EC August 2018

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WV Economic Growth (?) and Natural Gas
by William V. DePaulo, Esq. via EC 17 Aug '18

17 Aug '18

Ted Boettner, Dean Baker: Is WV's economic 'comeback' real? (Gazette Opinion) - By Ted Boettner and Dean Baker - 10 hrs ago - (0) <https://www.wvgazettemail.com/opinion/gazette_opinion/op_ed_commentaries/te…> *Local journalism makes a difference* Your support makes that possible — subscribe today <https://www.wvgazettemail.com/subscriptions> [image: Slide1.jpeg] Over the last few months there has been a flurry of op-eds and articles from big corporations and Republican lawmakers arguing that state budget cuts and low-wage policies like “Right-to-Work” are resulting in a booming economy in our state. Some have gone so far to say West Virginia is “America’s Comeback Kid.” West Virginia’s economy is growing in some sectors — most notably natural gas — but it is performing poorly compared to other states and has yet to recover from the Great Recession that begin more than 10 years ago. Let’s dig into the numbers. First, let’s look at our economic recovery from the Great Recession, which began in December 2007 and officially ended in June of 2009. Altogether, West Virginia has about 9,000 fewer jobs and has seen its labor force shrink by 34,000 from December 2007 to June 2018. Only one other state in the country (Wyoming, another energy state) has had slower job growth over this period. West Virginia also had a larger reduction in its workforce than any other state. The state’s economic growth – or change in real (inflation adjusted) Gross Domestic Product (GDP) – was about 9.1 percent from 2007 to 2017, less than 1 percent annually, compared to the U.S. average of 13 percent. Meanwhile, West Virginia is one of 13 states with an unemployment rate higher today than at the start of the Great Recession. As of June 2018, West Virginia had the third highest unemployment rate in the nation at 5.3 percent. Over the last year, employment has grown by 0.9 percent in the Mountain State, which was below the U.S. average and slower than most states. While West Virginia’s real GDP over the last two years has grown relatively fast compared to other states, this is almost entirely fueled by the rise in natural gas prices, which have grown by about 66 percent or $1 per thousand cubic feet over the last two years. The rise in natural gas prices has unleashed a pipeline building construction boom along with more natural gas production – growing from 1.3 trillion to 1.6 trillion cubic feet of production over the last two years. West Virginia’s real GDP grew by $1.8 billion over the last year. However, $1.4 billion or 78 percent of this growth was from the mining sector that includes natural gas extraction, coal mining, and other mining. The growth in natural gas extraction and metallurgical coal production is not only the central reason for the strong GDP growth over this period but it is mostly likely responsible for West Virginia’s relative strong earnings growth over the last year. This means that West Virginia’s politicians can’t really take credit for the growth of the last two years, unless they want to claim responsibility for the jump in world energy prices that gave us $3.00 a gallon gas. The loss of oil exports from Venezuela and Iran has far more to do with recent growth than the end of “Obama’s war on coal” While state and local public policy can impact economic growth – especially over the long-run (think infrastructure, education, higher education) – its effects are typically small in the short run outside of a burst of deficit spending (which has to be paid back over the medium-run) or a big infusion of federal money. For example, the expansion of Medicaid to working adults has increased federal spending in West Virginia by $900 million per year while the Trump tax cuts — that mostly go to the wealthy — will cut taxes by over $1 billion per year in West Virginia. Other factors that play a big role in state economic growth are climate, proximity to national markets, energy prices, the availability of raw materials and natural resources, and the composition of each state’s economy. The state is also largely at the mercy of national and global economic trends, such as economic recessions caused by housing and tech bubbles, or tight monetary policy through interest-rate hikes. Most people and businesses look for a good quality of life, sound infrastructure, world-class schools, and a place where they can make money. While jobs and our labor market are beginning to rebound, it is important that we have a clear understanding of the evidence and data before asserting that state or federal policies over the last several years are responsible for the recent economic growth. West Virginia’s economy still has a long way to go before it gets back to where it was over a decade ago and most of our economic growth is tied up in volatile industries where the benefits largely go out of state and the work is insecure. Over the last decade, most West Virginia households have seen no income gains from the state’s economic growth. If policymakers want to grow the state’s economy so it benefits everyone, not just a few, they will need to put more money, power, and skills in the hands of working families. This could include targeted tax cuts for low-income families, investing more in higher education and public broadband, raising the minimum wage, paid sick days for all, using severance taxes to build a sustainable future, and creating a paid family leave program. These policies not only keep more money inside our state, but they also provide a foundation for broader growth and prosperity. Ted Boettner is the Executive Director of the West Virginia Center on Budget and Policy and Dean Baker is a Senior Economist at the Center for Economic and Policy Research in Washington, DC. William V. DePaulo, Esq. 860 Court Street, North Suite 300 Lewisburg, WV 24901 Tel 304-342-5588 Fax 866-850-1501 william.depaulo(a)gmail.com

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Re: [EC] [App. Gas Working Grp.] The intensification of the water footprint of hydraulic fracturing
by cindy rank via EC 17 Aug '18

