced water is approximately 20 times greater than that observed in conventional well site produced water. The ratio of Ra-226 to Ra-228 in unconventional well site produced water is approximately eight times greater than that found in conventional well site produced water. (Sections 3.3.4 and 3.6.3) (PA DEP TENORM study report section 9.0)

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

While the report comprehensively covers the processes from drilling to end users, the number of samples collected and analyzed are very sparse for a state-wide study. Just to give an idea, only 8 well sites were sampled during the flowback phase and of the 8 only 4 had enough volume to analyze. Of 14 drill mud samples collected, only 5 were analyzed as liquids, and alpha & beta analysis was only done on one sample.

Obtaining the proper sample size is often a major barrier for field studies. Additional research needs to be conducted with a larger sample size and more rigorous exposure monitoring to determine specific risk metrics for workers and the public.

Current Handling of TENORM

From drilling to distribution, there are many topics of concern associated with TENORM; however, we will focus on the current treatment of TENORM waste, the release of data, and the transparency of this issue.

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

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

According to the DEP report, hydraulic fracturing produces an enormous stream of waste by-products. Safe disposal of this waste has not yet been devised. A few of the conclusions concerning TENORM disposal and treatment in the report listed some areas of concern, identified below:

Filter cake ^[1] and its radiological environmental impact if spilled, and
The amount of radioactive waste entering the landfills in PA, which reached 430,317 tons in the first 10 months of 2014.

In unison with the conclusions were recommendations, where the report “recommends considering limiting radioactive effluent discharge from landfills, and adding radium-226 and radium-228 to annual sample analysis of leachate from landfills.” Additionally, the report states that if something such as filter cake spills, it will bring into question the safety of long-term disposal and suggest a protocol revision.

Public Health Concerns

The report identified two places where there is a higher than average radioactive exposure risk for workers and community members of the public: specifically at centralized wastewater treatment plants and zero liquid discharge plants that treat oil and gas wastewater. An additional unknown is whether there is a potential inhalation or ingestion hazard from fixed alpha and beta surface radioactivity if materials are disturbed. As a general precaution, they recommend the evaluation of worker’s use of protective equipment under certain circumstances.

Although research has not come to a consensus regarding a safe level of radiation exposure, it should not be assumed that any exposure is safe. Past research has evaluated two types of radiation exposure: stochastic and non-stochastic, both of which have their own risks and are known to be harmful to the human body. The EPA has defined stochastic effects as those associated with long-term, low level exposure to radiation, while non-stochastic effects are associated with short-term, high-level exposure. From past scientific research, radiation is known to cause cancer and alter DNA, causing genetic mutations that can occur from both stochastic and non-stochastic exposure. Radiation sickness is also common, which involves nausea, weakness, damage to the central nervous system, and diminished organ function. Exposure levels set by the EPA and other regulatory agencies fall at 100 millirem (mrem) per year to avoid acute health effects. As a point of reference, medical X-rays deliver less than 10 mrem, and yearly background exposure can be about 300 mrem.

In the report, Radiological Dose and Risk Assessment of Landfill Disposal of TENORM in North Dakota, Argonne National Laboratory researchers suggest that the exposure to workers be limited and monitored. In many of their studies, they found the doses exceed the 100 mrem/year level in the workers when the appropriate attire is not worn during working hours, which raised some concern.

The DEP deems certain radiation levels “allowable”, but it should be noted that allowable doses are set by federal agencies and may be arbitrary. Based on the PA DEP’s report, consumers of produced gas can get up to 17.8% of their yearly radiation allowance, while POTW workers could get up to 36.3% of their yearly allowable dose. According to the Nuclear Information and Resource Service, radiation bio-accumulates in ecosystems and in the body, which introduces a serious confounder in understanding the risk posed by a dose of 17.8% per year.

