Totten Shale Gas Hydraulic Fracturing - Fracking Issues Challenges White Paper 12-05-2013 200 PPT

WHITE PAPER SHALE GAS HYDRAULIC FRACTURING (FRACKING) ISSUES & CHALLENGES

Michael P To-en, Principal

AssetsforLife.net December 05, 2013

SecAons

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Trillion cubic feet, TCF

IMPORTS

EXPORTS

Shale gas 800% Rise in 12 years as Natural Gas prices steeply decline

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36,000 Shale Wells in US in 2012

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P. O Box 470157

Fort Worth, Texas USA 76157-0157 Office: (817) 210-6292 Fax: (817) 231-0707

www.shaledigest.com

1 Powell Shale Digest Special Edition International Journalists Aug 13 2012

August 13, 2012

SHALE PRODUCERS IN U.S. TOP 35,000 WELLS, 23 TCF GAS & 682 MMBO The Powell Shale Digest© was requested by one of the largest shale operating companies in the U.S. to answer a request

from a newspaper in Paris, France. They desired to know the number of shale gas and oil producers in the United States. We

estimated 40,000 wells. Our final research numbers were 35,996 producers, 22,970,801,142 MCF gas + 682,073,803 BO/BC.

Subsequently, we totaled our last research of the major shale plays in the United States and below is our summary.

SHALE PRODUCERS IN U.S. MAJOR SHALE PLAYS

SHALE NAME STATE AGE YRS.

NO. WELLS

BEGAN MO/YR

LAST PROD

RESEARCH MO/YR

CUM GAS MCF

CUM OIL BO/BC

BARNETT SHALE TX 30.0 17,980 Jun-82 May-12 11,922,273,082 39,444,928 FAYETTEVILLE SHALE AR 7.75 3,730 Mar-04 Nov-11 2,512,089,052 - HAYNESVILLE SHALE LA 4.3 1,402 Jan-08 Apr-12 4,086,232,822 282,151 HAYNESVILLE SHALE TX 6.25 797 Mar-06 May-12 1,700,959,291 350,099 EAGLE FORD SHALE TX 6.4 3,597 Dec-05 May-12 622,433,431 120,582,966 BAKKEN/THREE FORKS SHALE ND 26.3 3,777 Mar-86 Jun-12 366,805,083 390,030,044 BAKKEN/THREE FORKS SHALE MT 26.4 886 Jan-86 Jun-12 107,666,762 128,981,402 MARCELLUS SHALE PA 2.4 2,312 Jul-09 Dec-11 1,530,087,438 2,070,715 MARCELLUS SHALE WV 5.9 1,515 Jan-05 Dec-10 122,254,181 331,498

TOTALS 35,996 22,970,801,142 682,073,803

Data Source: State Regulatory Agencies

August 13, 2012

Powell Shale Digest, Special EdiAon, InternaAonal Journalists, Aug 13 2012

Does not include the UAca Shale. The Marcellus figures are more dated than for the other shale plays due to lagging reporAng by Pennsylvania and West Virginia regulators.

Coal declined 11% in 5 years, Natural Gas increased 10% -‐-‐ with cost & emission savings

7 UCS, Gas Ceiling, Assessing the Climate Risks of an Overreliance on Natural Gas for Electricity, Sept. 2013, Union of Concerned ScienAsts.

Shale FormaAons Immense

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Map of basins with assessed shale oil & shale gas formaKons, as of May 2013

PGC Resource Assessments, 1990-2012

Data source: Potential Gas Committee (2013)

Total Potential Gas Resources (Mean Values)

PotenKal Gas Agency, PotenKal Supply of Natural Gas in the United States, Report of the PotenKal Gas CommiQee (December 31, 2012)

Shale gas producAon in North America A bullish view in LATE 2009 to 2040

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15 TCF

Kenneth B Medlock III, “Barne- Shale SAll has lots of life”, June 11, 2011, Baker InsAtute Energy Forum, slide presented at the Dallas Federal Reserve Bank in 2009, h-p://fuelfix.com/blog/2011/06/27/barne--‐shale-‐sAll-‐has-‐lots-‐of-‐life/

Shale gas producAon in North America Super-‐bullish view by EARLY 2011 to 2040

10 Kenneth B Medlock III, “Barne- Shale SAll has lots of life”, June 11, 2011, Baker InsAtute Energy Forum, slide presented at the American AssociaAon of Petroleum Engineers AAPG, 2011, h-p://fuelfix.com/blog/2011/06/27/barne--‐shale-‐sAll-‐has-‐lots-‐of-‐life/

20 TCF

EXXONMobile Natural Gas Global & North America SUPPLY PerspecAve to 2040

11 Source: ExxonMobile, Energy Outlook, 2013, h-p://www.exxonmobil.com/Corporate/energy_outlook_datacenter_eo13gassupply.aspx

3 basic steps in HF Process

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Establish the Pad: Inject hydraulic fluid, without propping agent (proppant), into target formaAon

Pumped at about 100 barrels per minute; Pressure: around 14,000 psi Pressure tests conducted to check for leakage into neighboring formaAons

Add propping agent “proppant” Proppant—sand, ceramics, wire mesh, sintered bauxite Proppant carried into fractures—designed to hold the fractures open for flow

Flush the reservoir 20-‐50% return—although anecdotal data from industry says 80% or more

Produce the gas normally thereamer. ProducAve for 1-‐2 years. Geometric decline over Ame. Total amount of fracking fluid use per well in the Marcellus: 1-‐5 million gallons

Key Points – PUBLIC Opinion 1. Public opinion surveys show diverse perspecAves. 2. Nov 2013 survey finds half the public know li-le about fracking 3. Several 2013 surveys find more people are negaAve towards fracking by two to one margin

4. NegaAve aotudes driven by toxic legacy of fossil industry plus lax or absent regulatory standards and enforcement for ensuring no impacts on air, water, land, human health and well-‐being

5. NegaAve aotudes driven by uneven quality of industry pracAces leading to local impacts

6. Public divided over fracking risks/threats and promises (e.g., cleaner than coal, low cost fuel, tax revenue base, security)

7. Social jusAce concerns of economic winners vs losers 13

Public Opinion Surveys Californians Wary of Fracking

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Californians Wary of Fracking, poll says September 26, 2013, By Chris Megerian 61% of likely voters said they favor stricter rules, and 53% said they're against the expansion of fracking in the state. Californians want stricter regulaAon of hydraulic fracturing, the controversial method of oil and natural gas extracAon, according to a new poll from the Public Policy InsAtute of California. In addiAon, a majority of likely voters surveyed opposed the increased use of fracking, which involves injecAng water and chemicals into the ground to remove the resources locked underneath. The issue is gaining increased a-enAon in California because energy companies are eyeing an esAmated 15 billion barrels of oil in the massive Monterey Shale rock formaAon.

Public Opinion Surveys Pennsylvania

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Public Opinion Surveys New York

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Poll: Fracking opposiKon at an all-‐Kme high in NY September 30, 2013, By Jon Campbell The gap between opponents and supporters of hydraulic fracturing has grown to an all-‐Ame high in New York, according to a new poll. The Siena College survey released Monday shows 45 percent of New York voters do not support allowing high-‐volume fracking in the state, compared to 37 percent who do. 18% had no opinion or not enough informaAon to formulate one. The gap is even larger upstate, where 52 percent oppose fracking and 34 percent are in favor of it. The gas-‐rich Marcellus Shale formaAon, which spans several states in the Northeast and Mid-‐AtlanAc, stretches across New York's Southern Tier. “A majority of upstaters and Democrats, and a plurality of independents and New York City voters oppose fracking, which is supported by a plurality of Republicans and downstate suburbanites," Greenberg said.

Public Opinion Surveys United States

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Support for regulaAon of hydraulic fracturing has increased in the past three months, a sign that the gas-‐drilling pracAce is facing greater public scruAny. A Bloomberg NaAonal Poll found that 66 percent of Americans want more government oversight of the process, known as fracking, in which water, chemicals and sand are shot underground to free gas trapped in rock. That’s an increase from 56 percent in a September poll. The poll found 18 percent favored less regulaAon, down from 29 percent three months ago. “More people are aware of fracking, and they are a li-le bit more opposed to it,” Sheril Kirshenbaum, director of the University of Texas Energy Poll, said in an interview. The school’s polls also have asked quesAons on the topic, and “it’s becoming more familiar,” she said.

Public Opinion Surveys U of Texas Poll Shows Divide on Fracking

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Worries about Boom & Bust Cycles

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Evidence suggesAng cauAon in projecAng long term economic development from natural gas drilling comes from a study of 26 counAes in western US states that have based their economic development on the extracAon of fossil fuels (natural gas, oil, and coal).

This study shows that these counAes (that have at least 7% of their total jobs in resource extracAon industries) have not performed as well as similar counAes without extracAon industries.

Both their average annual growth in personal income and their employment growth (1990–2005) were lower than their peer counAes without extracAon industries.

Concerns about Boom & Bust Cycles

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These energy-‐dependent county economies exhibited a set of similar characterisAcs. They had: •  Less economic diversity •  Lower levels of educaAonal

a-ainment •  More income inequality between

households •  Less ability to a-ract investment.

natural gas, and in a 2008 report withLash, he estimated that perhaps 10 percent of that gas (50 tcf ) might berecoverable.13 The following year, heestimated that recoverable reserves couldbe as high as 489 tcf.14 More recentestimates of recoverable gas fall in the200-300 tcf range. From a geologist’sperspective, extraction of these totalrecoverable reserves could take decades.

Another perspective on the pace andscale of drilling looks at what are thelikely firm strategies in response to theirprofit opportunities in particular shaleplays and among potential extraction sites.For example, given a limited number ofdrilling rigs, they will be deployed in thoseplaces (within a gas play or across gasplays) where profits are most likely. Thequestion for an energy company is notwhether a well is viable in terms ofpotentially recoverable gas, but whether itis commercially viable — that is, will itmake money for the operator (the owner

of the mineral rights) and the drillingcompanies. An understanding of thechoices made by operators and theirsubcontractors in a shale play requires ananalysis of the costs and delivery rates ofdrilling operations, margins of commercialprofitability, and corporate financial andcompetitive relationships.

Production in shale plays isunpredictable and only a small number ofwells may be able to produce commercialvolumes of gas over time withoutre-fracking, which is very costly. Evidencefrom the Barnett and Haynesville shaleplays in the USA, for example, indicatesthat high initial production rates may dropoff rapidly, making it difficult for operatingcompanies to cover their finding anddevelopment costs. Industry investmentadvisors are cautious about the long-termproductivity of the US natural gas plays.Their advice to investors is simple: ‘Shaleproduction is characterised by a steepdecline curve early in its productive life.

! Henry Stewart Publications 1756-9538 (2012) Vol. 2, 4, 000–000 Journal of Town & City Management 7

How shale gas extraction affects drilling localities

Amou

nts

gene

rate

d

Time (whether over months or years)

The pattern of the Boom-Bust cycle in royalties, business income, �tax revenues and jobs�

(green line)

Adapted from Tim Kelsey (2011), 'Annual Royalties in a Community'.

Figure 3:AQ2

Also, a majority of the energy industry focused counAes (16 of the 26) lost populaAon during this period. Though the reasons for this loss are not fully documented, anecdotal informaAon suggests that they may include the higher cost of living in these counAes and the displacement of residents who do not want to live in an industrialized landscape — for example, reArees.