17 Aug '18

from Tony Ingraffea: Anthony R. Ingraffea [image: Attachments]10:52 AM (52 minutes ago) to *sshonkoff(a)psehealthyenergy.org <sshonkoff(a)psehealthyenergy.org>*, *earthworks*, *Terry*, Amy, Cleanup In shale gas and oil, it has always been about SCALE: the stuff is so damn stingy you have to bludgeon it. Generation I wells used 3-5 millions gallons of water and 1-2 hundred pounds of sand per foot of lateral; gen II Wells, 5-10 million gallons, 500-1000 pounds of sand per foot; current gen III Wells, 10-30 million gallons, a ton of sand, and the laterals are now longer than 2 miles long. EIA forecasts a million more such wells in the next 20 years: you do the math. Might as well just transport The Fingerlakes and much of Wisconsin underground. Getting so absurd that one needs a calculator with only scientific notation to run the numbers: 10 trillion gallons of water, 20 trillion pounds of sand. Think about the carbon footprint of acquiring and transporting it.... We have solutions to this nonsense. Best Tony Sent from my iPad ========================== On Thu, Aug 16, 2018 at 9:53 AM David McMahon <wvdavid(a)wvdavid.net> wrote: > Hi, > > I know that with experience the industry is drilling > longer and longer horizontal well bores – up to 2 or 3 miles when at the > beginning the standard was about 1 mile. Does the article say that this > explains the increased water use or is it more water per foot of horizontal? > > > Dave > > > > David McMahon > > e-Mail: wvdavid(a)wvdavid.net > > Land line: 304-415-4288 > > Fax: 810-958-6143 > > Physical address: 1018 Kanawha Blvd E. #1200 > > Charleston, WV 25301 > > Postal address: 1624 Kenwood Road > > Charleston, WV 25314 > > > > *From:* appalachian-gas-working-group(a)googlegroups.com [mailto: > appalachian-gas-working-group(a)googlegroups.com] *On Behalf Of *William V. > DePaulo, Esq. > *Sent:* Wednesday, August 15, 2018 7:58 PM > *To:* Energy Committee; Appalachian-Gas-Working-Group > *Subject:* [App. Gas Working Grp.] The intensification of the water > footprint of hydraulic fracturing > > > http://advances.sciencemag.org/content/4/8/eaar5982 > The intensification of the water footprint of hydraulic fracturing > > *1. **Andrew J. Kondash**, * > > *2. **Nancy E. Lauer* *and * > > *3. **Avner Vengosh*** > <http://advances.sciencemag.org/content/4/8/eaar5982#corresp-1>* > > See all authors and affiliations > > Science Advances 15 Aug 2018: > Vol. 4, no. 8, eaar5982 > DOI: 10.1126/sciadv.aar5982 > > > > · *Article <http://advances.sciencemag.org/content/4/8/eaar5982>* > > · *Figures & Data > <http://advances.sciencemag.org/content/4/8/eaar5982/tab-figures-data>* > > · *Info & Metrics > <http://advances.sciencemag.org/content/4/8/eaar5982/tab-article-info>* > > · *eLetters > <http://advances.sciencemag.org/content/4/8/eaar5982/tab-e-letters>* > > · * PDF > <http://advances.sciencemag.org/content/4/8/eaar5982/tab-pdf>* > Abstract > > Unconventional oil and gas exploration in the United States has > experienced a period of rapid growth, followed by several years of limited > production due to falling and low natural gas and oil prices. Throughout > this transition, the water use for hydraulic fracturing and wastewater > production in major shale gas and oil production regions has increased; > from 2011 to 2016, the water use per well increased up to 770%, while > flowback and produced water volumes generated within the first year of > production increased up to 1440%. The water-use intensity (that is, > normalized to the energy production) increased ubiquitously in all U.S. > shale basins during this transition period. The steady increase of the > water footprint of hydraulic fracturing with time implies that future > unconventional oil and gas operations will require larger volumes of water > for hydraulic fracturing, which will result in larger produced oil and gas > wastewater volumes. > INTRODUCTION > > The environmental impacts of a fossil fuel–powered economy have led many > nations across the world to begin developing greener energy and > transportation solutions. In particular, the water footprint of fossil fuel > exploration and electricity production has been projected to have major > environmental impacts. It has been estimated that global water withdrawal > for energy production constitutes 15% of the world’s total water > consumption (*1* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-1>). Rapidly > diminishing global water resources due to population growth and climate > change have further exacerbated energy dependence on water availability, > particularly in water-scarce regions (*2* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-2>–*5* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-5>). The > beginning of the 21st century marks a special era with respect to global > energy and water resources. The development of new drilling technologies > and production strategies such as horizontal drilling and hydraulic > fracturing has significantly improved the production of natural gas and oil > by stimulating fluid flow from impermeable shale rocks previously not > considered viable energy sources. Since the mid-2000s, these developments > have spurred exponential growth of unconventional gas and oil well drilling > across the United States and are spreading now to other parts of the world (*Figs. > 1* <http://advances.sciencemag.org/content/4/8/eaar5982#F1> and *2* > <http://advances.sciencemag.org/content/4/8/eaar5982#F2>) (*4* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-4>, *6* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-6>–*10* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-10>). The rise > of unconventional energy development has generated public debate on its > environmental implications (*11* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-11>–*16* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-16>), especially > with respect to both water availability and quality (*2* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-2>, *4* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-4>, *8* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-8>, *17* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-17>–*21* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-21>). > > > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F1.large.jpg?w…> > > · *Download high-res image* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F1.large.jpg?d…> > > · *Open in new tab* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F1.large.jpg> > > · *Download Powerpoint* > <http://advances.sciencemag.org/highwire/powerpoint/206438> > > *Fig. 1**Map of water stress and shale plays.* > > (*A*) Map showing the global water stress overlaid with shale formations > across the world. (*B*) Water stress and shale regions in the United > States examined in this study (*5* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-5>, *10* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-10>). > > > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F2.large.jpg?w…> > > · *Download high-res image* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F2.large.jpg?d…> > > · *Open in new tab* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F2.large.jpg> > > · *Download Powerpoint* > <http://advances.sciencemag.org/highwire/powerpoint/206491> > > *Fig. 2**Box plots of water use with lateral lengths.