Transparency of Radiation Risk

The DEP has been gathering data for their TENORM report since 2012. In July of 2014, Delaware Riverkeeper Network filed a Right-to Know request to obtain the information that the DEP had collected in order for their expert to analyze the raw data. The department refused to release the information, insisting that “the release of preliminary invalidated data, including sample locations, could likely result in a substantial and demonstrable risk of physical harm, pose a security risk and lead to erroneous and/or misleading characterizations of the levels and effects of the radioactive risks.” Essentially, the DEP was equating the risks of radioactive material to the risks of releasing raw data — two incomparable risks. DRN appealed, claiming that they simply sought the raw information, which is presumed public unless exempt, and would have no risk on the public. PA DEP was ordered to release their records to DRN within 30 days.

Conclusion

One observation that you could take from this report is the lack of regulatory advancement. The study is filled with suggestions, like:

Radium should be added to the PA spill protocol to ensure cleanups are adequately characterized,
A limited potential was found for recreationists on roads with oil and gas brine from conventional natural gas wells–further study should be conducted, and
More testing is needed to identify areas of contamination and any area should be cleaned up.

Intent doesn’t make the changes; action does. Will any regulations change, at least in Pennsylvania where radioactive materials are returning to the surface on a daily basis? There seems to be no urgency when it comes to regulating TENORM and its many issues at the state level. Are workers, citizens, and the environment truly being protected or will we wait for a disaster to spur action?

Footnotes:

[1] This is the residue deposited on a permeable medium when a slurry, such as a drilling fluid, is forced against the medium under pressure. Filtrate is the liquid that passes through the medium, leaving the cake on the medium.

A South American Crossroads

May 29, 2015/by Guest Author

by Brook Lenker, Executive Director

Gracious. Passionate. Determined.

Few words fully capture the evocative resilience of Argentina where history is as turbulent as the winds of Patagonia. Fracking for oil and natural gas is a growing storm on the national horizon, and the effects will be fueled or mitigated by the ceaseless power of the Argentine people.

In the plains of Vaca Muerta, the forces collide. Democracy and calls for transparency meet big energy and nonresponsive government. Chevron has seduced YPF, the state-supported oil company, for a heavily-subsidized stake in the hydrocarbon riches. The shale play represents some of the largest oil and gas reserves in the world, proportional to the scale of concern about excessive use of water and its possible contamination; ranching and agriculture are the lifeblood of this drought-prone land. So much is at stake.

Our Energy Solutions in South America

FracTracker, Earthworks, and Ecologic Institute sent a delegation to Argentina and Uruguay from May 5 through the 12th as part of an outreach program called Our Energy Solutions made possible by our hosts’ generosity, foundation support, and last year’s Indiegogo campaign.

Eager audiences greeted our presentations about the American experience with unconventional oil and gas development and the promise of renewable energy. It was standing room only at a Senate forum in Buenos Aires and the offices of El Telegrafo in Paysandu. In Parana, we kicked-off a national conference about fracking and concluded our tour in San Rafael – a city on the northern fringe of the drilling boom. In total, we addressed more than 650 people, answering their concerns, cultivating their understanding of the perils of extraction, and sharing the opportunities for cleaner energy. Our ultimate reach was even greater, magnified by television and newspaper coverage and connections fostered with other organizations and institutions. The new relationships in South America may achieve unfathomable good.

A Moral Imperative

With his Argentine roots, Pope Francis is a ubiquitous and revered figure across the country. He’s also a gentle global force calling on humanity to confront climate change and care for the earth. One of our unforgettable hosts, Juan Pablo Olsson, had been in Rome the week prior to meet with the pontiff and participate in an environmental conference at the Vatican. Inspired, Juan Pablo and other speakers cited the moral imperative of the issues we were communicating and shared this papal plea: “a humble and simple request to work together to defend the future of the planet.”

The call still resonates. Every day we are confronted by the acute harms of unrestrained extraction – from contamination of air and water to the violation of fundamental human and constitutional rights. The glaciers of Patagonia aren’t melting, they are crying – for a global demonstration of compassion.

Stay tuned for news in the fall from the next leg of this journey – Europe.

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

May 27, 2015/by Guest Author

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

Oklahoma has made news recently because its earthquake story is so dramatic. The state that once averaged one to two magnitude 3 earthquakes per year now averages one to two per day. This same state, which never used to be seismically active, is now more seismically active than California. In terms of understanding the connection between wastewater disposal wells and earthquakes, though, it may be more helpful to look at other states first. Let us explore this issue further in Man-made Earthquakes, Part 2.

