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A Disturbing Tale of Diminishing Returns in Ohio

A Disturbing Tale of Diminishing Returns in Ohio
The US Energy Information Administration (EIA) recently announced that Ohio’s recoverable shale gas reserves have magically increased by 11,076 billion cubic feet (BCF). This increase ranks the Buckeye State in the top 5 for changes in recoverable shale natural gas reserves between 2016 and 2017 (pages 31- 32 here). After reading the predictable and superficial media coverage, we thought it was time to revisit the data to ask a pertinent question: What is the fracking industry costing Ohio?

Recent Shale Gas Trends in Ohio

According to the EIA’s report, Ohio currently sits at #7 on their list of proven reserves. It is estimated there are 27,021 BCF of shale gas beneath the state (Figure 1).

Graph of natural gas reserves in different states 2016-2017

Figure 1. Proven and change in proven natural gas reserves from 2016 to 2017 for the top 11 states and the Gulf of Mexico (calculated from EIA’s “U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2017”).

There are a few variations in the way the oil and gas industry defines proven reserves:

…an estimated quantity of all hydrocarbons statistically defined as crude oil or natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proven if economic producibility is supported by either actual production or conclusive formation testing. – The Organization of Petroleum Exporting Countries

… the quantity of natural resources that a company reasonably expects to extract from a given formation… Proven reserves are classified as having a 90% or greater likelihood of being present and economically viable for extraction in current conditions… Proven reserves also take into account the current technology being used for extraction, regional regulations and market conditions as part of the estimation process. For this reason, proven reserves can seemingly take unexpected leaps and drops. Depending on the regional disclosure regulations, extraction companies might only disclose proven reserves even though they will have estimates for probable and possible reserves. – Investopedia

What’s missing from this picture?

Neither of the definitions above address the large volume of water or wastewater infrastructure required to tap into “proven reserves.” While compiling data for unconventional wells and injection wells, we noticed that the high-volume hydraulic fracturing (HVHF) industry is at a concerning crossroads. In terms of “energy return on energy invested,” HVHF is requiring more and more resources to stay afloat.

OH quarterly Utica oil & gas production along with quarterly Class II injection well volumes:

The map below shows oil and gas production from Utica wells (the primary form of shale gas drilling in Ohio). It also shows the volume of wastewater disposed in Class II salt water disposal injection wells.

 View map fullscreen | How FracTracker maps work

Publications like the aforementioned EIA article and language out of Columbus highlight the nominal increases in fracking productivity. They greatly diminish, or more often than not ignore, how resource demand and waste production are also increasing. The data speak to a story of diminishing returns – an industry requiring more resources to keep up gross production while simultaneously driving net production off a cliff (Figure 2).

Graph of Utica permits in Ohio on a cumulative and monthly basis along with the average price of West Texas Intermediate (WTI) and Brent Crude oil per barrel from September, 2010 to December, 2018

Figure 2. Number of Utica permits in Ohio on a cumulative and monthly basis along with the average price of West Texas Intermediate (WTI) and Brent Crude oil per barrel from September 2010 to December 2018

The Great Decoupling of New Year’s 2013

In the following analysis, we look at the declining efficiency of the HVHF industry throughout Ohio. The data spans the end of 2010 to middle of 2018. We worked with Columbus-area volunteer Gary Allison to conduct this analysis; without Gary’s help this work and resulting map, would not have been possible.

A little more than five years ago today, a significant shift took place in Ohio, as the number of producing gas wells increased while oil well numbers leveled off. The industry’s permitting high-water mark came in June of 2014 with 101 Utica permits that month (a level the industry hasn’t come close to since). The current six-month permitting average is 25 per month.

As the ball dropped in Times Square ringing in 2014, in Ohio, a decoupling between oil and gas wells was underway and continues to this day. The number of wells coming online annually increased by 229 oil wells and 414 gas wells.