Susan Christopherson and Ned Rightor, How shale gas extracAon affects drilling localiAes: Lessons for regional and city policy makers, Journal of Town and City Management, vol. 2, no. 4, 2012

Dealing w/ Boom & Bust Cycles

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All this suggests to local governments three crucial elements of preparaAon:

1. The need for baseline data. Without the baseline data on roads, water treatment, rents, traffic, use of government equipment, etc., local governments cannot hold the well operators or their subcontractors accountable for the increased cost to local services that their acAviAes generate, nor can they make a good case for relief from the state.

2. The need for a dedicated revenue stream from gas producKon.

3. The need to budget for future costs. Just as the unfolding of demands on localiAes from the effects of shale gas development may not correspond to the flow of tax revenue from gas producAon or lease/royalty payments to landowners, so the effects of shale gas exploraAon may last far longer than the boom in drilling acAvity in any given locality. Lowering property taxes during the revenue boom may only lead to raising them even more when the full effects on local government operaAons are realized. Be-er to uAlize the variety of budgeAng instruments — fiscal impact fees, trust funds, capital reserve funds and a healthy fund balance — designed to stabilize the tax rate by seong aside monies to defray future costs.

Susan Christopherson and Ned Rightor, How shale gas extracAon affects drilling localiAes: Lessons for regional and city policy makers, Journal of Town and City Management, vol. 2, no. 4, 2012

Public Distrust Reasonable Cause or Uninformed Fear?

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“The oil and gas industry is the only industry in the U.S. that is allowed by the

EPA to ‘inject hazardous materials-‐unchecked’ directly into or adjacent to underground drinking water supplies.”

CEH, Toxics & Dirty Secrets

The Frackers’ Well-‐Oiled PoliAcal Machine, Mother Jones, Dec. 2012, h-p://www.motherjones.com/environment/2012/10/fracking-‐companies-‐drilling-‐poliAcal-‐influence-‐charts

h-p://ceh.org/

Key Points – SCIENCE Evidence

•  In theory, range of impact issues all resolvable (water use, waste, contaminaAon, GHG emissions, air polluAon, land use)

•  In pracAce, range of impact issues not being addressed transparently, rapidly, sufficiently, comprehensively with eye towards cumulaAve long-‐term consequences

•  Complexity of issues allows for respected experts to argue for expansion and for ban

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EDF/UT find emissions rate 0.42% in “Green CompleAon” gas wells

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EDF UT-‐AusAn found fugiAve methane emissions rates at a scant .42-‐percent, far lower than the NOAA/University of Colorado study and 2-‐4% lower than the Howarth et al Cornell study. the EDF/UT-‐AusAn study focused on well compleAon sites the industry calls green compleAons -‐-‐ a process in which impuriAes such as sand, drilling debris, and fluids from hydraulic fracturing are filtered out and the gas is sold, not wasted. EPA will not mandate green compleAons unAl 2015, so they are not representaAve of the industry's performance at the moment. The study is based only on evaluaAon of sites and Ames chosen by industry, and reflects the leading or best actors, NOT the super-‐emi-ers.

David T. Allen et al., “Measurements of methane emissions at natural gas producAon sites in the United States,” Proc Natl Acad Sci USA, 44, October 29, 2013.

Methane emissions double what EPA esAmates

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November 2013 study found GHG emissions from “fossil fuel extracAon and processing (i.e., oil and/or natural gas) are likely a factor of two or greater than cited in exisAng studies.” In parAcular, they concluded, “regional [(e.g., Texas, Oklahoma] methane emissions due to fossil fuel extracAon and processing could be 4.9 ± 2.6 Ames larger than in EDGAR, the most comprehensive global methane inventory.” This suggests the methane leakage rate from natural gas producAon, which EPA recently decreased to about 1.5% is in fact 3% or higher.

Joe, Romm, Bridge Out: Bombshell Study Finds Methane Emissions From Natural Gas ProducAon Far Higher Than EPA EsAmates, ClimateProgress, November 25, 2013, ciAng Sco- Miller et al, Anthropogenic emissions of methane in the United States, Proceedings of the NaAonal Academy of Sciences USA, November 25, 2013, 0.1073/pnas.1314392110

3 NOAA studies find higher leakage rates of methane emissions

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NOAA researchers found in 2012 that natural-‐gas producers in the Denver area “are losing about 4% of their gas to the atmosphere — not including addiAonal losses in the pipeline and distribuAon system.”

Air sampling by NOAA over Colorado Finds 4% Methane Leakage, More Than 2X Industry Claims

Petron, G., et al. (2012), Hydrocarbon emissions characterizaAon in the Colorado Front Range -‐ A pilot study, J. Geophys. Res., doi:10.1029/2011JD016360


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A 2013 study by NOAA found leaks from oil and gas exploraAon and extracAon in the L.A. basin represenAng “about 17% of the natural gas produced in the region, similar to the leak rate esAmated by the California Air Resources Board using other methods.”

Almost all the gas produced in the basin is “associated” with oil producAon (rather than, say, fracked).

Associated gas is sAll about a fimh of total U.S. gas producAon.

The NOAA WP-‐3D research aircrac flies along the San Gabriel mountains in the Los Angeles basin during the CalNex experiment in summer 2010. The aircrac is much like a "flying chemical laboratory," containing specialized instrumentaKon that can help scienKsts beQer understand air quality and climate change.

Peischl, J. et al., QuanAfying sources of methane using light alkanes in the Los Angeles basin, California, J. Geophys. Res. Atmos., doi:10.1002/jgrd.50413, 2013.

6 to 12% methane emissions leakage rate in Uintah County shale gas producKon

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Eleven flyovers across well producAon sites in an enAre shale gas basin in Utah determined the rate of methane emissions in Uintah County to be 6 to 12 percent of the average hourly natural gas producAon during the month of February 2012.

This emissions esAmate is 1.8 to 38 Ames inventory-‐based esAmates from this region and five Ames the US EPA naAonwide average esAmate of leakage from the producAon and processing of natural gas.

Although the emissions for Uintah reported here may not be representaAve of other natural gas fields, this study demonstrates the importance of verifying emissions from natural gas producAon to enable an accurate assessment of its overall climate impact.

Karion, A., et al. (2013), Methane emissions esAmate from airborne measurements over a western United States natural gas field, Geophys. Res. Le-., 40, 4393–4397, doi:10.1002/grl.50811.


Failsafe Fracking – feasible?

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TOWARD AN EVIDENCE-BASED FRACKING DEBATE

Science, Democracy, and Community Right to Know in Unconventional Oil and Gas Development

The Center for Science and Democracy at the Union of Concerned Scientists

Science-‐driven, evidence-‐based, empirical tesAng, monitoring and evaluaAon is essenAal to help: •  Illuminate the issues •  Transparently discuss all

dimensions •  Promote innovaAve soluAons •  Research be-er pracAces •  Inform poliAcal debate •  Guide consensus building

process

Key Points – POLITICAL Response •  Federal & most States Bullish on economic gains and tax revenue base, Local govts. mixed

•  PreferenAal treatment to fossil fuels & fracking industry in subsidies and incenAves

•  PreferenAal treatment in exempAng from compliance of 8 federal environmental laws

•  PreferenAal treatment in ignoring long-‐term, cumulaAve impacts on air, water, land use

•  Laissez-‐faire approach (e.g., industry self-‐policing, state-‐based regulatory decisions)

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US House of RepresentaAves legislates to accelerate fracking – Nov 2013

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Two House bills passed: one, to reduce federal "red tape" and cut down on "frivolous lawsuits that act as stumbling blocks to job creaAon & energy development” was approved by a vote of 228-‐192. President Barack Obama promised to veto the bills, saying they are unnecessary and run counter to protecAons put in place for oil and gas drilling.

The other bill deems a drilling applicaAon approved if no decision is made within 60 days, set a minimum threshold for lands leased by the BLM, charge a $5,000 fee to groups that protest lease permits, and restrict the Interior Department from enforcing proposed rules to regulate fracking on public lands. Ma-hew Daly, House Approves bill to speed up oil and gas drilling, Huffington Post, Nov 20, 2013, h-p://www.huffingtonpost.com/2013/11/20/house-‐oil-‐and-‐gas-‐bill_n_4312118.html?utm_hp_ref=green

HR1965, Federal Lands Jobs and Energy Security Act; HR2728, ProtecAng States’ Rights to Promote American Energy Security Act

Skewed government subsidies, and ignoring monetary externaliAes

burdened on taxpayers & ratepayers

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Fossil fuels receive preferenAal tax and fiscal policies that result in accruing more than half a trillion dollars per year in the USA, and nearly $2 trillion worldwide, according to IMF assessments.

Social Cost of carbon "Report: Damages From Each Gigaton Of Carbon

Pollu@on May Exceed $950 billion a year "

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A recent analysis of the social cost of carbon (SCC) — the total economic damage done by GHG polluAon — finds official govt. esAmates are dangerously low.

Using a range of more credible numbers for the physics of climate change and differing economic discount rates, find that the SCC lies between $30 and $956 per ton, and will rise in 2050 to between $69 and $1,660 a ton (in 2013$).

Frank Ackerman and Elizabeth Stanton , Climate Risks and Carbon Prices, Economics for Equity and Environment Network report, July 2011

The AdministraAon, in federal guidance, esAmates SCC to be $36 per ton CO2 emissions, about $0.25 per gallon of gasoline, and roughly 4 cents per kWh polluAon fee on coal-‐fired electricity and 2¢/kWh on natural gas-‐fired electricity.

Social Cost of Carbon

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"Shell Oil Self-‐Imposes Carbon Pollu@on Tax High Enough To Crash Coal, Erase Natural Gas’s Value-‐Added"

Royal Dutch Shell includes a high price for CO2 when evaluaAng new projects. The $40 a metric ton price that Shell uses would — if widely adopted — reshape domesAc and internaAonal energy consumpAon and investment trends. Other corporaAons are also imposing internal prices on their carbon emissions. Disney has adopted a $10 to $20 price per ton CO2, and Microsom has adopted a $7 per ton CO2.

Key Points – INDUSTRY PosiAon

•  Be-er at self-‐policing than government mandated standards and regulaAons

•  IncenAves are not subsidies, essenAal for doing business, sustaining innovaAon

•  Public concerns can be, are being, addressed through ongoing innovaAons (e.g., reducing water use, waste, chemicals, emissions, land footprint)

•  All public concerns are resolvable, and best addressed through industry-‐driven iniAaAves

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36

•  Vertical Wells (pink) develop 23 acres per well with 19% land disturbance. •  Horizontal (green) develop 500 acres per pad with 2% surface disturbance

Centralized OperaAons, Less Land Disturbance, Lower ConstrucAon Costs

Industry case: Economic & Environmental Advantages of Horizontal Drilling

Kelvin B Gregory, NavigaAng the Water Management Challenges During Hydraulic Fracturing for Shale Gas ProducAon, Carnegie-‐Mellon, “Environmental and Social ImplicaAons of Hydraulic Fracturing and Gas Drilling in the United States: An IntegraAve Workshop for the EvaluaAon of the State of Science and Policy”, Duke University January 9, 2012

Industry voluntary self-‐reporAng FRACKING FLUID – 20-‐Month trend

h-p://ecowatch.com/2012/09/25/water-‐for-‐fracking/

Based on industry voluntary self-‐reporAng to FracFocus between Jan. 2011 and Sept. 2012. Not all industry wells are reported. As of the end of 2012 an esAmated 47% of wells are reported to FracFocus, the other 53% not reported for proprietary chemical reasons.

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FRACKING FLUID – COMPOSITION

h-p://www.shalegaswiki.com/index.php/Fracturing_fluid 38

FRACKING FLUIDS – no problem

"You can drink it. We did drink it around the table, almost ritual-‐like, in a funny way," Hickenlooper tesAfied before the Senate Commi-ee on Energy and Natural Resources.

h-p://www.huffingtonpost.com/2013/03/07/hickenlooper-‐says-‐state-‐w_n_2828221.html

Halliburton CEO David Lesar raised a container of Halliburton's new fracking fluid made from materials sourced from the food industry (CleanSAm), then called up a fellow execuAve to demonstrate how safe it was by drinking it.