* > > Water use per well data (cubic meter per well; left *y* axis) for shale > gas (*top row*) and tight oil regions (*bottom row*) with median lateral > lengths per well (meter per well; right *y* axis) for each region plotted > as colored lines. The central line of each box is the median, while the top > and bottom of each box represent the third and first quartile, > respectively. Whiskers on the box plot represent maximum and minimum > values, while circles above the box plots show outliers in the data. > Whiskers on the colored lateral length lines show the 95% bootstrap > confidence intervals. > > The process of hydraulic fracturing uses large volumes of water mixed with > chemicals and proppant (sand) to fracture and hold open fractures in > low-permeability shale and tight oil rocks to allow extraction of > hydrocarbons. Despite higher water intensity (the amount of water used to > produce a unit of energy; for example, liters per gigajoules) of hydraulic > fracturing compared to conventional vertical oil and gas wells, it has been > shown that the overall water withdrawal for hydraulic fracturing is > negligible compared to other industrial water uses on a national level ( > *6* <http://advances.sciencemag.org/content/4/8/eaar5982#ref-6>, *7* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-7>, *22* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-22>, *23* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-23>). On a local > scale, however, water use for hydraulic fracturing can cause conflicts over > water availability, especially in arid regions such as western United > States, where water supplies are limited (*2* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-2>, *20* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-20>, *24* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-24>, *25* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-25>). > > The wastewater generated from hydraulic fracturing is composed of a blend > of returned injected hydraulic fracturing water and typically high saline > formation water that flows back out of the well after hydraulic fracturing > to generate flowback and produced (FP) waters. Over time, the contribution > of the saline formation water increases, which results in an increase in > the salinity of the FP water. The salts, toxic elements, organic matter, > and naturally occurring radioactive material in the FP water pose > contamination risks to local ecosystems from spills (*14* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-14>, *26* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-26>) and > mismanagement (*6* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-6>, *27* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-27>–*29* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-29>). In > addition to these risks, treatment of the FP water to safely return and > release to the environment is energy-intensive and expensive; thus, many > operators are forced to either recycle the FP water onsite for future > hydraulic fracturing operations or reinject it into deep-injection wells. > > Current technological limitations to the efficiency of hydraulic > fracturing include a rapid decrease (20 to 50% of total production after > the first year) in unconventional gas and oil production through time after > initial production, and the fact that a significant portion of the gas in > the shale formations is left unproduced (*22* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-22>, *30* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-30>). Despite > these limitations, advancements in hydraulic fracturing and horizontal > drilling technology have increased production of gas and oil from shale > regions; between 2007 and 2016, the shale gas production has increased by > eightfold in the United States (*1* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-1>). Two recent > studies have suggested that intensification of the hydraulic fracturing > process through drilling longer horizontal laterals has resulted in > increased water use and hydrocarbon production (*20* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-20>, *25* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-25>). Given the > relatively long history of hydraulic fracturing in United States, > understanding how the water footprint of hydraulic fracturing has evolved > through time with technological advancements and shifting economic > conditions is critical (*22* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-22>, *23* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-23>). Lessons > learned from U.S. production development can directly influence planning > and implementation of hydraulic fracturing practices, as other countries > such as China bring their natural gas reserves online. > > For the first time, this study presents systematic temporal data on water > use, unconventional shale gas and tight oil production rates, and volume of > FP water from major shale-producing regions in the United States. In > addition, we combine several databases to estimate the efficiency of > production from both hydrocarbons and water perspective on a year-by-year > basis, showing that the water footprint of hydraulic fracturing has been > steadily increasing through time. > RESULTS > > In each of the six regions studied in this report, water use per well is > increasing (*Fig. 2* > <http://advances.sciencemag.org/content/4/8/eaar5982#F2> and tables S1 > and S2). The Marcellus region (Pennsylvania and West Virginia) had the > lowest increase in water use (20%), from a median value of 23,400 m3 per > well in 2011 to 27,950 m3 per well in 2016, while the Permian Basin > (Texas and New Mexico) had the largest increase in water use (770%), from > 4900 m3 per well in 2011 up to 42,500 m3 per well in 2016. Median > water-use volumes varied largely among regions, with the Bakken region > using the least water (21,100 m3 per well in 2016) and the Permian basin > using the most water (42,500 m3 per well in 2016). One exception is the > Haynesville region, where water use per well decreased with time (*Fig. 2* > <http://advances.sciencemag.org/content/4/8/eaar5982#F2>). Horizontal > drilling requires producers to drill vertically to a target depth and then > curve the well horizontally through shale formations, maximizing the > surface area producing oil and gas. The length of the portion of the well > that was drilled horizontally is referred to as the lateral length, with > hydraulic fracturing events occurring in stages as a well is drilled > further horizontally. Over the period of 2011–2016, the median length of > lateral section of horizontal wells also increased (tables S1 and S2), most > likely due to technological development and economic considerations to > increase the extraction yields from individual wells. We show below that > the hydrocarbon extraction intensity has similarly increased during this > period. Parallel to the increase in lateral lengths of the horizontal wells > and hydrocarbon extraction yields through time, the water use has also > increased. The relative increase in lateral length (0 to 80%) was, however, > significantly lower than the increase in water use (14 to 770%). There are > two exceptions to this observation: (i) in the Marcellus region, the > increase in lateral length (20%) was equal to the increasing water use > (25%); (ii) oil-producing wells in the Permian basin, where lateral length > increase (79%) and water-use increase (770%) were both higher than those in > the other studied regions. When water use per well is normalized to the > length of lateral section of the horizontal well, in almost every case, we > observed an increase in water use per length of the horizontal well. This > pattern is most evident in the Permian region, where water use increased > from 4.3 m3 per meter in 2011 to 29.0 m3 per meter in 2016 for > gas-producing wells, and from 3.9 m3 per meter in 2011 to 19.0 m3 per > meter in oil-producing wells (tables S1 and S2). The smallest observed > changes were in the Marcellus and Haynesville regions, where water use per > horizontal length has been relatively consistent through time. > > In all cases, the FP water generation was also increasing through time, > with particularly higher rates after 2014 (*Fig. 3* > <http://advances.sciencemag.org/content/4/8/eaar5982#F3> and tables S1 > and S2). Both the gas- and oil-producing portions of the Eagle Ford region > showed large increases through time, with a 610% increase in FP water in > the oil-bearing section (from 2400 m3 per well in 2011 to 16,900 m3per > well in 2015) and a 1440% increase in the gas-bearing section (from 1340 m > 3 per well in 2011 to 20,700 m3 per well in 2015). The smallest increase > in FP water occurred in the Niobrara region, where production increased > from 1800 m3 per well in 2011 to 2300 m3 per well in 2016. > > > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F3.large.jpg?w…> > > · *Download high-res image* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F3.large.jpg?d…> > > · *Open in new tab* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F3.large.jpg> > > · *Download Powerpoint* > <http://advances.sciencemag.org/highwire/powerpoint/206457> > > *Fig. 3**Oil, gas, and FP water variations with time.* > > Annual shale gas (*A*), tight oil (*C*), and FP water (*B* and *D*) > productions in shale gas–producing regions (A and B) and oil-producing > regions (C and D). Whiskers on the bar graphs represent 95% bootstrap > confidence intervals (table S1). > > Coupled with the increase in water use and FP water production rates, > unconventional natural gas production shows an upward trend in production, > with volumes increasing through time among the regions. Year 1 shale gas > production in the Permian region increased from 10.9 × 106 m3 per well in > 2011 to 25.1 × 106 m3 per well in 2016, a 360% increase (*Fig. 3* > <http://advances.sciencemag.org/content/4/8/eaar5982#F3>). Similarly, > year 1 shale gas production in the Marcellus formation increased through > time, from 21.8 × 106 m3 per well in 2011 to 29.0 × 106 m3 per well in > 2015, before falling to 20.8 × 106 m3 per well in 2016. In contrast, in > the Eagle Ford formation, year 1 production remained relatively constant > from 2011 to 2014, before increasing from 2014 to 2015. > > Unconventional oil production shows a consistent increase in year 1 oil > production volume per well through time, with values falling only in the > Eagle Ford region from 2014 to 2015. The largest increase was in the > Permian region, where oil production increased from 8200 m3 per well in > 2011 to 16,700 m3 per well in 2016, a 130% increase (*Fig. 3* > <http://advances.sciencemag.org/content/4/8/eaar5982#F3>). When comparing > our estimate of total year 1 hydrocarbon production (year 1 estimate > multiplied by well count estimate) to total hydrocarbon production reported > by the Energy Information Administration (EIA) (fig. S1) (*31* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-31>), we see > that year 1 production parallels total oil production in most regions in > the United States. > > We define the water-use intensity for hydraulic fracturing as the amount > of water used for hydraulic fracturing to generate a unit of energy from > the produced gas and oil (see Materials and Methods) (*19* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-19>, *23* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-23>, *32* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-32>). In > gas-producing regions, water-use intensity (for the first 12 months of > production) ranges from 7 liters/GJ (Haynesville) to 21 liters/GJ > (Marcellus) in 2011 and grew to between 13.5 liters/GJ (Haynesville) and 33 > liters/GJ (Permian) in 2016 (*Fig. 4* > <http://advances.sciencemag.org/content/4/8/eaar5982#F4> and tables S1 > and S2). Unconventional oil regions also have increasing water-use > intensities, increasing from 11 liters/GJ (Permian) in 2011 to between 28 > liters/GJ (Bakken and Permian) in 2016 and 50 liters/GJ (Eagle Ford) in > 2015. For comparison, the average water intensity of conventional natural > gas is only 4 liters/GJ for drilling and extraction, while coal mining > constitutes a mean value of 43 liters/GJ (fig. S4) (*33* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-33>). Water-use > intensity is also calculated as the ratio between the volume of water used > and the volume of hydrocarbon produced (tables S1 and S2 and fig. S2). The > increase of the water use to hydrocarbon production ratios with time > indicates that the intensification of hydraulic fracturing process to > increase hydrocarbon production rates involves net addition of water, and > thus, the water intensity has increased with time. > > > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F4.large.jpg?w…> > > · *Download high-res image* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F4.large.jpg?d…> > > · *Open in new tab* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F4.large.jpg> > > · *Download Powerpoint* > <http://advances.sciencemag.org/highwire/powerpoint/206464> > > *Fig. 4**The changes in the water intensity of hydraulic fracturing with > time.