Graph showing Number of producing oil and gas wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Figure 3. Number of producing oil and gas wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Graph of Producing oil and gas wells as a percentage of permitted wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Figure 4. Producing oil and gas wells as a percentage of permitted wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Permits

The ringing in of 2014 also saw an increase in the number of producing wells as a percentage of those permitted. In 2014, the general philosophy was that the HVHF industry needed to permit roughly 5.5 oil wells or 7 gas wells to generate one producing well. Since 2014, however, this ratio has dropped to 2.2 for oil and 1.4 for gas well permits.

Put another way, the industry’s ability to avoid dry wells has increased by 13% for oil and 18% for gas per year. As of Q2-2018, viable oil wells stood at 44% of permitted wells while viable gas wells amounted to 71% of the permitted inventory (Figure 4).

Production declines

from the top-left to the bottom-right

To understand how quickly production is declining in Ohio, we compiled annual (2011-2012) and quarterly (Q1-2013 to Q2-2018) production data from 2,064 unconventional laterals.

First, we present average data for the nine oldest wells with respect to oil and gas production on a per day basis (Note: Two of the nine wells we examined, the Geatches MAH 3H and Hosey POR 6H-X laterals, only produced in 2011-2012 when data was collected on an annual basis preventing their incorporation into Figures 6 and 7 belwo). From an oil perspective, these nine wells exhibited 44% declines from year 1 to years 2-3 and 91% declines by 2018 (Figure 5). With respect to natural gas, these nine wells exhibited 34% declines from year 1 to years 2-3 and 79% declines by 2018 (Figure 5).

Figure 5. Average daily oil and gas production decline curves for the above seven hydraulically fractured laterals in Ohio’s Utica Shale Basin, 2011 to Q2-2018

Four of the nine wells demonstrated 71% declines by the second and third years and nearly 98% declines by by Q2-2018 (Figure 6). These declines lend credence to recent headlines like Fracking’s Secret Problem—Oil Wells Aren’t Producing as Much as Forecast in the January 2nd issue of The Wall Street Journal. Four of the nine wells demonstrated 49% declines by the second and third years and nearly 81% declines by Q2-2018 (Figure 7).

Figure 6. Oil production decline curves for seven hydraulically fractured laterals in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Figure 7. Natural gas production decline curves for seven hydraulically fractured laterals in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Fracking waste, lateral length, and water demand

from bottom-left to the top-right

An analysis of fracking’s environmental and economic impact is incomplete if it ignores waste production and disposal. In Ohio, there are 226 active Class II Salt Water Disposal (SWD) wells. Why so many?

  1. Ohio’s Class II well inventory serves as the primary receptacle for HVHF liquid waste for Pennsylvania, West Virginia, and Ohio.
  2. The Class II network is situated in a crescent shape around the state’s unconventional wells. This expands the geographic impact of HVHF to counties like Ashtabula, Trumbull, and Portage to the northeast and Washington, Athens, and Muskingum to the south (Figure 8).

Map of Ohio showing cumulative production of unconventional wells and waste disposal volume of injection wells

Figure 8. Ohio’s unconventional gas laterals and Class II salt water disposal injection wells. Weighted by cumulative production and waste disposal volumes to Q3-2018.

Disposal Rates

We graphed average per well (barrels) and cumulative (million barrels) disposal rates from Q3-2010 to Q3-2018 for these wells. The data shows an average increase of 24,822 barrels (+1.05 million gallons) per well, each year.

That’s a 51% per year increase (Figure 9).

A deeper dive into the data reveals that the top 20 most active Class II wells are accepting more waste than ever before: an astounding annual per well increase of 728,811 barrels (+30.61 million gallons) or a 230% per year increase (Figure 10). This divergence resulted in the top 20 wells disposing of 4.95 times the statewide average between Q3-2010 and Q2-2013. They disposed 13.82 times the statewide average as recently as Q3-2018 (Figure 11).

All of this means that we are putting an increasing amount of pressure on fewer and fewer wells. The trickle out, down, and up of this dynamic will foist a myriad of environmental and economic costs to areas surrounding wells. As an example, the images below are injection wells currently under construction in Brookfield, Ohio, outside Warren and minutes from the Pennsylvania border.