39

Key Points – COMPLEX RealiAes •  Shale resources occur in diverse locaAons making generic

statements difficult u  Extreme dry to abundant water locaAons u  Low to high water use requirements per well u  Low to high water waste discharges per well u  How to safely discharge and store wastes long-‐term u  Sparse populaAon to high density communiAes u  Rare to abundant capped and uncapped Abandoned Wells u  Low land value to high-‐valued land purposes u  Local aotudes towards fracking industry ranging from strongly pro

expansion to strongly pro ban, omen in equal amounts u  24-‐fold difference in GHG emission levels from well operaAons

•  Shale gas preferenAal treatment, policies, subsidies & regulaAons vs. compeAtors (lower cost end-‐use efficiency, wind, solar power

40

Marcellus Shale Complex Issues

41

•  Water needed for HF and disposal of produced load water are becoming serious obstacles for Marcellus development.

•  Problem with water sourcing is not availability but geong water mgnt plans approved for the high volume withdrawals (3-‐4 million gals).

Arthur E. Berman, Shale gas—Abundance or mirage? Why the Marcellus Shale will disappoint expectaAons, October 2010.

•  Few waste treatment plants, driving up the cost of transporAng disposal water. •  Widespread belief that HF will contaminate aquifers -‐-‐ a risk that cannot be tolerated. •  PopulaAon density is high in many areas, heightening sensiAvity to perceived drilling and

producing hazards. •  Any spills or blowouts raise risk of shut down or curtailing operaAons in a larger area than

the problem well. •  Abandoned wells complicate issue of prior contaminaAon vs. new HF impacts. •  Drilling in suburban areas will complicate puong acreage blocks together. •  More potenAal objecAons to drilling the thousands of locaAons necessary to hold leases

and prove reserves. •  Factors do not mean that development won’t proceed, but it is likely to move forward

more slowly and at greater cost than in other shale plays.

Key Points – Issues & Level of Concern

! 9!

INTRODUCTION)!

Issues)&)Level)of)Concern)!

!

!! !

ISSUES!&!LEVEL!OF!CONCERN!(High,!

Medium,!Low)!

SCIENCE<based,!evidence<driven,!accumulated!empirical!experience!

INDUSTRY!practices!and!motivations!–

leading!to!lagging!continuum!

PUBLIC!opinions,!local!outcomes!and!experiences,!

social!and!environmental!

impacts!

POLITICAL!response,!process,!procedures,!rules,!

regulations,!consensus!(Local,!

State,!Natl)!

Water!Use! Medium!to!High! Low!to!Medium! High!L:!High!S:!Medium!N:!Low!!

Water!contamination! High! Low!to!Medium! High!

L:!High!S:!Medium!N:!Low!

Water!Waste! Medium!to!High! Low! High!L:!High!S:!Medium!N:!Low!

GHG!Emissions! High! Low! Medium!to!High!

L:!Medium!to!High!S:!Medium!to!High!N:!Low!

Air!Pollution! High! ! High!L:!High!S:!Medium!N:!Low!

Fuel!Price! Medium!to!High! Low! High! Low!Long<term!Supply! Low!to!Medium! Low! Low! Low!

Land!change!patterns! Medium! Low! Medium!to!High! Low!

Competitive!Alternatives! Medium!to!High! Low! Medium!to!High! Low!to!Medium!

CCS! Low!to!Medium! Low! Medium!to!High! Low!CCUS! Low! Medium! Medium! Medium!

Earthquakes! Medium! Low! Medium!to!High! Low!Unknown!Knowns! Low! Low! Low! Low!

Known!Unknowns! Low! Low! Low! Low!

Unknown!Unknowns! Low! Low! Low! Low!

42

Low

Key Points – Issues & Level of Concern

! 9!

INTRODUCTION)!


!

!! !


Medium,!Low)!






impacts!



State,!Natl)!















! 9!

INTRODUCTION)!


!

!! !


Medium,!Low)!






impacts!



State,!Natl)!















43

Irreconcilable differences? War of Words & ConfrontaAons

44

h-p://earthroot.net/frackconference/

h-p://www.ihs.com/info/ecc/a/americas-‐new-‐energy-‐future-‐report-‐vol-‐3.aspx

VS. MERCHANTS OF FEAR?

MERCHANTS OF DOUBT?

Key Points – FEDERAL Policy Fracking industry exempAons from key provisions of federal laws (so-‐called “Halliburton Loophole”)

1.  Clean Water Act (CWA) 2.  Safe Drinking Water Act (SDWA) 3.  NaAonal Environmental Policy Act (NEPA) 4.  Toxic Substances Control Act (TSCA) 5.  Resource ConservaAon & Recovery Act (RCRA) 6.  Hazardous Materials TransportaAon Act (HMTA) 7.  Emergency Planning & Community Right to

Know Act (EPCRA) 8.  Comprehensive Environmental Response,

CompensaAon and Liability Act (CERCLA)

45

Key Points – LOCAL BANS RISING

400 BANS IN 21 STATES

46 h-p://www.foodandwaterwatch.org/water/fracking/fracking-‐acAon-‐center/map/

Key Points – State vs Local Officials

47

Some states have introduced legislaAon that limits the ability of municipaliAes to use zoning to protect ciAzens from exposure to pollutants from hydraulic fracturing by protecAng residenAal areas. Such laws have been created in Pennsylvania, Ohio and New York, Colorado, and Texas are ba-ling over related legislaAon.

Fort Collins Mayor pro tem Kelly Ohlson had no kind words for CO Gov. Hickenlooper, saying he has no credibility, nor do state regulators. “I believe the governor should spend his Ame protecAng the health and safety and welfare of ciAzens of Colorado rather than acAng like the chief lobbyist for the oil and gas industry,” Ohlson said. “In fact, I think he should literally quit drinking the fracking Kool-‐Aid.”

CO Gov. Hickenlooper has said the state will sue any local government that bans fracking. “Someone paid money to buy mineral rights under that land [and] You can’t harvest the mineral rights without doing hydraulic fracturing.”

Overview Horizontal Drilling from AnA-‐Fracking perspecAve

49

“Walking Rig” MulAple wells on same pad

Uncertainty of Ongoing, Long-‐term Performance: Industry has Leader Cluster and

Long Tail of PotenAal Poor Performers

50

Lead

ership & Great Perform

ance

The Long Tail

Laggers & Poor Performers

FRACKING FLUID – 20-‐Month trend


h-p://www.youtube.com/watch?v=jMHr6LQhTRE

Visualizing 65.9 Billion Gallons of Frackwater

750,000 gallons per second flow over the iconic Niagara Falls during the summer. The chart on the right indicates water volume used for fracking in equivalent “Niagara Falls tourist hours”.

51

FRACKING FLUID – 50+% not reported


More than half of new wells went unreported on FracFocus in each of three states: Texas, Oklahoma and Montana

In all, 1,126 companies had at least one well in the analysis period. 1,038 of them, or 92 percent, didn’t report any wells on FracFocus.

52

Drilling AddiAves & funcAons in Shale gas extracAon

10

Part 2: Chemical and Biological Hazards From Natural Gas Extraction

Drilling Additives:

Many chemical products are used in the development of a gas well. Some examples,

along with their most common applications, are shown in Table II.

Table II: Additive Functions in Shale Gas Extraction

Additive Type Examples Purpose Used In

Friction Reducer heavy naphtha, polymer microemulsion

lubricate drill head, penetrate fissures

drilling muds, fracturing fluids

Biocide glutaraldehyde, DBNPA, dibromoacetonitrile

prevent biofilm formation


Scale Inhibitor ethylene glycol, EDTA, citric acid

prevent scale buildup


Corrosion Inhibitor

propargyl alcohol, N,N-dimethylformamide

prevent corrosion of metal parts


Clay Stabilizer tetramethylammonium chloride

prevent clay swelling


Gelling Agent bentonite, guar gum, “gemini quat” amine

prevent slumping of solids


Conditioner ammonium chloride, potassium carbonate, isopropyl alcohol

adjust pH, adjust additive solubility


Surfactant 2-butoxyethanol, ethoxylated octylphenol

promote fracture penetration

drilling fluids, fracturing fluids

Cross-Linker sodium perborate, acetic anhydride

promote gelling fracturing fluids

Breaker hemicellulase, ammonium persulfate, quebracho

“breaks” gel to promote flow-back of fluid

post-fracturing fluids

Cleaner hydrochloric acid dissolve debris stimulation fluid, pre-fracture fluid

Processor ethylene glycol, propylene glycol

strip impurities from produced gas

post-production processing fluids

R. E. Bishop, “Chemical and Biological Risk Assessment for Natural Gas ExtracAon in New York h-p://wellwatch.files.wordpress.com/2011/05/risk-‐assessment-‐natural-‐gas-‐extracAon.pdf.

53

Large-‐scale Chemical Use

54

The large-‐scale use of chemicals with significant toxicity has given rise to a great deal of public concern, and an important aspect of the debate concerns the level of proof required to associate an environmental change with acAviAes associated with gas drilling.

80,000 fracking wells since 2005 280 billion gallons toxic wastewater in 2012

2 billion gallons chemicals in 2012

Chemical Issues

55

Barium Lead Arsenic Benzene Bromide

Over 200 different chemical products More than three-‐fourths are health hazards: respiratory diseases, endocrine diseases, infer@lity and birth defects, kidney, heart, liver, brain damage, cancer

2-‐butoxyethanol (2-‐BE) Glutaraldehyde Hydrogen Sulfide 4-‐Nitroquinoline-‐1-‐oxide (4-‐NQO)

Chemicals of Special Concern

Professor Ronald E. Bishop, Ph.D., C.H.O. Chemistry & Biochemistry, SUNY College at Oneonta, Shale Gas Impacts on Water Quality, Incident Frequencies PotenAal Pathways Chemicals of Concern

Fracking Fluids -‐ Chemicals

56

Based on FracFocus data, chemicals used in Marcellus Shale typical hydraulic fracturing job, a 3D visualizaAon of volume of various chemicals used in the process. “Trade secret" chemicals not idenAfied are symbolized by the large quanAty of red barrels.

h-p://blog.skytruth.org/2012/06/meet-‐frack-‐family.html

FRACKING FLUIDS – are a problem

Veterinarian Michelle Bamberger and Professor Robert Oswald of molecular medicine at Cornell’s College of Veterinary Medicine, published the first and only peer-‐reviewed report to suggest a link between fracking and illness in food animals.

The authors compiled 24 case studies of farmers in six shale-‐gas states whose livestock experienced neurological, reproducAve and acute gastrointesAnal problems amer being exposed — either accidentally or incidentally — to fracking chemicals in the water or air. Michelle Bamberger & RE Oswald, Impacts of gas drilling on human and animal health, New SoluAons: A Journal of Environmental and OccupaAonal Health, 2012;22(1):51-‐77.

h-p://www.youtube.com/watch?v=IYdeWhP-‐u_4

57

Fracking Fluids – CiAzens want more complete transparent informaAon

58 h-p://blog.skytruth.org/2012/11/skytruth-‐releases-‐fracking-‐chemical.html

CiAzen-‐generated map based on extracted data from more than 27,000 "chemical disclosure reports" voluntarily submi-ed by industry to FracFocus, between Jan. 2011 and Aug. 2012. The SkyTruth Fracking Chemical Database is the first free public resource enabling research and analysis of the chemicals used in fracking operaAons naAonwide.