How other states handle induced seismicity

In 2010 and 2011, Arkansas experienced a swarm of earthquakes near the town of Greenbrier that culminated in a magnitude 4.7 earthquake. Officials in Arkansas ordered a moratorium on all disposal wells in the area, and earthquake activity quickly subsided.

In late 2011, Ohio experienced small earthquakes near a disposal well that culminated in a magnitude 4 earthquake that shook and startled residents. The disposal well was shut down, and the earthquakes subsided. Subsequent research into the earthquake confirmed that the disposal well in question had, in fact, triggered the earthquake. A swarm of earthquakes last year in Ohio shut down another well, and again, after the wastewater injection ceased, the earthquakes subsided.

Similarly in Kansas, after two earthquakes of magnitudes 4.7 and 4.9 shook the state in late 2014, officials ordered wells in two southern counties to decrease the volume of water injected into the ground. Again, earthquake activity quickly subsided.

A seismologist’s toolbox

A favorite saying among scientists is that correlation does not equal causation, and it’s easy to apply that phrase to the correlations seen in Ohio, Arkansas, and Kansas. Yet scientists remain certain that wastewater disposal wells can trigger earthquakes. So what are some of the techniques they use to come to these conclusions? At the Virginia Seismological Observatory (VTSO), two of the tools we used to determine a connection were cross-correlation programs and beach ball diagrams.

Cross-correlation

The VTSO research, which was funded by the National Energy Technology Laboratory, looked specifically at earthquake swarms that have popped up a couple times near a wastewater disposal well in West Virginia. We used a cross-correlation program to distinguish earthquakes that were likely triggered by the nearby well from events that might be natural or related to mining activity.

A seismic station records all of the vibrations that occur around it as squiggly lines. When an earthquake wave passes through, its squiggly lines take on a specific shape, known as a waveform, that seismologists can easily recognize (as an example, the VTSO logo in Fig. 1 was designed using a waveform from one of West Virginia’s potentially induced earthquakes.)

Figure 1. Virginia Tech Seismological Observatory logo w/waveform

For naturally occurring earthquakes, the waveforms will have some variation in shape because they come from different faults in different locations. When an injection well triggers earthquakes, it typically activates faults that are within close proximity, resulting in greater similarities between waveforms. A cross-correlation program is simply a computer program that can run through days, weeks, or months of data from a seismometer to find those similar waveforms. When matching waveforms indicate that earthquake activity is occurring near an injection well – and especially in regions that don’t have a history of seismic activity – we can conclude the earthquakes are triggered by human activity.

Beach Balls

Any earthquake fault, whether it’s active or ancient, is stressed to its breaking point. The difference is that, in places like California that are active, the natural forces against the faults often change, which triggers earthquakes. Ancient faults are still highly stressed, but the ground around them has become more stabilized. However at any point in time, if an unexpected force comes along, it can still trigger an earthquake.

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

Figure 2. Beach ball diagrams of 16 of the largest earthquakes in Oklahoma in 2014, all showing similar focal mechanisms, which is indicative of induced seismicity.

Earthquake faults don’t all point in the same direction, which means different forces will affect faults differently. Depending on their orientation, some faults might shift in a north-south direction, some might shift in an east-west direction, some might be tilted at an angle, while others are more upright, etc. Seismologists use focal mechanisms to describe the movement of a fault during an earthquake, and these focal mechanisms are depicted by beach ball diagrams (Figure 2). The beach ball diagrams look, literally, like black and white beach balls. Different quadrants of the “beach ball” will be more dominant depending on what type of fault it was and how it moved (See USGS definition of Focal Mechanisms and the “beach ball” symbol).

When an earthquake is triggered by an injection well, it means that the fluid injected into the ground is essentially the straw that broke the camel’s back. Earthquake theory predicts that the forces from an injection well won’t trigger all faults, but only those that are oriented just right. Since we expect that only certain faults with just the right orientation will get triggered, that means we also expect the earthquakes to have similar focal mechanisms, and thus, similar beach ball diagrams. And that’s exactly what we see in Oklahoma.