* > > Water-use intensity variations with time for hydraulic fracturing of shale > gas (*A*) and tight oil (*C*) regions and corresponding FP water/water > use ratios in shale gas (*B*) and tight oil (*D*) regions. Water-use > intensity is defined as the amount of water required to generate a unit of > energy. (A) and (B) show the water-use intensity for shale gas–producing > regions, while (C) and (D) show water-use intensity for unconventional > oil-producing regions. Whiskers represent 95% bootstrap confidence > intervals. > > When comparing the volume of FP water production rates to the water used > for hydraulic fracturing, we show that, in many cases, more water is used > for hydraulic fracturing than returns as FP water over the first year (*Fig. > 4* <http://advances.sciencemag.org/content/4/8/eaar5982#F4>; FP > water/water use ratio < 1). In shale gas–producing regions, we see an > increase in the ratio through time, with the exception of the Permian > region, which increases from 2011 to 2014 but then drops in 2015 and 2016. > The Permian region is also unique as the FP water/water use ratios for both > unconventional oil and gas wells are higher than 1. Unconventional > oil-producing regions have varying trends in the FP water/water use ratio. > Wells in the Eagle Ford oil region have an increasing ratio through time, > while no consistent trend is observed in the Bakken, Permian, and Niobrara > regions (*Fig. 4* <http://advances.sciencemag.org/content/4/8/eaar5982#F4> > and table S2). Regions where the FP water/water use ratios were > increasing through time present a growing water management challenge, as > the net increase (14 to 770%) in the water use (*Fig. 4* > <http://advances.sciencemag.org/content/4/8/eaar5982#F4> and tables S1 > and S2) is coupled with increasing FP water production, growing at even > higher rates (60 to 1440%). This trend exacerbates water management issues > because producers must now manage increasingly large volumes of water for > hydraulic fracturing operations as well as larger oil and gas wastewater > volumes that need to be adequately disposed. > DISCUSSION > > Much of the controversy surrounding hydraulic fracturing revolves around > the use of large volumes of water to hydraulically fracture wells. Concern > is especially high in semiarid regions (*Fig. 1* > <http://advances.sciencemag.org/content/4/8/eaar5982#F1>), where water > withdrawals for hydraulic fracturing can account for a significant portion > of consumptive water use within a given region, even contributing to > groundwater resource depletion (*2* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-2>). Overall, > there have been calls to increase the use of alternative water sources such > as brackish water or recycling FP water, minimizing the strain on local > freshwater resources (*2* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-2>, *25* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-25>). > > Previous studies have suggested that hydraulic fracturing does not use > significantly more water for exploration and production than other energy > sources (fig. S4) and, at the same time, indicated that water use for > hydraulic fracturing makes up only a small fraction of the industrial water > utilization in the United States (*7* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-7>, *22* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-22>, *23* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-23>, *33* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-33>). These > evaluations were based on aggregated water footprint data during the early > years (2011–2014) of hydraulic fracturing in the United States. Here, we > show, however, steadily increasing volumes of water use with time in all > the major unconventional gas and oil regions (*Fig. 2* > <http://advances.sciencemag.org/content/4/8/eaar5982#F2> and tables S1 > and S2). Parallel to the increase of shale gas and tight oil production > intensity, we also show that the water intensity of hydraulic fracturing is > increasing for both unconventional gas and oil regions (*Fig. 4* > <http://advances.sciencemag.org/content/4/8/eaar5982#F4> and tables S3 > and S4). In addition, the water used for hydraulic fracturing is retained > within the shale formation; only a small fraction of the fresh water > injected into the ground returns as flowback water, while the greater > volume of FP water returning to the surface is highly saline, is difficult > to treat, and is often disposed through deep-injection wells. This means > that despite lower water intensity compared to other energy resources (fig. > S4), the permanent loss of water use for hydraulic fracturing from the > hydrosphere could outweigh its relatively lower water intensity. > > The period of 2014–2015 marks a turning point, where water use and FP > water production began to increase at higher rates. During this period, gas > and oil prices dropped significantly, causing producers to scale back the > number of new installed wells (*Fig. 5* > <http://advances.sciencemag.org/content/4/8/eaar5982#F5> and tables S1 > and S2). In each of the oil-producing regions, the water use/oil production > ratio increased, suggesting that the increase in water use for hydraulic > fracturing outpaces the increasing oil production on a per-well basis (*Fig. > 4* <http://advances.sciencemag.org/content/4/8/eaar5982#F4>, fig. S2, and > table S2). In the shale gas–producing regions, this trend is also present, > but not as strongly apparent as with the unconventional oil-producing > regions (*Fig. 4* <http://advances.sciencemag.org/content/4/8/eaar5982#F4>, > fig. S2, and table S1). Consequently, while increasing lateral length of > horizontal drilling and water use for hydraulic fracturing (*Fig. 2* > <http://advances.sciencemag.org/content/4/8/eaar5982#F2>) have resulted > in increasing oil production (per well), the net water-use efficiency, > particularly for unconventional oil production, has decreased (that is, > higher water intensity). > > > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F5.large.jpg?w…> > > · *Download high-res image* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F5.large.jpg?d…> > > · *Open in new tab* > <http://advances.sciencemag.org/content/advances/4/8/eaar5982/F5.large.jpg> > > · *Download Powerpoint* > <http://advances.sciencemag.org/highwire/powerpoint/206471> > > *Fig. 5**New shale gas and tight oil well installations compared to oil > and gas prices.* > > Variations of installed well counts (left *y* axis) and gas and oil > prices (right *y* axis) with time for shale gas–producing regions plotted > with corresponding natural gas citygate price (*top*) and for > oil-producing regions with corresponding crude oil price (*bottom*). The > data show the number of new well installations corresponding closely with > the contemporary gas and oil prices. MCF, thousand cubic feet; BBL, barrel. > > By combining the increasing trends in both water use and FP water > production with the increasing FP water/water use ratios in some regions, > we can see that the overall water footprint of hydraulic fracturing is > increasing through time; more water is being used for hydraulic fracturing > operations, while, at the same time, comparatively more FP water is being > generated. We observed increasing total water use (water use per well > multiplied by well count; fig. S3) in oil-producing regions despite the > recent slowdown in oil production rates (*Fig. 5* > <http://advances.sciencemag.org/content/4/8/eaar5982#F5>). Assuming that > the recent economic downturn eventually subsides and the drilling of new > wells again reaches levels seen during the heyday of hydraulic fracturing > in the early 2010s, the total water impact of hydraulic fracturing is > poised to increase markedly in both shale gas– and oil-producing regions. > On the basis of modeling future hydraulic fracturing operations in the > United States in two scenarios of drilling rates, we project cumulative > water use and FP water volumes to increase by up to 50-fold in > unconventional gas-producing regions and up to 20-fold in unconventional > oil-producing regions from 2018 to 2030, assuming that the growth of water > use matches current growth rates and the drilling of new wells again > matches peak