Exposed livestock “are making their way into the food system, and it’s very worrisome to us,” Bamberger said.

“They live in areas that have tested posiAve for air, water and soil contaminaAon. Some of these chemicals could appear in milk and meat products made from these animals.” Elizabeth Royte, Livestock falling ill in fracking regions, NBCNews, November 29, 2012

59


LOUISIANA, 17 cows died amer an hour’s exposure to spilled fracking fluid, which is injected miles underground to crack open and release pockets of natural gas.

NEW MEXICO, hair tesAng of sick ca-le that grazed near well pads found petroleum residues in 54 of 56 animals.

NO. CENTRAL PENNSYLVANIA, 140 ca-le were exposed to fracking wastewater when an impoundment was breached. Approximately 70 cows died, and the remainder produced only 11 calves, of which three survived.

Elizabeth Royte, Livestock falling ill in fracking regions, NBCNews, November 29, 2012 60

Insurance Risk?

61

NaAonwide Mutual Insurance Co. spokeswoman Nancy Smeltzer stated that personal and commercial policies "were not designed to cover" risk f rom the drilling process, called fracking.

memo reads: "Amer months of research and discussion, we have determined that the exposures presented by hydraulic fracturing are too great to ignore. Risks involved with hydraulic fracturing are now prohibited f or General Liability, Commercial Auto, Motor Truck Cargo, Auto Physical Damage and Public Auto (insurance) coverage." It said "prohibited risks" apply to landowners who lease land for shale gas drilling and contractors involved in fracking operaAons, including those who haul water to and from drill sites; pipe and lumber haulers; and operators of bulldozers, dump trucks and other vehicles used in drill site preparaAon.

Fracking Boom Gives Banks Mortgage Headaches

62

At least three insAtuAons — Tompkins Financial in Ithaca, N.Y., Spain's Santander Bank and State Employees' Credit Union in Raleigh, N.C. — are refusing to make mortgages on land where oil or gas rights have been sold to an energy company.

Andy Peters, Fracking Boom Gives Banks Mortgage Headaches, Nov. 12, 2013, h-p://www.americanbankers.com/

"That alone would make it a problem.” The mortgage agreement says home-‐owners can sell an oil or gas lease to an energy firm with prior consent from a lender, but May says, "I don't know any lenders who are granAng that right now.”

The uniform New York state mortgage agreement, used by Fannie Mae and Freddie Mac, states that "you cannot cause or permit any hazardous materials to be on your property and it specifically references oil and gas," says Greg May, VP of residenAal mortgage lending at Tompkins.

Banks Mortgages & Fannie Mae

63 Andy Peters, Fracking Boom Gives Banks Mortgage Headaches, Nov. 12, 2013, h-p://www.americanbankers.com/

If FannieMae owns the mortgage, it’s unlikely it would approve such a transfer. FannieMae generally does not "allow surface instruments," such as an oil rig, on property it owns, says spokeswoman Callie Dosberg.

A landowner could apply for prior approval, and there "may be a work-‐around, but generally the agency does not approve such requests," she says.

A greater concern for homeowners is that Fannie Mae or Freddie Mac could force the enAre outstanding loan balance to become due immediately.

Banks Mortgage & Freddie Mac


Freddie Mac is within its legal authority to exercise a mortgage's "due on sale" clause if a borrower enters into a mineral-‐rights agreement. No "public informaAon" is available to show if that has ever happened. An ability to exercise the "due on sale" clause is triggered if a landowner transfers a right a-ached to the property; or through language that bars "hazardous condiAons" on the site. A clause in Freddie Mac's standard security instrument bars "the borrower from taking any acAon that could cause the deterioraAon, damage or decrease in value of the subject property." So the borrower cannot enter into a mineral lease without express approval.

Not Problem in Western States with Banks, Mortgages & Fracking


Severed mineral rights has not been an issue in the western United State, where homeowners have always assumed that their land had a mineral right that was separate from their mortgage, says Kent Siegrist, a Tulsa, Okla., lawyer. "In Oklahoma, it's virtually impossible to buy property with the minerals sAll a-ached to it," says Siegrist, who represents oil companies and landowners. No bankers in western North Dakota, where the oil industry is centered, have raised concerns about fracking and mortgage lending, says Rick Clayburgh, president and CEO of the North Dakota Bankers AssociaAon.

Mid-‐night & Mid-‐day Illegal Dumping

66

Two Ohio state regulatory agencies conducted a criminal invesAgaAon into how and why 20,000 gallons of fracking wastes were dumped into a storm drain near the site of the D&L Energy Group headquarters on Salt Springs Road, near Youngstown, Ohio. Apparently CEO Ben W. Lupo directed employees there to dump the wastewater down a storm drain.

h-p://www.vindy.com/videos/2013/feb/05/2175/#sthash.aOXBQTvq.dpuf

Wilderness & NaAonal Park Impacts

67

Footprint…wildlife…viewshed

E X P E R I E N C E Y O U R A M E R I C A

Footprint…wildlife…viewshed

E X P E R I E N C E Y O U R A M E R I C A Penoyer, Stray Gas MigraAon Issues in Well Design and ConstrucAon; ConsideraAons in Avoiding Methane Impacts to Drinking Water Aquifers and/or Air Emissions, NaAonal Park Service, U.S. Dept. of Interior

UTAH Wilderness Wonderland Threatened

The BLM deferred 99,960 acres of proposed oil and gas leases in and around the Utah’s magnificent San Rafael Swell. This region has been considered for everything from NaAonal Monument to NaAonal Park status. It’s a wonderland of red rock towers, spires and canyons.

68

Night Sky PolluAon & Noise

69

Legacy problems Unplugged abandoned wells

70

Nearly a quarter century ago the EPA esAmated that there were more than 1 million abandoned oil and gas wells naAonwide, with nearly 1 in 5 being portals for polluAon to reach the surface.


71

New York state regulators esAmate there are 57,000 orphan/abandoned wells in the state, with half of their locaAons unknown. In 2009 more orphan/abandoned wells were newly discovered than were plugged.

NYS DEC - Division of Mineral Resources 24 Nineteenth Annual Report

New York State Oil, Gas and Mineral Resources, 2002

Priority Plugging List Historically, abandoned wells have been discov-ered at playgrounds and parking lots, inside buildings, in wetlands, underwater in creeks and ponds, in wooded and brushy areas and in resi-dential yards. Every year DEC staff discover additional abandoned wells during scheduled inspections or while investigating complaints. DEC staff evaluate the environmental and pub-lic safety threats posed by each well and place the most serious cases on the Priority Plugging List to be plugged whenever funds become available. Currently, there are 634 wells in 18 counties on the Priority Plugging List. Allegany and Catta-raugus County have a considerable number of abandoned old oilfield wells on the Priority Plugging List, but problem oil and gas wells of all ages are on the list. To date, only a small percentage of Priority Plugging List wells have ever been removed from the list. Wells removed from the list were plugged and abandoned with monies from the Oil and Gas Account and Environmental Audit Funds. Environmental Audit Process The Environmental Audit Program requires that each State Agency annually report any environ-mental problems associated with the lands and facilities they manage. Many agencies such as DEC, Parks, Urban Development, DOT and Mental Health have recently plugged leaking or abandoned wells identified in the Enviromental Audit (see page 23 for DEC plugging on State lands). However, many abandoned wells located on State lands are still not being reported, such as those found on DOT right-of-ways. In February Division staff made a presentation at a State Agency Environmental Audit Work-shop. Division staff explained the need to report abandoned wells and showed the workshop at-tendees examples of abandoned wells and the wide variety of settings where they can be found.

This Priority Plugging List well in the City of Rome, Oneida County was discharging brine at a rate of five gallons per minute into a wetland adjacent to Brandy Brook and had already killed over an acre of vegetation in 1998.

The mostly wooden structure is an older style of drilling rig known as a cable tool rig. It is being used to plug a well in a DOT right-of-way next to a stream.

The Division issued 177 Well Plug-ging Permits in 2002. All wells must be plugged and abandoned at the end of their productive life. The Division ensures that the proposed plugging procedures will protect ground and surface water and the site will be properly reclaimed and revegetated.

Plugging Permits

Professor Ronald E. Bishop, Ph.D., C.H.O. Chemistry & Biochemistry, SUNY College at Oneonta, Shale Gas Impacts on Water Quality, Incident Frequencies PotenAal Pathways Chemicals of Concern , siAng New York State Department of Environmental ConservaAon, Division of Mineral Resources, New York State Oil, Gas and Mineral Resources, 2002, July 2004, pp. 22-‐24, h-p://www.dec.ny.gov/docs/materials_minerals_pdf/prod023.pdf

One case involved an old gas well that discharged brine at a rate of five gallons per minute into a wetland near Rome, killing over an acre of vegetaAon.


72

Another involved the enAre village of Rushville, on the border between Ontario and Yates CounAes, where two dozen unplugged abandoned wells were responsible for widespread emanaAon of gas from the soil, so that methane accumulated to explosive levels in some structures.



Zoar Well Plugging Site. The construction of the access road and well site was designed to minimize disturbance to the surrounding area.

Public Lands - Using State Environmental Audit funds, the Department plugged seven problem abandoned wells on a wide range of public lands. DEC plugged three abandoned gas wells on the Three Rivers Wildlife Man-agement Area in Onondaga County. One well had been flowing natural gas and another was discharging brine. In addition, DEC plugged four abandoned wells in Cattaraugus County, three on Cattaraugus Reforestation Area #22 in the Town of Allegany and one on the Zoar Multiple Use Area in the Town of Persia. In a separate incident, another abandoned well was discovered on property that The Nature Conservancy purchased for possible addition to the Deer Creek Wildlife Management Area in Oswego County.

Seneca Lake - Through field and office work, Division staff discovered seven abandoned salt wells at the US Salt facility in the Town of Reading, Schuyler County. The wells had been abandoned for decades. All the wells were less than 50 feet from the shore and adjacent to a steep grade which raised concerns about po-tential impacts to the lake. Rig access was very difficult, but the responsible party successfully plugged all the wells.

Ongoing Problems - Many abandoned well issues take several years to resolve as the Di-vision pursues legal action against those responsible. The Moore Lease in Allegany County is a good example with more than 200 abandoned wells involved in legal actions. The Moore wells occur in a variety of settings (residential areas, roadside, woodland, field etc) and many are leaking oil.

Abandoned wells can leak oil, gas and/or brine. They can contaminate groundwater and sur-face water, kill vegetation and cause safety and health problems. Underground leaks may go undetected for years before their damage is discovered.



ABANDONED WELLS

Residential Area - Pipeline company employees detected natural gas emanating from two residential lawns in the Village of Rushville, Ontario and Yates County. Explosive gas levels were also found in-side a garage. Division staff uncovered two natural gas wells in the vicinity. Gas in the soil declined when the wells were vented under DEC direction. Roughly 24 gas wells were drilled in the village in the 1900's and need to be plugged when funds are available. The backhoe is exca-vating a leaking well next to a building.

School - During construction of a new bus garage at the Bolivar-Richburg High School in Allegany County, several buried abandoned wells were uncovered. Since no well records were available, the school had to bring in a small service rig (red equipment in foreground) to check the condition of the wells. All the wells had to be plugged before construction could re-sume. This is not the first school well inci-dent that the Division has handled. For example, in nearby Wyoming County DEC plugged a gas well that was leaking brine in the parking lot of Wyoming County Central School in 1991.

The Division estimates that over 75,000 oil and gas wells have been drilled in New York State since the 1820s.

Most of the wells were drilled before New York established

a regulatory program and many were never plugged. Every

year the Division of Mineral Resources deals with a “new”

group of problem abandoned wells in a wide variety of

settings. Here is a selection of abandoned wells from 2002.