More concerning is the fact that areas of Ohio that are injection well hotspots, like Warren, are proposing new fracking-friendly legislation. These disturbing bills would lubricate the wheels for continued expansion of fracking waste disposal and permitting. House bills 578 and 393 and Senate Bill 165 monetize and/or commodify fracking waste by giving townships a share of the revenue. Such bills “…would only incentivize communities to encourage more waste to come into their existing inventory of Class II… wells, creating yet another race to the bottom.” Co-sponsors of the bills include Democratic Reps. Michael O’Brien, Glenn Holms, John Patterson, and Craig Riefel.

Lateral Lengths

The above trends reflect an equally disturbing trend in lateral length. Ohio’s unconventional laterals are growing at a rate of 9.1 to 15.6%, depending on whether you buy that this trend is linear or exponential (Figure 12). This author believes the trend is exponential for the foreseeable future. Furthermore, it’s likely that “super laterals” in excess of 3-3.5 miles will have a profound impact on the trend. (See The Freshwater and Liquid Waste Impact of Unconventional Oil and Gas in Ohio and West Virginia.)

This lateral length increase substantially increases water demand per lateral. It also impacts Class II well disposal rates. The increase accounts for 76% of the former and 88% of the latter when graphed against each other (Figure 13).

Figure 12. Ohio Utica unconventional lateral length from Q3-2010 to Q4-2018

Figure 13. Ohio Utica unconventional water demand and Class II SWD injection well disposal volumes vs lateral length from Q3-2010 to Q4-2018.

Conclusion

This relationship between production, resource demand, and waste disposal rates should disturb policymakers, citizens, and the industry. One way to this problem is to more holistically price resource utilization (or stop oil and gas development entirely).

Unfortunately, states like Ohio are practically giving water away to the industry.

Politicians are constructing legislation that would unleash injection well expansion. This would allow disposal to proceed at rates that don’t address supply-side concerns. It’s startling that an industry and political landscape that puts such a premium on “market forces” is unwilling to address these trends with market mechanisms.

We will continue to monitor these trends and hope to spread these insights to states like Oklahoma and Texas in the future.

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance – with invaluable data compilation assistance from Gary Allison


Data Downloads

FracTracker is a proponent of data transparency, and so we often share the data we use to construct our maps analyses. Click on the links below to download the data associated with the present analysis:

 

Source: FracTracker Alliance

By:  January 9, 2019/0 Comments/in Articles, Data and Analysis /by Ted Auch, PhD

LINK:  https://www.fractracker.org/2019/01/diminishing-returns-in-ohio/?fbclid=IwAR2f98mrz640_fPkiAAJEJlzUmne7Qd4zYn0xNqwm3dBW3icZDhX56LUlG

 

 

 

 

 

 

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Link to interactive map: http://maps.fractracker.org/3.13/?appid=1165798efb424e34a5d3c92bca61e53f

Showing details down to the street location:

Quarterly Oil and Gas Production for 2064 Utica Wells in Ohio 2011 to Q2 2018

Quarterly Oil and Gas Production for 2064 Utica Wells in Ohio 2011 to Q2 2018

Ohio Class II Salt Water Disposal (SWD) Injection Well Volumes 2010 to Q3-2018

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Another article:

Fracked Shale Oil Wells Drying Up Faster than Predicted, Wall Street Journal Finds

Read time: 9 mins

Pumpjacks in Permian Basin outside Midland, Texas

In 2015, Pioneer Natural Resources filed a report with the federal Securities and Exchange Commission, in which the shale drilling and fracking company said that it was “drilling the most productive wells in the Eagle Ford Shale” in Texas.

That made the company a major player in what local trade papers were calling “arguably the largest single economic event in Texas history,” as drillers pumped more than a billion barrels of fossil fuels from the Eagle Ford.

Its Eagle Ford wells, Pioneer’s filing said, were massive finds, with each well able to deliver an average of roughly 1.3 million barrels of oil and other fossil fuels over their lifetimes.