production (fig. S5 and tables S3 and S4). Even if future > drilling rates will stay at 2016 levels (that is, low oil gas prices), we > predict a large increase of the total water use for both unconventional oil > and shale gas basins (fig. S5). Likewise, we predict a large increase in > the FP water volume for the two scenarios, with particularly high total FP > water production in the Permian and Eagle Ford basins (fig. S5). > > The increase in the water footprint of hydraulic fracturing shown in this > study has serious implication for local communities, where increased > drilling volume will lead to large instantaneous water demands, and > resulting in increasing FP water burdens that will have to be managed into > the future. The predicted increasing water use and FP water production in > the Permian and Eagle Ford basins are alarming given the extreme water > scarcity in these regions (*Fig. 1* > <http://advances.sciencemag.org/content/4/8/eaar5982#F1>). The results > presented in this study are consistent with previous studies in the Permian > (*19* <http://advances.sciencemag.org/content/4/8/eaar5982#ref-19>) and > Eagle Ford (*25* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-25>) basins that > have shown that local water resources could be affected by increasing water > demands for hydraulic fracturing. At the same time, other studies have > shown that water use for hydraulic fracturing in water-rich areas such as > the Sichuan basin in China (*8* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-8>, *34* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-34>) will > constitute only a small fraction of the available local water resources. > While the water intensity during early stages of hydraulic fracturing (<30 > liters/GJ in most cases) was comparable and even lower than that of coal > mining (43 liters/GJ; fig. S4), the recent (2014–2017) intensification of > hydraulic fracturing has increased the water intensity, particularly for > unconventional oil (up to 93 liters/GJ; fig. S4). Additional studies are > needed to analyze the local impacts of hydraulic fracturing on water > resource depletion in light of increasing water demand for hydraulic > fracturing and the increasing volumes of FP water that need to be managed, > particularly in areas vulnerable to induced seismicity from injection of > large volumes of oil and gas wastewater. As unconventional gas and oil > exploration is expanding globally and other countries begin to follow the > U.S. shale revolution (for example, China) (*34* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-34>), the > results of this study should be used as a guidance for the expected water > footprint of hydraulic fracturing at different stages of energy development. > MATERIALS AND METHODS > Experimental design > > The goal of this study was to synthesize and collate production volumes > for unconventional gas and oil production, associated FP water, and water > use for hydraulic fracturing per shale gas/oil well. We downloaded > production data for each of these components from the major shale gas and > tight oil regions identified in this study using multiple sources and > separated by year of initial production. Once organized, data were reported > based on the first 12 months of the well lifetime to see how production and > water-use values compared on a year-by-year basis. > Data acquisition > > Production volumes for gas, oil, and FP water for each reporting well in > our target regions were downloaded using the DrillingInfo Desktop > application (*35* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-35>). Data were > downloaded by primary well production type (gas or oil). FP water data (and > natural gas production for 2015–2016) were not available from the Marcellus > region, and thus, data from the Marcellus Formation were downloaded from > the gas and oil reporting website of the Pennsylvania Department of > Environmental Protection (PA DEP) (*36* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-36>). Water-use > data were downloaded from the FracFocus Chemical Disclosure Registry (*37* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-37>). Well > counts from 2014 to 2016 were taken from the EIA Drilling Productivity > Report (DPR) (*31* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-31>), while well > counts from 2012 to 2014 were taken from Baker Hughes’ onshore well counts ( > *38* <http://advances.sciencemag.org/content/4/8/eaar5982#ref-38>). The > well counts provided did not indicate if they were taken from conventional > or unconventional oil-producing wells or in regions producing both gas and > oil, and whether the well was classified as an oil well or gas well. > Consequently, we used DrillingInfo to find the ratio of conventional to > unconventional wells and the ratio of oil to gas wells for each region for > each year and multiplied that by the number of wells reported by Baker > Hughes and in the DPR. In addition, wells drilled in the Bakken formation > were not reported by the Baker Hughes report. As a result, Bakken Formation > well counts from 2011 to 2013 were taken from the North Dakota Oil and Gas > Division (*39* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-39>). Combining > data from several resources can introduce bias and error into results using > these values. Values reported in this study were found to be comparable to > those reported in previous studies. Natural gas and oil historical prices > were taken from the EIA (*1* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-1>). > Statistical methods > > Data from over 12,000 individual wells were organized by producing region, > American Petroleum Institute (API) number, first production year, and month > since first production. Data were sorted by first production year and then > aligned within each year by month since first production. The median values > among all API numbers reporting data within a given year were calculated > for each month since production began (*22* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-22>, *23* > <http://advances.sciencemag.org/content/4/8/eaar5982#ref-23>). A similar > analysis was done with the PA DEP Marcellus data. Finally, areas where less > than 0.5% of data are reported (number of DrillingInfo reports/well count < > 0.5%) were removed from the data set. This removed DrillingInfo data for > the Haynesville formation from 2015 and 2016, the Eagle Ford gas- and > oil-producing regions from 2016, and the Marcellus formation from 2015 to > 2016. Marcellus data from 2015 to 2016 were replaced with data from PA DEP. > The region for each water-use data point was determined spatially using the > latitude and longitude provided by FracFocus to locate points within > unconventional gas and oil plays (shapefile provided by the U.S. EIA) ( > *31* <http://advances.sciencemag.org/content/4/8/eaar5982#ref-31>). > Water-use data were then sorted by region, and the median water-use value > was calculated for each spud year. > > Energy intensities were calculated by converting production volumes of gas > and oil to energy production using their energy content. Energy content for > natural gas was assumed to be 0.038 and 38.18 GJ/m3 >