73

Plugging or excavaAon of abandoned wells on school properAes in Allegany and Wyoming CounAes cost those school districts thousands of dollars.



ABANDONED WELLS

Residential Area - Pipeline company employees detected natural gas emanating from two residential lawns in the Village of Rushville, Ontario and Yates County. Explosive gas levels were also found in-side a garage. Division staff uncovered two natural gas wells in the vicinity. Gas in the soil declined when the wells were vented under DEC direction. Roughly 24 gas wells were drilled in the village in the 1900's and need to be plugged when funds are available. The backhoe is exca-vating a leaking well next to a building.

School - During construction of a new bus garage at the Bolivar-Richburg High School in Allegany County, several buried abandoned wells were uncovered. Since no well records were available, the school had to bring in a small service rig (red equipment in foreground) to check the condition of the wells. All the wells had to be plugged before construction could re-sume. This is not the first school well inci-dent that the Division has handled. For example, in nearby Wyoming County DEC plugged a gas well that was leaking brine in the parking lot of Wyoming County Central School in 1991.

The Division estimates that over 75,000 oil and gas wells have been drilled in New York State since the 1820s.

Most of the wells were drilled before New York established

a regulatory program and many were never plugged. Every

year the Division of Mineral Resources deals with a “new”

group of problem abandoned wells in a wide variety of

settings. Here is a selection of abandoned wells from 2002.

Abandoned wells have been found leaking oil into creeks and wetlands in Steuben and Allegany CounAes, and into residenAal ponds and lawns in Allegany and Ca-araugus CounAes


Legacy problems create confusion with current development

74

Case on Point – Eddy Family Arc of new gas wells developed by U.S. Energy Resources about 1⁄4 mile away Eddy family’s land. Eddy’s water well polluted by oil -‐-‐ not brine or other gas

industry chemicals Probable cause: abandoned oil well near their home DisposiAon: cause not related to gas development U.S. Energy Development offered a water treatment system, while acknowledging no culpability. U.S. Energy also offered a financial se-lement in return for signing a non-‐disclosure agreement. The treatment system was accepted, but not the cash.


What to Do about legacy problems?

75

Clean up the old mess before we start a new one. §  Prohibit non-‐disclosure agreements unAl AFTER

invesAgaAons are complete. §  DramaAcally increase staffing of Bureau of Oil and

Gas RegulaAon §  In NY over 13,000 oil/gas wells, only 16 field

agents: over 800 wells per inspector §  Promote research on health impacts. §  Plausible deniability is not preferable to

scienAfically-‐based risk assessment.


Summary Shale Gas Methane Emissions

77

1. Shale gas is abundant, emits half the CO2 emissions as coal, is currently low-‐cost, resulAng in rapid expansion. But methane is a far more potent GHG than previously esAmated, and if leakages surpass a certain percentage of producAon then climate advantages over coal disappear. 2. AggregaAng gas emissions from pre-‐producAon, producAon, processing, transmission (pipeline) and end-‐use combusAon (e.g., power plant) is complex, and a myriad of assumpAons result in a wide range of esAmates. 3. There is widespread agreement that there is insufficient monitoring and measurement to accurately or precisely determine the gas industry’s methane emissions. EPA esAmates emissions at 2 to 3% of producAon, but esAmates from field research span 24-‐fold – from 0.45% to 12%. 4. Industry leaders believe below 1% is a sensible goal and would gain wide support from environmental and civic groups. Climate scienAsts see this as a necessary imperaAve, but not sufficient, given the carbon constrained budgets the world must adopt in order to prevent exceeding 2°C rise in global average temperature. Zero emissions is an imperaAve, so gas expansion must shim to zero emissions within the next decade-‐plus. 5. Coal is not the ulAmate comparison for gas, but now confronts cost-‐effecAve compeAAon from three emission-‐free opAons – end-‐use efficiency, wind and solar power. And methane emissions is only one among a dozen a-ributes that civic, corporate and public leaders use to evaluate the least-‐cost-‐and-‐risk methods of delivering energy services to the point of use.

Possible mechanisms for leakage of stray gas to water resources

78 Penoyer, Stray Gas MigraAon Issues in Well Design and ConstrucAon; ConsideraAons in Avoiding Methane Impacts to Drinking Water Aquifers and/or Air Emissions, NaAonal Park Service, U.S. Dept. of Interior

Methane migraAon via abandoned wells

79

Gas Leakage along a Well Wellbore Leakage

• Wellbore leakage is separated into two distinct areas of the wellbore

• Shallow leakage generally due to poor cementing practices

• Deep leakage generally due to stimulation or perforating

• Only deep leakage is generally associated with CO2

• CO2 leakage in the shallow areas are due to secondary events

Theresa L. Watson, T.L. Watson & Associates, and Stefan Bachu, Alberta Energy Resources ConservaAon Board, EvaluaAon of the PotenAal for Gas and CO2 Leakage Along Wellbores, journal SPE Drilling & CompleAon, SPE 106817-‐PA 80

Wellbore leakage is separated into two disAnct areas of the wellbore. Shallow leakage is generally due to poor cemenAng pracAces. Deep leakage is generally due to sAmulaAon or perforaAng. Only deep leakage is generally associated with CO2.

Gas Leakage along a Well


Shallow Leakage

• Surface Casing Vent Flow• Gas Migration• Casing Failure

Shallow Leakage

• Surface Casing Vent Flow• Gas Migration• Casing Failure

Surface Casing Vent Flow, Gas MigraAon, Casing Failure.

Zonal Abandonment failure example


Zonal Abandonment Failure

Gas MigraAon along a Well

2

“Since the earliest gas wells, uncontrolled migration of hydrocarbons to the surface has challenged the oil and gas industry…many of today’s wells are at risk. Failure to isolate sources of hydrocarbon either early in the well-construction process or long after production begins has resulted in abnormally pressurized casing strings and leaks of gas into zones that would otherwise not be gas bearing”.

Figure 1. Simplified schematic showing phenomenon of upward gas migration

along a casing string. From Dusseault et al., 2000.

Figure 2. Schematic of details of possible fluid migration paths in and around a cased/cemented well.

Theresa Watson & Stefan Bachu, Wellbore Leakage PotenAal in CO2 Storage or EOR, Fourth Wellbore Integrity Network MeeAng Paris, France,, March 19, 2008. 83

Cement Type

Data and photograph courtesy Barbara Kutchko, DOE

One Year DegradaAon of Neat Class H Cement

Deep Leakage to Surface and Groundwater in Central Alberta

84 Theresa L. Watson, T.L. Watson & Associates, and Stefan Bachu, Alberta Energy Resources ConservaAon Board, EvaluaAon of the PotenAal for Gas and CO2 Leakage Along Wellbores, journal SPE Drilling & CompleAon, SPE 106817-‐PA

Deep Leakage to Surface and Groundwater in Central Alberta

What’s the Problem with Horizontal Well MulA-‐stage Fracturing?

85

Theresa Watson, Alberta RegulaAons: Wellbore Integrity Issues Driving Regulatory Change, North American Wellbore Integrity Workshop Oct. 16-‐17, 2013

§  Increasing numbers of horizontal, mulA-‐stage hydraulic fractured wells

§  Large numbers of pre-‐exisAng wellbores in the province

§  PotenAal to impact assets and groundwater

Where’s the Proof?

86 Theresa Watson, Alberta RegulaAons: Wellbore Integrity Issues Driving Regulatory Change, North American Wellbore Integrity Workshop Oct.17, 2013

Blue: all wells drilled in Alberta since 1955 Light orange: all wells fractured Dark orange: all horizontal wells sAmulated by mulAstage hydraulic fracturing

Where’s the Proof?Where s the Proof?• Blue: all wells

drilled in Alberta since 1955

• Light orange: all wells fractured

• Dark orange: all h i lhorizontal wells stimulated by multistage hydraulic g yfracturing

Watson, Theresa, Presented at University of Calgary, Schulich School of Engineering Alumni 2013 Distinguished Speakers Panel, March 14, 2013.

Where’s the proof?

87

Where’s the ProofWhere s the Proof

Kim.Thomas, Overview of Interwellbore Communication Incidents: An ERCB Perspective. Presented at the Canadian Society of Unconventional Resources 14th Annual Conference October 3-4, 2012, Calgary Alberta

Kim.Thomas, Overview of Inter-‐wellbore CommunicaKon Incidents: An Energy Resources ConservaKon Board of Canada PerspecKve. Presented at the Canadian Society of UnconvenAonal Resources 14th Annual Conference October 3-‐4, 2012, Calgary Alberta

Where’s the ProofWhere s the Proof

Kim Thomas Overview of Interwellbore CommunicationKim.Thomas, Overview of Interwellbore Communication Incidents: An ERCB Perspective. Presented at the Canadian Society of Unconventional Resources 14th Annual Conference October 3-4, 2012, Calgary Alberta

Distance between wellbores: Closest 30 meters Furthest 2400 m Mean 355 m Median 250 m

Where’s the proof?

88 Kim.Thomas, Overview of Inter-‐wellbore CommunicaKon Incidents: An Energy Resources ConservaKon Board of Canada PerspecKve. Presented at the Canadian Society of UnconvenAonal Resources 14th Annual Conference October 3-‐4, 2012, Calgary Alberta

20 reported incidents since 2009 • 18 incidents: fracture sKmulaKon communicaKng to a producing well

• 2 incidents: fracture sKmulaKon to a drilling well

• 55% of the incidents had no spills, equipment damage, or long-‐term adverse effects on producKon

Where’s the Proof?Where s the Proof?•20 reported incidents since 2009

• 18 incidents: fracture stimulation communicating to a producing well

• 2 incidents: fracture stimulation to a drilling well

•55% of the incidents had no spills equipment damage orspills, equipment damage, or long-term adverse effects on production

Where’s the Proof?Where s the Proof?•20 reported incidents since 2009• 18 incidents: fracture stimulation communicating to a producing well



Where’s the Proof?Where s the Proof?•20 reported incidents since 2009• 18 incidents: fracture stimulation communicating to a producing well



Legacy of Abandoned Wells

89

§ Urban encroachment on old abandoned oil fields

§ Public safety concerns about leaking wells and gas accumulaKons in basements

§ Numbers of impacts growing

§ No permanent indicator of abandoned wells on the land or on Ktle

Where’s the Proof?Where s the Proof?

Photos Courtesy Doull Site Inc







Theresa Watson, Alberta RegulaAons: Wellbore Integrity Issues Driving Regulatory Change, North American Wellbore Integrity Workshop Oct.17, 2013



Wellbore Strike by Farming Equipment Wellbore Strike by Farming Equipment

Wellbore Strike by Farming Equipment



Wellbore Strike during Development Wellbore Strike during Development

Wellbore Strike during Development



Urban Expansion & Encroachment Urban Encroachment

City

Well 2

Well 1

2006 City Boundary

Estimated 2056 City Boundary

2 people per km2

8 people per km2 100 people

per km2

Population growth by expanding urban centresINCREASED POPULATION. EsAmated growth from 3 milliion to 6 million by 2056. INCREASED WATER WELLBORES. It is esAmated that there will be 959,000 wells in Alberta province by 2056 compared to 343,000 in 2006.

What SoluAons?


§  Requires a 5 meter setback from an abandoned well §  Requires developers to check for abandoned wells

and contact licensees to make development plans §  Liability remains with licensee §  Requires abandoned wells to be tested for gas

migraAon §  Risk assessment and ongoing tesAng

Alberta Province’s DirecKve 79: Surface Development in Proximity to Abandoned Wells

Other regulatory changes?