Three years later, The Wall Street Journal checked the numbers, investigating how those massive wells are turning out for Pioneer.

Turns out, not so well. And Pioneer is not alone.

Those 1.3 million-barrel wells, the Journal reported, “now appear to be on a pace to produce about 482,000 barrels” apiece — a little over a third of what Pioneer told investors they could deliver.

In Texas’ famed Permian Basin, now the nation’s most productive shale oil field, where Pioneer predicted 960,000 barrels from each of its shale wells in 2015, the Journal concluded that those “wells are now on track to produce about 720,000 barrels” each.

Not only are the wells already drying up at a much faster rate than the company predicted, according to the Journal’s investigative report, but Pioneer’s projections require oil to flow for at least 50 years after the well was drilled and fracked — a projection experts told the Journal would be “extremely optimistic.”

Fracking every one of those wells required a vast amount of chemicals, sand, and water. In Karnes County, Texas, one of the two Eagle Ford counties where Pioneer concentrated its drilling in 2015, the average round of fracking that year drank up roughly 143,000 barrels of water per well.

Dry Creek Water Station sign looking very dry outside Sanderson, Texas
Dry Creek Water Station near Sanderson in West Texas, looking very dry. Credit: Brant KellyCC BY 2.0

A Billion Missing Barrels

And while Pioneer has become one of the most active drillers in the Permian, it’s hardly alone in booking projections that the Journal found were dubious.

Two-thirds of projections made by the fracking companies between 2014 and 2017 in America’s four hottest drilling regions appear to have been overly optimistic, according to the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in Texas and North Dakota,” it reported. “Collectively, the companies that made projections are on track to pump nearly 10 percent less oil and gas than they forecast for those areas, according to the analysis of data from Rystad Energy AS, an energy consulting firm.”

That is the equivalent of almost one billion barrels of oil and gas over 30 years,” the Journal added, “worth more than $30 billion at current prices.”

The problems the Journal focused on will be familiar to those who’ve turned a critical eye to shale reserves in the past: The most productive areas, or “sweet spots,” are smaller than first expected and companies predicted that wells would dry up slower than they have. DeSmog launched its latest series covering shale’s financial woes in April 2018 and our coverage extends back over a half-decade.

For the Journal, the take-aways were financial. “So far, investors have largely lost money,” the newspaper pointed out, adding that a review of 29 drillers showed companies have spent $112 billion more than they earned from drilling in the past decade. “Since 2008, an index of U.S. oil and gas companies has fallen 43 percent, while the S&P 500 index has more than doubled in that time, including dividends.”

The industry’s defenders argue that spending money now to make money later is simply how business works — this year’s “losses” are actually investments in future profits.

But because shale drilling is relatively new, even the experts are left guessing about how much oil will be flowing from the wells 10, 20, or 30 years after fracking — and investors have become frustrated as shale drillers have largely failed to turn the corner and start racking up profits instead of continuing to operate in the red.

Natural gas flare in the Permian Basin near Midland, Texas
A natural gas flare in West Texas, near Midland. In 2018 the price of natural gas in the Permian fell below zero. Credit: © Laura Evangelisto

The industry’s only hope of paying off debt and rewarding equity investors is for oil prices to rise high enough for long enough that they can generate consistent cash flow without breaking the bank on capex [capital expenditures],” said Clark Williams-Derry, director of energy finance at the Sightline Institute.

But they’ll have real problems — sweet spots are getting depleted, wells are declining faster than they’d hoped, pipelines are still constrained causing deep discounts in some markets, co-produced gas is close to worthless, and any sustained rebound will boost the cost for drilling services (i.e., higher prices mean higher costs).”

“Plus,” he added, “investors need to worry about long-term cleanup costs.”

Calling in the Experts

And the pressure on the experts charged with preparing oil and gas production estimates for drillers is enormous. As the first shale wells get older and more production history rolls in, engineers have developed models they say can make better predictions — but the Journal suggested those tools haven’t been widely adopted.