Cross-correlation programs and beach ball diagrams are only two tools we used at the VTSO to confirm which earthquakes were induced, but seismologists have many means of determining if an earthquake is induced or natural.

Limitations of science?

With so much strong scientific evidence, why can people in industry still claim there isn’t enough science to officially confirm that an injection well triggered an earthquake? In some cases, these claims are simply wrong. In other cases, though, especially in Oklahoma, the problem is that no one was monitoring the disposal wells and the earthquakes from the start. Well operators were not required to publicly track the volumes of water they injected into wells until recently, and no one monitored for nearby earthquake activity. The big problem is not a lack of scientific evidence, but a lack of data from industry to perform sufficient research. Scientists need information about the history, volume, and pressure of fluid injection at a disposal well if they’re to confirm whether or not earthquakes are triggered by it. Often, that information is proprietary and not publically available, or it may not exist at all.

At this point though, two other factors make direct correlations between injection wells and earthquakes in Oklahoma even more difficult:

So many wells have injected signficiant volumes of water in close enough proximity that pointing a finger at a specific well is more challenging.
A large number of wells have injected water for so many years, that the earthquakes are migrating farther and farther from their original source. Again, pointing a finger at a specific well gets harder with time.

What we know

We know what induced seismicity is and why it occurs. We know that if a wastewater injection well disposes of large volumes of fluids deep underground in a region that has existing faults, it will likely trigger earthquakes. We know that if a region previously had few earthquakes, and then sees an uptick in earthquakes after wastewater injection begins, the earthquakes are likely induced. We know that if we want to understand the situation better, we need more seismic stations near disposal wells so we can more accurately monitor the area for seismicity both before and after the well becomes active.

What don’t we know?

We don’t know how big an induced earthquake can get. Oklahoma’s largest earthquake, which was also the largest induced earthquake ever recorded in the United States, was a magnitude 5.6. That’s big enough to cause millions of dollars of damage. Worldwide, the largest earthquake suspected to be induced occurred near the Koyna Dam in India, where a magnitude 6.3 earthquake killed nearly 200 people in 1967.

Can an earthquake that large occur in the central U.S.? The best guess right now: yes.

Seismologists suspect that an induced earthquake could get as big as the size of the fault. If a fault is big enough to trigger a magnitude 7 or 8 earthquake, then that is potentially how large an induced earthquake could be. In the early 1800s, three earthquakes between magnitudes 7 and 8 struck along the New Madrid Fault Zone near St. Louis, Missouri. Toward the end of the 1800s, a magnitude 7 earthquake shook Charleston, South Carolina. In those two areas, injection wells could potentially trigger very large earthquakes.

We have no historic record of earthquakes that large in Oklahoma, so right now, the best guess is that the largest an earthquake could get there would be between a magnitude 6 and 6.5. That would be big enough to cause significant damage, injuries, and possibly death.

The solution

What’s the take-home message from all of this?

First, the science exists to back up the conclusion that wastewater injection wells trigger earthquakes.
Second, if we want to get a better feel for which wells are more problematic, we need funding, seismic stations, and staff to monitor seismic activity around all high-volume injection wells, along with a history of injection times, volumes and pressures at the well.
Third, this is a problem that, if left unchecked, has the potential to result in major damage, incredible expense, and possibly loss of life.

Induced earthquakes are a real phenomenon. While more research is necessary to help us better understand the intricacies of these events and to identify correlations in complex cases, the general cause of the earthquake swarms in Oklahoma and other states is not a mystery. They are man-made problems, backed up by decades of scientific research. They have the potential to create significant damage, but we have the wherewithal to prevent them. We don’t need to go to the extreme of shutting down all wells, but rather, we just need to be able to monitor the wells and ensure that they don’t trigger earthquakes. If a well does trigger an earthquake, then at that point, the well operators can either experiment with significantly decreasing the volume of water that’s injected, or the well can be shut down completely. Understanding and acknowledging the connection between injection wells and earthquakes will make induced seismicity a much easier problem to solve.

Read Part 1