§  Change in abandoned well capping requirements §  Changes in surface casing requirements §  Discussion and research ongoing to determine a level of acceptable

leakage §  Field research invesAgaAng surface measureable gas leakage of

abandoned wells §  Ongoing changes in abandonment requirements §  Limits on in-‐situ oil sands development due to pre-‐exisAng §  wellbores in the steam AOI. §  Changes to wellbore construcAon requirements for injecAon wells

Alberta Province example

Increase in New Water Wells

95

Increase in Water Wells Associated with Population Increase

An increase in the number of water wells increases the likelihood that gas, due to migration through shallow zones, can accumulate in buildings.

Increasing number of water wells increases likelihood gas, due to migraAon through shallow zones, can accumulate in buildings.

Deep Leakage Factors

96

Deep leakage factors.

Factor Criterion Meets Criterion Value

Default Value

Fracture count =1 1.5 1

Fracture count >1 2 1

Acid count=1 1.1 1

Acid count=2 1.2 1

Acid count>2 1.5 1

Perforations count>1 2 1

Abandonment type Bridge Plug 3 1

Abandonment type Not abandoned

2 1

Cement types and values.

Cement Type Assigned Value Description

1:1 POZ MIX 1 Cement and fly ash

1:1:# POZ3 Cement, fly ash and various quantities

of bentonite

BLACKGOLD 1 Unknown

CAP (NEAT)1 Cap pumped on top of foam cement,

not applicable.

CLASS X NEAT 1 Various neat cements

FILL ECP1 Cement to fill annular packer, not

applicable

FOAMED 1 Cement foamed with nitrogen

G + # PC SALT1 Cement with various percent salt

additive

G + # PC SAND1 Cement with various percent silica

sand additive

GPSL/GPCEM/THX 3 Gypsum and gel additives

LIGHT WEIGHT 3 Assumed gel additive to reduce density

SELF STRESS3 No cement, hole allowed to slough in

on casing

SLAG1 Blast furnace slag, reduces cement

porosity

SLOTTED LINER 3 No cement

SLURRY 6D 1 Unknown

TAPERED CASING 3 No cement

TH CEM/CEM FNDU1 Thermal cement, usually sand or silica

additive

UNCEM CSG/LINER 3 No cement

Deep Leakage Factors

Theresa Watson & Stefan Bachu, Wellbore Leakage PotenAal in CO2 Storage or EOR, Fourth Wellbore Integrity Network MeeAng Paris, France,, March 19, 2008.

Scoring Shallow & Deep Leakage PotenAal

97 Theresa Watson & Stefan Bachu, Wellbore Leakage PotenAal in CO2 Storage or EOR, Fourth Wellbore Integrity Network MeeAng Paris, France,, March 19, 2008.

Scores

Deep leak potential.

Deep Leak Potential (DLP) Score

Low <2

Medium 2-6

High 6-10

Extreme >10

Shallow leak potential.

Shallow Leak Potential (SLP) Score

Low <50

Medium 50-200

High 200-400

Extreme >400

DLS= v(fracture count) X v(acid count) X v(perforated interval count) X v(aban type) X v(cement type)

SLP = v(spud date) X v(aban date) X v( SC size) X v(well type) X v(location) Xv( TD) X v(dev) X v(cement top) X v(additional plugs)

Scores

Deep leak potential.

Deep Leak Potential (DLP) Score

Low <2

Medium 2-6

High 6-10

Extreme >10

Shallow leak potential.

Shallow Leak Potential (SLP) Score

Low <50

Medium 50-200

High 200-400

Extreme >400

DLS= v(fracture count) X v(acid count) X v(perforated interval count) X v(aban type) X v(cement type)

SLP = v(spud date) X v(aban date) X v( SC size) X v(well type) X v(location) Xv( TD) X v(dev) X v(cement top) X v(additional plugs)

SLP Score = v(spud date) X v(abandoned date) X v( SC size) X v(well type) X v(locaKon) Xv( TD) X v(dev) X v(cement top) X v(addiKonal plugs)

DLP Score = v(fracture count) X v(acid count) X v(perforated interval count) X v(aban type) X v(cement type)

Leakage Case Study -‐ Alberta

98

Case Studies

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Zama Field

Pembina Field

Edmonton

Calgary

ALBERTA

Field data and results summary.

Pembina Zama

Number of cased wells 9860 607

Number of wells drilled and abandoned 1050 106

% of wells with cement data 40% 64%

% of wells with high DLP cement score 28% 20%

% of wells fractured 75% 2%

% of wells acidized 47% 80%

% of wells abandoned 12% 13%

% of wells with multiple completions 11% 55%

% of wells with extreme DLP 14% 28%

% of wells with extreme SLP 7% 18%

% of wells with extreme SLP and DLP 1.6% 4.3%

Zama Deep Leakage Potential

0

20

40

6080

100

120

140

0 5 10 15 20 25 30+

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0

50

100

150

200

250

300

100200

300400

500600

700800

9001000+

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Nu

mb

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f W

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h S

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Theresa L. Watson, T.L. Watson & Associates, and Stefan Bachu, Alberta Energy Resources ConservaAon Board, EvaluaAon of the PotenAal for Gas and CO2 Leakage Along Wellbores, journal SPE Drilling & CompleAon, SPE 106817-‐PA

State of Colorado takes naAonal lead in regulaAng HF methane emissions

99

In November 2013, Colorado health officials proposed new regulaAons for the oil and gas industry. The rules would require operators to capture almost all methane, equivalent to 92,000 tons per year, from both oil and gas wells and storage tanks. CO has more than 30,000 wells, one-‐third drilled between 2006-‐2011.

Michael Wines, Colorado Governor Proposes Strict Limits on Greenhouse Gas Leaks From Drilling, November 18, 2013, New York Times

Operators will be responsible for detecAng methane leaks and reducing emissions by 95 percent, especially near populaAon centers. The Colorado regulaAons would be the first in the United States to regulate methane emissions.

Areas around wells have seen an increase in ground-‐level ozone formed from methane and other chemicals, which can cause and exacerbate asthma. In recent years, a smoggy haze has crept across the front range of the Rocky Mountains north of Denver, where new wells are concentrated, partly as a result of gas leaks that have reacted with other chemicals to form ozone. Nine counAes in the area, including much of Rocky Mountain NaAonal Park, exceed federal ozone limits.

State of Colorado HF methane regs tougher than naAonal regs

100

The industry’s methane emissions are mostly unregulated. the CO proposal goes well beyond the restricAons that EPA began enforcing last year. The federal rules apply primarily to new wells, leaving thousands of older sites exempt from regulaAon, and cover only leaks of volaAle organic compounds.

Michael Wines, Colorado Governor Proposes Strict Limits on Greenhouse Gas Leaks From Drilling, November 18, 2013, New York Times

They do not directly limit leaks of methane, although requirements to limit emissions of volaAle organic compounds also end up reducing methane. Nor do the federal rules require companies to check for leaks at well sites and repair them.

While some industry experts believe the costs will be burdensome to operators, ciAng compliance costs of up to $80 million per year, the legislaAon was dramed with industry input. Ted Brown, Sr VP at Noble Energy, said the rules are “the right thing to do” for the environment and the health of Coloradans.” Gov. Hickenlooper developed the proposal in negoAaAons with 3 of the state’s largest oil and gas developers — Anadarko Petroleum Corp., Encana Corp. and Noble Energy — and EDF. Formal hearings on the proposal will begin February 2014.

Natural Gas vs. Coal A Climate PerspecAve

101 Source: adapted from IEA, “Golden Age of Gas” special report (Figure 1.5)

Leakage rate (% of total producKon)

RaKo

of G

HG emission

s of g

as over coa

l 8%

7%

6%

5%

4%

3%

2% 1%

0 25 50 75 105 0

0.5

1

1.5

2

Global Warming PotenKal (GWP) for methane

Natural Gas Methane Leakage Rates & GWP

102

Natural'Gas'vs.'Coal'A'Climate'Perspec5ve'

9'Source:'adapted'from'IEA,'“Golden'Age'of'Gas”'special'report'(Figure'1.5)''

Leakage&rate&(%&of&total&produc2on)&

Ra2o

&of&G

HG&emission

s&of&g

as&over&coa

l& 8%&

7%&

6%&

5%&

4%&

3%&

2%&1%&

0& 25& 50& 75& 105&0&

0.5&

1&

1.5&

2&

Global&Warming&Poten2al&(GWP)&for&methane&

3 key factors of how natural gas compares to coal from a climate standpoint:

1.   GWP for Methane (a science and policy quesKon) 2.   Methane Leakage Rate (a data quesKon) 3.   End-‐use combusKon efficiency (leading or lagging tech)

Studies esAmate U.S. leakage rates span large range 2 – 5%, with some studies and monitoring indicaAng 5 to 12+% leakage levels at some locaAons. To remain less GHG-‐intensive than coal, methane leakage rates must remain below 2%; sensible goal to achieve below 1%.

EsAmaAng Emissions from Shale Gas Systems

103

gram

s CO

2e per M

egaJou

le (M

J)

0

5

10

15

20

Source: James Bradbury et al, Clearing the Air: Reducing Upstream Greenhouse Gas Emissions from U.S. Natural Gas Systems, April 2013, World Resources InsAtute

There are differing assumpAons regarding how frequently the average well requires HF and liquids unloading, and the extent to which control technologies are used. HF is an emissions-‐intensive process used to iniAate producAon and in workovers to re-‐sAmulate producAon mulAple Ames during the well’s 20-‐ to 30 year lifespan.

Why such different esKmates among studies?

Studies done prior to NOAA and EDF/UT AusAn studies

Life cycle methane leakage rate esKmates for natural gas from onshore convenKonal & shale gas sources

104

CONVENTIONAL ONSHORE

RANGE SHALE/

UNCONVENTIONAL

RANGE

LOW HIGH LOW HIGH

Burnham 2.75 0.97 5.47 2.01 0.71 5.23

Howarth 3.85 1.7 6 5.75 3.6 7.9

Weber 2.8 1.2 4.7 2.42 0.9 5.2

Logan -‐ -‐ -‐ 1.3 0.8 2.8

Leakage rate esKmates are highly sensiKve to choice of EUR (esKmated ulKmate recovery). Burnham, A., J. Han, C.E. Clark, et al. 2011. “Life cycle greenhouse gas emissions of shale gas, natural gas, coal, and petroleum.” Environ Sci Technol., h-p://pubs.acs.org/doi/pdfplus/10.1021/es201942m. Howarth, R., and R. Santoro, and A. Ingraffea. 2011. “Methane and the Greenhouse-‐Gas Footprint of Natural Gas from Shale FormaAons.” ClimaAc Change 106(4): 679–690, h-p://www.springerlink.com/content/e384226wr4160653/. Logan, J., G. Heath, J. Macknick, et al. 2012. “Natural Gas and the TransformaAon of the U.S. Energy Sector: Electricity.” NREL Report-‐6A50-‐55538, h-p://www.nrel.gov/docs/fy13osA/55538.pdf [Logan esAmate based on data from the Barne- basin]. Weber, C., and C. Clavin. 2012. “Life Cycle Carbon Footprint of Shale Gas: Review of Evidence and ImplicaAons.” Environ Sci Technol, h-p://pubs.acs.org/doi/ abs/10.1021/es300375n .