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New fracking wells are using hundreds of times more water than their predecessors
by William V. DePaulo, Esq. via EC 15 Aug '18

15 Aug '18

https://www.popsci.com/fracking-fresh-water New fracking wells are using hundreds of times more water than their predecessors The change between 2011 and 2018 is stark. By Kat Eschner <https://www.popsci.com/authors/kat-eschner> 1 hour ago [image: water flowing over rocks] Fresh water is important to life, and industries. EcoPic <https://depositphotos.com/4563348/stock-photo-flowing-water.html> Over the last few years, fracking operations have gotten more efficient at removing oil and natural gas from the ground—this according to a new study <http://advances.sciencemag.org/content/4/8/eaar5982> published today in the journal Science Advances. That’s good news for the fossil fuels industry, which is getting more than ever out of a given well—but might be bad news for fresh water. The story isn’t the same everywhere. Ever since oil and gas prices decreased in 2014, the number of fracking wells being drilled annually across the country has gone down. But the size and output of the new wells that are being drilled has increased dramatically, because of a method known as horizontal drilling that maximizes the amount of surface area underground for the oil to flow through. Another thing has skyrocketed: the amount of water used in each well. In some places, says study author Avner Vengosh, “this net increase per well caused overall increase” in water usage for fracking in regions where it is practiced. The increase was as much as a whopping 770 percent in the Permian region of West Texas. There, for gas-producing wells, water use went from from about 350 gallons per foot of well in 2011 to 2335 gallons per foot of well in 2016. But in others, such as the Marcellus region of Pennsylvania and West Virginia, the amount of water used overall for fracking stayed about the same even though wells got bigger, because there were fewer of them. The early numbers come from a paper Vengosh and others at Duke published <https://pubs.acs.org/doi/abs/10.1021/acs.estlett.5b00211> in 2015. That study established a baseline, says Vengosh–but when graduate student Andrew Kondash, the new paper’s first author, started looking at the water figures for 2015-2016, the numbers were much, much higher. This led the team to doubt their original data, Vengosh says. But some more work revealed that it was true—water use per well had gone up substantially, even as the number of wells dropped. To figure this out, Kondash looked at water usage data for six major shale deposits across the country. They evaluated how many wells had been drilled, how much water was used in each, and how much wastewater was produced. The totals here represent fracking’s “water footprint”–the fresh water that needs to go in for fracking to take place, and the water mixed with chemicals, sand and—sometimes <https://pubs.acs.org/doi/abs/10.1021/es402165b?journalCode=esthag>—radioactive isotopes that seeps out with the natural gas or oil. “It has been shown that the overall water withdrawal for hydraulic fracturing is negligible compared to other industrial water uses on a national level,” the study reads. Total industrial use is estimated <https://pubs.usgs.gov/circ/1441/circ1441.pdf> at almost 15 million gallons of water per day, for uses ranging from auto manufacturing to mining. “On a local scale, however, water use for [fracking] can cause conflicts over water availability, especially in arid regions such as western United States, where water supplies are limited.” Freshwater availability might be the limiting factor of fuel extraction in the Permian Basin of West Texas, says Vengosh. The oilfields there are predicted <https://www.houstonchronicle.com/business/energy/article/Permian-will-outpa…> to produce historic amounts of crude oil in the next few years—but without the freshwater to do it via fracking, says Vengosh, that wouldn’t be possible. “The water use is part of the system that cannot be mitigated in any way,” he says. The demand for fresh water could promote innovation in fracking technologies. “In many places, the amount of water that’s recycled has gone up” in recent years, says McGill University’s civil engineer Mary Kang, who studies groundwater and fracking. Kang was not involved in the current project. It’s possible that innovation might make water recycling more efficient, says Vangosh. The increased water use means there’s the other factor, he says. “Now they need to deal with a much larger volume of wastewater.” A current common way to deal with it is to pump it into deep wastewater wells, rather than recycling it. That deals with the immediate problem for each individual well, but little is known about the long-term effects. Wastewater injection wells have been linked to increasing numbers of earthquakes <https://www.popsci.com/wastewater-injection-oklahoma-earthquake> in Oklahoma. “Water is not just some uniform resource,” says Kang. Water accessibility and quality are highly variable between locations—and there are parts of the water supply we still don’t really understand yet, like the deep groundwater that she studies. This new study gives everyone from industry to environmentalists a new baseline for figuring out how much water will be used in fracking, and is likely to prompt at least some to reevaluate their water budgets. But the grand total left in those water budgets, and the speed at which they’ll be consumed still remains to be seen. 860 Court Street, North Suite 300 Lewisburg, WV 24901 Tel 304-342-5588 Fax 866-850-1501 william.depaulo(a)gmail.com

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MANCHIN, CAPITO AND McKINNEY ASK FERC TO REISSUE PERMITS FOR ACP AND MVP
by William V. DePaulo, Esq. via EC 14 Aug '18