Why aren’t we doing this?” one engineer demanded repeatedly after John Lee, one of the most prominent reserves experts in the U.S., gave a talk in Houston in July about making more accurate shale projections.

‘Because we own stock,’ replied another engineer, sparking laughter,” the Journal reported.

The Journal’s reporting frequently cited Rystad Energy, an independent oil and gas consulting firm, as the source of more conservative projections — but, as DeSmog has previously reported, Rystad isn’t the only large independent firm to find troubling indications that shale wells are on track to produce only a fraction of their “proved” reserves.

Wood Mackenzie, another major oil consulting firm, studied the Permian’s Wolfcamp shale, where early projections predicted that production from a five-year-old well should be declining at a rate of 5 to 10 percent. Those wells, the firm found, are actually declining by roughly 15 percent a year — a significantly larger drop than expected and an ominous sign for any companies projecting wells can last 50 years.

Dried out clay
Things are looking a little drier than expected for the future of fracked wells in Texas. Credit: Francesco Ungaro from Pexels

And fracking giant Schlumberger — which like Halliburton specializes in performing hydraulic fracturing jobs on wells other companies drill — has begun calling attention to a problem with much more immediate impacts: The sweet spots are getting too crowded.

For years, the industry has said that it can minimize impacts by drilling multiple wells from the same well pad — but in parts of the Permian, wells drilled later on or near existing well pads have proved roughly 30 percent less productive compared to the first well drilled.

[T]he well-established market consensus that the Permian can continue to provide 1.5 million barrels per day of annual production growth for the foreseeable future is starting to be called into question,” Schlumberger’s CEO Paal Kibsgaard said in an October 2018 earnings call. “At present, our industry has yet to understand how reservoir conditions and well productivity change as we continue to pump billions of gallons of water and billions of pounds of sand into the ground each year.”

Kibsgaard warned that similar problems are beginning to show up in the Eagle Ford as well.

The Long-Term Costs of a Boom and a Bust

Karnes County is still the most active part of the Eagle Ford, with 562 drilling permits issued last year. After a heady oilfield boom, oil prices plunged in 2015 and 2016, leading to the layoffs of thousands of workers and royalty checks drying up. This past year, drilling has re-emerged, albeit at a slower pace. “It’s not a boom, but there’s a resurgence here in the Eagle Ford,” Rick Saldana, an energy company superintendent told the Houston Chronicle in October.

Investors have faced a rocky ride. Sanchez Energy, the Eagle Ford’s third largest driller, has now been warned twice by the New York Stock Exchange that it will be de-listed if its stock price, now at roughly $0.26 a share, doesn’t soon rise above $1.

But other impacts of the boom and bust cycle run deeper.

In nearby Dilley, Texas, a former oilfield man-camp, built to house Eagle Ford workers, was turned into the “the South Texas Family Residential Center” in December 2014 by a private prison company. It’s now the nation’s largest immigration detention center for families, housing up to 2,400 people, half of them children.

And while over the past decade, Wall Street and other investors poured billions into fracking — the Journal tallied $112 billion more spent than earned from production at 29 major drillers — the U.S. more broadly has failed to seriously invest in a rapid transition away from climate-changing fossil fuels.

That leaves the U.S. at risk of being left behind as the rest of the world focuses its efforts to innovate on renewable energy prospects that don’t dry up like oil wells. Bethany McLean, a financial journalist famous for first breaking the Enron story, recently told Fortune about conversations she’d had with major private equity investors as she researched her new book Saudi America.

They are all trying to figure out when we’ll be able to see the end of the oil age, because as soon as that happens, the price of oil will go into secular decline (as it did with coal),” she said. “Other countries, namely China, are frantically investing in renewables. For us to crow about our oil wealth, and not focus on renewables, is for us to miss the opportunity to be leaders in the world as it’s going to be.

LINK:  https://www.desmogblog.com/2019/01/10/fracking-shale-oil-wells-drying-faster-predicted-wall-street-journal

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