Comparing Detailed EsKmates of Life Cycle GHG Emissions: Shale Gas & ConvenKonal Onshore Natural Gas Sources

105

4 |

0HDQZKLOH��UHFHQW�UHVHDUFK�EDVHG�RQ�¿HOG�PHDVXUHPHQWV�RI�DPELHQW�DLU�QHDU�QDWXUDO�JDV�ZHOO�¿HOGV�LQ�&RORUDGR�DQG�Utah suggest that more than 4 percent of well production may be leaking into the atmosphere at some production-stage operations.5 With hundreds of thousands of wells and thousands of natural gas producers operating in the U.S., this will likely remain an active debate, even as forthcom-ing data from EPA and other sources aims to clarify these

questions in the coming months. For example, independent researchers at the University of Texas at Austin are team-ing up with the Environmental Defense Fund and several industry partners to directly measure methane emissions from several key sources. When results are published in 2013 and 2014, these data will provide valuable points of reference to help inform this important discussion.

Figure S-2 | Comparing Detailed Estimates of Life Cycle GHG Emissions from Shale Gas and Conventional Onshore Natural Gas Sources

* Data available from Marcellus only** “Other Production” and “Other Processing” each include point source and fugitive emissions (mostly from valves)*** Includes all combustion and fugitive emissions throughout the entire transmission system (mostly from compressor stations)

Notes: Recent evidence suggests that liquids unloading is a common practice for both shale gas and onshore conventional gas wells (Shires and Lev-On 2012). Therefore, contrary to data originally published by NETL, showing zero emissions, liquids unloading during shale gas development may result in GHG emissions that are comparable to those associated with conventional onshore natural gas development. GWP for methane is 25 over a 100-year time frame.Source: National Energy Technology Laboratory.

15 10 5 5 10 15

Pipelines & Compressor Stations***

Pipeline Construction

TRANSMISSION

CRADLE-TO-GATE

Compressors

Other Processing**

Acid Gas Removal

Dehydration

PROCESSING

Liquids Unloading

Other Production**

Workovers

PRODUCTION

Well Completion

Well Construction

Water (treatment and transport)*

PRE-PRODUCTION

GHG Emissions (g CO2e/MJ) GHG Emissions (g CO2e/MJ)

SHALE GAS CONVENTIONAL ONSHORE GAS

CH4 CO2PRE-‐PRODUCTION

PRODUCTION

PROCESSING

TRANSMISSION

CRADLE-‐TO-‐GATE

CH4 CO2

GHG Emissions gCO2e/MJ GHG Emissions gCO2e/MJ 15 15 10 10 5 5


OpportuniAes to Reduce FugiAve Methane

106

New EPA rules – NSPS/NESHAP* VolaAle Organic Compounds(VOCs) Hazardous Air Pollutants (HAPs)

Two Scenarios with addiKonal reducKons Low-‐hanging fruit “Go-‐ge-er” scenario


*NSPS – New Source Performance Standards NESHAP -‐ NaAonal Emission Standards for Hazardous Air Pollutants

ProjecKons of GHG Emissions from All Natural Gas Systems Acer AddiKonal Abatement

107

6 |

FURTHER POTENTIAL TO REDUCE METHANE EMISSIONS With the implementation of just three technologies that capture or avoid fugitive methane emissions, we estimate that upstream methane emissions across all natural gas systems could be cost-effectively cut by up to an additional 30 percent (Figure S-4). The technologies include (a) the use of plunger lift systems at new and existing wells during liquids unloading operations; (b) fugitive meth-ane leak monitoring and repair at new and existing well sites, processing plants, and compressor stations; and (c) replacing existing high-bleed pneumatic devices with low-bleed equivalents throughout natural gas systems. By our estimation, these three steps would bring down the total life cycle leakage rate across all natural gas systems to just above 1 percent of total production. Through the adoption RI�¿YH�DGGLWLRQDO�DEDWHPHQW�PHDVXUHV�WKDW�HDFK�DGGUHVV�smaller emissions sources, the 1 percent goal would be readily achieved.

NEXT STEPS TO REDUCE METHANE EMISSIONSNew public policies will be needed to reduce methane emissions from both new and existing equipment through-out U.S. natural gas systems because market conditions DORQH�DUH�QRW�VXI¿FLHQW�WR�FRPSHO�LQGXVWU\�WR�DGHTXDWHO\�or quickly adopt best practices. Minimum federal stan-dards for environmental performance are a necessary and appropriate framework for addressing cross-boundary pollution issues like air emissions. Federal CAA regula-tions are generally developed in close consultation with industry and state regulators and are often implemented E\�VWDWHV��7KLV�IUDPHZRUN�DOORZV�DGHTXDWH�ÀH[LELOLW\�WR�enable state policy leadership and continuous improve-ment in environmental protection over time.

:H�KDYH�LGHQWL¿HG�D�UDQJH�RI�DFWLRQV�WKDW�FDQ�EH�WDNHQ�WR�reduce methane emissions.6 These tools are listed in this summary, and discussed in more detail in section 5.

Federal Approaches to Address EmissionsIn addition to the recently enacted NSPS/NESHAP rules, EPA has a number of additional tools to either directly or indirectly reduce methane emissions from U.S. natural gas systems, most of which would also support more protec-tive actions at the state level. For example, EPA could do the following:

'LUHFW�UHJXODWLRQ�RI�*+*�HPLVVLRQV� EPA could directly regulate GHG emissions under section 111 of the CAA, which could achieve greater reductions in methane and CO2 emissions from new and existing sources than would otherwise be achieved indirectly through standards for VOCs or HAPs.

(PLVVLRQV�VWDQGDUGV�IRU�DLU�WR[LFV� Under section 112 of the CAA, EPA could set emissions standards for HAPs from production-stage infrastructure and operations in urban areas.

Figure S-4 | Projections of GHG Emissions from All Natural Gas Systems after Additional Abatement

Notes: Potential for additional upstream methane emissions reductions for all natural gas systems based on implementation of a hypothetical rule in 2019 requiring plunger lift systems, leak detection and repair, and replacing existing high-bleed pneumatic devices with low-bleed equivalents (purple line); or a rule requiring those technologies and five additional abatement measures (green line). The light blue dashed line shows the total amount of GHG emissions (MMt CO2e) that would result from 1 percent fugitive methane emissions relative to total dry gas production in each year, plus estimated annual CO2.

MM

t CO 2e

350

250

300

200

150

100

50

400

450

2005 2010 2015 2020 2025 2030 2035

Pre-NSPS

BAU (with NSPS)

BAU (with NSPS), with Three Abatement Technologies

“Go-Getter” Scenario

1% Leakage RateLooming quesKon: How to get enKre industry pursuing abatement opportuniKes, not just the leaders. What will it take? Stronger regulaKons? Subsidies? CombinaKon of carrots and sKcks?


WRI Report Key Takeaways on Shale gas methane emissions

108 Source: James Bradbury et al, Clearing the Air: Reducing Upstream Greenhouse Gas Emissions from U.S. Natural Gas Systems, April 2013, World Resources InsAtute

1.  Reduce emissions to below 1% to ensure fuel-‐switching to natural gas is beneficial

2.  FugiAve methane occurs at every stage of the natural gas life cycle, more direct measurements are imperaAve

3.  Recent EPA rules will stem methane leakage; but deeper reducAons can be achieved cost-‐effecAvely

4.  The Clean Air Act is an appropriate tool for policy acAon; responsive to industry and flexible for states

110

“At some point down the road towards the red light of 2°C it is enArely plausible, even predictable, that conAnuing to hold equiAes in fossil fuel companies will be ruled negligence.”

Bevis Longstreth, former SEC Commissioner appointed by President Reagan

CO2e budget for 2°C Limit

111

Listed Fossil FuelReserves & Resources

Global Non-ListedFossil Fuel Reserves

Remaining Available2°C Carbon Budget

Through 2100

2500

2000

1500

1000

500

0

UnburnableCarbonReserves

Gt C

O 2Es

timat

e

A significant portion of the world’s fossil fuel reserves will need to remain in the ground in 2050

if we are to avoid catastrophic levels of climate change. Fossil fuel companies, however, continue to develop reserves

that may never be used.

1541

987

2098

Fossil Fuel Assets at RiskUnburnable Carbon Reserves

www.ceres.org www.carbontracker.org

If humanity is to prevent global average temperature rise from exceeding 2°C , then 80% of fossil fuel assets (now owned by corporaAons or governments) must not be burned.

This means leaving the majority in the ground as stranded assets, or those that are consumed must be done with zero emission releases, such as carbon capture and storage (CCS).

With CCS, both coal and most gas-‐fired power plants are technically and economically unnecessary, given robust compeAAon that can deliver electricity services at the least-‐cost-‐and-‐risk LCOE (levelized cost of electricity).

Chart source: CERES & CarbonTracker, Investors ask fossil fuel companies to assess how business plans fare in low-‐carbon future -‐-‐ coaliAon of 70 investors worth $3 trillion call on world’s largest oil & gas, coal and electric power companies to assess risks under climate acAon and ‘business as usual’ scenarios, Nov 2013

Carbon Budget per generaAon for 2°C

112

Used to Create Society

Remaining budget Rest of humankind

Lars Boelen, World Energy Outlook 2013 – What It Doesn’t Say, Stormglas, Nov 12, 2013, ,h-p://stormglas.wordpress.com/2013/11/12/world-‐energy-‐outlook-‐2013-‐what-‐it-‐doesnt-‐say/

Very few Years Away from Reaching 2°C Carbon Budget

113

2°C Carbon Budget & Emissions Growth

114

(Annual global carbon emissions GtC by yearly emissions growth rate)

Note: the % is the chances of limiAng warming to 2°C Data: Budget -‐ IPCC WG1 ARS, Historical -‐ Global Carbon Project Note: assumes limited non-‐CO2 forcing changes (RCP 2.6) h-p://shrinktha�ootprint.com

Uncertainty pervades what decisions are made in the coming years and decades.

UNCERTAINTY

115 Source: UK Met Office, Hadley Centre, h-p://www.metoffice.gov.uk/climate-‐guide

Lost opportuniAes from inacAon in reducing CO2 emissions are esAmated to incur hundreds of trillions of dollars in future economic value foreclosed; in addiAon to hundreds of trillions of dollars in economic losses caused by increased destrucAon from extreme weather catastrophes.

Uncertainty if/when policies will avert BAU catastrophic climate impacts

116

CO2 EOR Facts

117

More than 1 billion tons of CO2 have been used for Enhanced Oil Recovery (EOR) over the past 40 years. Some 3,600 miles of pipelines acAvely transport CO2 today.

In the US, 50 CO2 pipelines currently operate, transporAng ~55 million tons of CO2 in 2010. These onshore pipelines cross 6 provincial/state boundaries and the US-‐Canada border. Much of the exisAng pipeline infrastructure in the US was built in the 1980s & 1990s for energy security reasons.

Global CCS InsAtute, The Global Status of Carbon Capture and Storage, 2013

THE GLOBAL STATUS OF CCS | 2013

75% of CO2 used in North American EOR operaAons is derived from geological structures containing vast amounts of NATURALLY OCCURRING CO2 that can be obtained relaAvely inexpensively. This readily available geologic CO2 is, in part, the reason the CO2–EOR industry developed in southern states. CAPTURED (ANTHROPOGENIC) CO2 contributes the remaining 25%, historically derived from gas processing and ferAlizer plants.

CO2 Enhanced Oil Recovery (EOR) Long-‐term Opportunity or Short-‐term Benefit?

118

National Enhanced Oil Recovery Initiative10

Journal, 2011).

Increasing CO2-EOR also stimulates the economy more broadly. Recent estimates show that expanded CO2-EOR could provide up to $12 trillion in economic benefits to the U.S. over the next three decades, based on the “multiplier effects” of oil production on economic activities (Carter, 2011). In fact, a report by the University of Texas Bureau of Economic Geology’s (TBEG) Gulf Coast Carbon Center quantifies the total economic activ-ity of oil production for Texas to be 2.9 times the value of the oil produced. In other words, almost two dollars of additional economic activity is created for every dollar of oil produced. Moreover, TBEG estimates 19 jobs for every $1 million of oil produced annually (TBEG, 2004).