14 Aug '18

https://www.wvgazettemail.com/news/politics/manchin-capito-mckinley-weigh-i… Manchin, Capito, McKinley weigh in on stopped pipelines - By Kate Mishkin Staff writer <https://www.wvgazettemail.com/users/profile/Kate%20Mishkin> - 2 hrs ago - (0) <https://www.wvgazettemail.com/news/politics/manchin-capito-mckinley-weigh-i…> Three members of West Virginia's congressional delegation have weighed in on two controversial natural gas pipelines, urging federal regulators to keep building them. In a letter dated Monday <https://www.documentcloud.org/documents/4757076-Manchin-Capito-McKinley-Pip…>, Sens. Joe Manchin, D-W.Va., Shelley Moore Capito, R-W.Va., and Rep. David McKinley, R-W.Va. urged the Federal Energy Regulatory Commission to allow construction to resume on the Atlantic Coast Pipeline and Mountain Valley Pipeline as quickly as possible. Construction on both natural gas pipelines was recently halted after the 4th Circuit Court of Appeals ruled that various federal agencies had skirted environmental protections when they approved the projects. FERC issued a stop work order on the Mountain Valley Pipeline late on Aug. 3, and then ordered a halt to the Atlantic Coast Pipeline exactly one week later, on Aug. 10. Environmental and citizen groups called the decision to stop work on both pipelines, at least until federal agencies can issue new permits and resolve the environmental problems, a victory. But in their letter, the lawmakers focused on the jobs and tax revenue that's now on hold. "We write to bring our concerns to your attention, as well as to encourage FERC and the relevant permitting agencies to quickly reconsider, correct and reissue the necessary permits for these projects," they wrote. None of the lawmakers responded to an interview request Tuesday, though. Reps. Alex Mooney and Evan Jenkins didn't sign the letter but their constituents have written to FERC about the pipelines. Mooney wasn't available for a comment, but a spokeswoman for Jenkins responded in an email. "I understand that many people have concerns about these pipelines, but I am confident that FERC and the pipeline developers will find an environmentally-friendly way to move these projects forward in a manner that is fair to landowners.” Jenkins said through a spokeswoman. Gov. Jim Justice, who, in June, said he'd "determine what role the state may play in expediting the construction" of the Mountain Valley Pipeline, also did not respond to a request for comment. Both pipelines will cross all three congressional districts -- the 300-mile-long Mountain Valley Pipeline from Wetzel County, West Virginia to Pittsylvania County, Virginia, and the 600-mile-long Atlantic Coast Pipeline from Harrison County, West Virginia to eastern North Carolina. In the letter, the lawmakers pointed to natural gas as a solution to the state's economic challenges. "We strongly encourage you to work with the permitting agencies in question to resolve the outstanding issues as quickly as possible in a manner that allows for re-issuance of these permits and recommencement of construction," the letter says. "We also ask that you consider amending or lifting the stop work orders on these projects to ensure that the shortest possible portions of the proposed routes are affected by these delays." FERC tapped the brakes on the Mountain Valley Pipeline <https://www.documentcloud.org/documents/4757123-FERC-MVP-Stop-Work-Order.ht…> after an appeals court vacated the Bureau of Land Management’s decision to grant a right of way and the U.S. Forest Service’s decision to allow a right of way and construction through the Jefferson National Forest. In the unanimous decision, Judge Stephanie Thacker wrote that American citizens put their faith in the Forest Service "to protect and preserve this country's forests, and they deserve more than silent acquiescence to a pipeline company's justification for upending large swaths of national forestlands." Then, the appeals court issued an order pulling a right-of-way permit for the National Park Service that authorized construction of the Atlantic Coast Pipeline <https://www.documentcloud.org/documents/4742097-FERC-ACP-stop-work-order.ht…> across the Blue Ridge Parkway and issued a longer explanation for its May 15 decision to pull the U.S. Fish and Wildlife's Incidental Take Statement for the pipeline. On Friday, FERC issued an order stopping that pipeline, too. Per FERC's order, Mountain Valley Pipeline has submitted a 16-page temporary stabilization plan that suggests, among other things, that pipe should be lowered into the ground to avoid UV exposure. The Atlantic Coast Pipeline hasn't yet submitted its stabilization plan. Reach Kate Mishkin at kate.mishkin(a)wvgazettemail.com, 304-348-4843 or follow @katemishkin on Twitter.

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Pipeline Security has become unreasonable or worse
by Duane Nichols via EC 04 Aug '18

04 Aug '18

Here’s local press on the Gerhart hearing. That is one traumatized family: http://www.altoonamirror.com/news/local-news/2018/08/pipeline-foe-gets-mont…

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Federal agency orders work to stop on Mountain Valley Pipeline
by Duane Nichols via EC 03 Aug '18

03 Aug '18

https://www.roanoke.com/news/local/ferc-orders-work-to-stop-on-mountain-val… In a letter to pipeline officials, the Federal Energy Regulatory Commission cited an appeals court decision last week that reversed earlier-granted approvals for pipeline work in the Jefferson National Forest. With work on that 3.6-mile segment of the pipeline now on hold, FERC determined that construction of the rest of the 303-mile project should not proceed.

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FERC STOP WORK ORDER TO MVP ATT'D
by William V. DePaulo, Esq. via EC 03 Aug '18

03 Aug '18

FERC STOP WORK ORDER TO MVP ATT'D QUOTE: *MVP is hereby notified that construction activity along all portions of the Project and in all work areas must cease immediately, with the exception of any measures deemed necessary by those land managing agencies or FERC staff to ensure the stabilization of the right of way and work areas. * William V. DePaulo, Esq. 860 Court Street, North Suite 300 Lewisburg, WV 24901 Tel 304-342-5588 Fax 866-850-1501 william.depaulo(a)gmail.com

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