An increase in oil production from EOR has the potential to reduce net crude oil imports by half and provide up to $210 billion in increased state and federal revenues by 2030. Under a robust policy, EOR could reduce the U.S. foreign trade deficit by $11-$15 billion dollars (2007 dollars) in 2020 and $120-$150 billion by 2030. Cumulatively, this reduction in oil imports would

keep $600 billion here at home, generating additional economic activity, jobs and revenues, rather than flowing out of the U.S. economy to other countries (ARI, 2010).

Regarding the benefits of EOR for reducing CO2 emissions, using CO2 captured from industrial sources to produce oil has the potential to help the United States reduce the CO2 intensity of the industrial and power generation sectors. Over the life of a project, for every 2.5 barrels of oil produced, it is estimated that EOR can safely prevent one metric ton of CO2 from entering the atmosphere.1

Current CO2 use for EOR ranges between 65 million tonnes per year (Melzer, 2012) to 72 million tonnes per year (ARI, 2011). ARI states that 55 million tonnes of CO2 come from natural sources and 17 million tonnes come from anthropogenic sources. But the potential for EOR to contribute to CO2 reduction goals is great. The volume of CO2 that could be captured and sequestered from industrial facilities and power plants to support “next generation” EOR could be 20- 45 billion metric tons (ARI, 2011).This is equal to the total U.S. CO2 pro-duction from fossil fuel electricity generation for 10 to 20 years (EPA, 2011). Figure 5 illustrates the oil production potential and CO2 demand — i.e., CO2 stored through EOR — from “next generation” EOR technologies.

Properly managed EOR projects have demonstrated that injecting CO2 into producing oil fields can safely store CO2 in geologic formations without leaking to groundwater resources or escaping to the atmosphere. EOR is governed by federal regulations that require the protection of underground sources of drinking water, under the U.S. Environmental Protection Agency’s (EPA’s) Underground Injection Control (UIC) program. Many states have obtained authority from EPA to ad-minister the UIC program and have laws that meet or go further than EPA’s requirements. Permits issued by the EPA or states require that EOR operators manage their site in a manner that will prevent CO2 (and other forma-tion fluids) from migrating out of the subsurface confin-ing formation and into drinking water aquifers (Code of Federal Regulations (CFR) 40 CFR §144).

1 Industry Sources

Source: ARI, 2011

Figure 5: Domestic Oil Supplies and CO2 Demand (Storage) Volumes from “Next Generation” CO2-EOR Technology**

*At an oil price of $85/B, a CO2 market price of $40/mt and a 20% ROR, before tax.

**Includes 2,300 million metric tons of CO2 provided from natural sources and 2.6 billion barrels already produced or being devel-oped with miscible CO2-EOR.

The potenAal volume of CO2 that could be captured and sequestered from industrial faciliAes and power plants to support “next generaAon” EOR could be 20-‐45 billion tons, equal to 1 to 2 decades of U.S. CO2 producAon from fossil fuel power plants.

*At an oil price of $85 per bbl, a CO2 market price of $40 per ton and a 20% ROR, before tax.

One ton of CO2 EOR produces 2.5 barrels of oil, which in turn, emit 1.1 tons of CO2 when combusted.

NaAonal Enhanced Oil Recovery IniAaAve (NEORI), Carbon Dioxide Enhanced Oil Recovery: A CriAcal DomesAc Energy, Economic, and Environmental Opportunity, Feb 2012

Large CO2 EOP PotenAal – but at what cost and risk?

119

16

Untapped Domestic Energy Supply and Long Term Carbon Storage Solution

A 2009 study by Advanced Resources International (ARI) for DOE assessed the role that “best practices” CO2 EOR technologies could play in U.S. oil recovery. ARI noted that introducing “best practices” technology to regions where it is currently not yet applied, lowering risks by conducting research, pilot tests and field demonstrations in geologically challenging fields, providing state production tax incentives, federal investment tax credits, and royalty relief, and establishing low-cost, reliable, CO2 supplies, could result in an additional 85 billion barrels of technically recoverable oil from the 400 billion barrels of oil remaining in large reservoirs across 11 basins.

However, many factors play a role in the suitability and economics of CO2 EOR applications—not the least of which are the price of oil and the cost and availability of CO2. Consequently, there can be a substantial gap between a “technically recoverable resource” and a proven reserve volume booked to an oil company’s balance sheet. Still, the study points to the significant potential of CO2 EOR to contribute to the nation’s future oil supply. Increasing the volume of technically recoverable domestic crude oil could help reduce the Nation’s trade deficit and enhance national energy security by reducing oil imports, add high-paying domestic jobs from the direct and indirect economic effects of increased domestic oil production and help to revitalize state economies and increase federal and state revenues via royalties, and corporate income taxes.

Carbon Dioxide Enhanced Oil Recovery

Potential Technically Recoverable Incremental Oil with “best practices” CO2 EOR Technology

NETL, CO2 Enhance Oil Recovery, 2010, NaAonal Energy Technology Laboratory

CO2 EOR is NOT CCS

120

CO2-‐EOR does not consAtute CCS, and is dissimilar enough from true commercial-‐ scale CCS it is unlikely to significantly accelerate large scale adopAon of CCS technology.

Federal subsidies promoAng energy security played the decisive role in creaAng the exisAng CO2-‐pipeline network and EOR iniAaAves, NOT for CCS.

Paul Dooley et al., CO2-‐driven Enhanced Oil Recovery as a Stepping Stone to What? July 2010, Pacific Northwest NaAonal Laboratories (PNNL).

These historically subsidized CO2 pipelines are a subsidy for any CO2-‐EOR flood that relies on them, as the new CO2 flood does not need to pay the enAre cost of delivering it to a given field. Thus, it would be prudent not to apply the same cost data to new CO2 pipelines in regions of the U.S. where there is CO2-‐EOR potenAal but no extant pipeline infrastructure.

CO2 EOR Subsidy Uncertainty

121

CO2-‐EOR currently accounts for 6 % of annual U.S. oil producAon using mostly naturally-‐occurring CO2. This is driven by the SecAon 45Q tax credit, which provides a subsidy of potenAally up to $10 per ton CO2 for no more than 75 million tCO2 from man-‐made sources used for CO2-‐EOR. The NEORI consorAum is lobbying Congress for greatly expanding the subsidy to capture nearly 4 billion of tons of CO2 from man-‐made sources that will be used to produce for EOR. NEORI argues the current subsidy is insufficient to cover the cost gap between what EOR operators are willing to pay for CO2 and the cost to capture and transport CO2 from power plants and industrial sources, as well as lacking sufficient transparency to enable CO2 capture project developers to obtain private sector investment for their projects. NEORI provide sufficient tax credits.

NEORI (NaAonal EOR InsAtute), Center for Climate SoluAons & Great Plains InsAtute, Recommended ModificaAons to the 45Q Tax Credit for CO2 SequestraAon, Feb.2012, submi-ed to USHR Ways & Means Commi-ee, April 2013

4 billion tons CO2 EOR produces ~10 billion bbls oil, which in turn, emit 4.4 billion tons of CO2 when combusted.

Long-‐term CO2 supply price Uncertainty

122

Figure 5: Illustration of supply and demand for pipeline quality CO2 and the resulting price paid under two scenarios of assumed scarcity (taken from Dooley, 2004)

If pipeline quality CO2 remains scarce, then it is reasonable to assume that the supplier (i.e., the

anthropogenic CO2 point of origin which might be different from the entity that delivers pipeline quality

CO2 at the boundary of a CO2 flood) will have some ability to set the price of pipeline quality CO2 and

receive some positive price (i.e., payment) for supplying this commodity. While potentially dated,

Norman (1994) examined the market for pipeline quality CO2 in West Texas in the early 1990s and found

the market to be oligopolistic in nature (i.e., a small number of sellers were able to control supply and

therefore influence the price paid). This is what one would expect in a market characterized by scarcity

and high barriers to entry. However when CCS systems are deployed on a large scale because of GHG

emissions constraints, a very different market structure for pipeline quality CO2 should exist. When the

supply of pipeline quality CO2 on offer significantly exceeds demand, the rents from CO2-EOR do not

accrue to the upstream supplier of CO2-EOR. Under these market conditions, while CO2-EOR may

remain profitable, the revenue streams would no longer accrue to the anthropogenic CO2 point source

supplier and the cost of capturing the CO2 would not be offset. For a more rigorous treatment of the

evolving pricing of pipeline quality CO2 for CO2-EOR in a greenhouse gas constrained world readers are

encouraged to consult Leach et al. (2009).

Page | 18


When CO2 supply is scarce relaAve to demand a posiAve price for CO2 results. But when pipeline quality CO2 is is far in excess of any potenAal then the price paid declines and eventually becomes negaAve (i.e., incurring disposal fee). XX’s current CO2 for EOR is posiAvely priced, but for how long?

CO2 EOR price Uncertainty

123

When the supply of pipeline quality CO2 on offer significantly exceeds demand, the rents from CO2-‐EOR do not accrue to the upstream supplier of CO2-‐EOR. Under these market condiAons, while CO2-‐EOR may remain profitable, the revenue streams would no longer accrue to the man-‐made CO2 point source supplier and the cost of capturing the CO2 would not be offset.


Figure 5: Illustration of supply and demand for pipeline quality CO2 and the resulting price paid under two scenarios of assumed scarcity (taken from Dooley, 2004)

If pipeline quality CO2 remains scarce, then it is reasonable to assume that the supplier (i.e., the

anthropogenic CO2 point of origin which might be different from the entity that delivers pipeline quality

CO2 at the boundary of a CO2 flood) will have some ability to set the price of pipeline quality CO2 and

receive some positive price (i.e., payment) for supplying this commodity. While potentially dated,

Norman (1994) examined the market for pipeline quality CO2 in West Texas in the early 1990s and found

the market to be oligopolistic in nature (i.e., a small number of sellers were able to control supply and

therefore influence the price paid). This is what one would expect in a market characterized by scarcity

and high barriers to entry. However when CCS systems are deployed on a large scale because of GHG

emissions constraints, a very different market structure for pipeline quality CO2 should exist. When the

supply of pipeline quality CO2 on offer significantly exceeds demand, the rents from CO2-EOR do not

accrue to the upstream supplier of CO2-EOR. Under these market conditions, while CO2-EOR may

remain profitable, the revenue streams would no longer accrue to the anthropogenic CO2 point source

supplier and the cost of capturing the CO2 would not be offset. For a more rigorous treatment of the

evolving pricing of pipeline quality CO2 for CO2-EOR in a greenhouse gas constrained world readers are

encouraged to consult Leach et al. (2009).

Page | 18

When CCS systems are deployed on a large scale because of GHG emissions constraints, a very different market structure for pipeline quality CO2 should exist.

RelaAve Risk Exposure New GeneraAon Sources

125 Source: Ron Binz, PracAcing Risk-‐Aware Electricity RegulaAon: What Every State Regulator Needs to Know, April 2012, CERES

RelaAve Cost & Risk Rankings

126

Source: Ron Binz, PracAcing Risk-‐Aware Electricity RegulaAon: What Every State Regulator Needs to Know, April 2012, CERES

Cost is an essenKal but not sufficient decision-‐making criterion

Risk is an essenKal and imperaKve decision-‐making criterion as well

Projected UKlity GeneraKon Resources RelaKve Cost & RelaKve Risk -‐ 2015

127 Source: Ron Binz, PracAcing Risk-‐Aware Electricity RegulaAon: What Every State Regulator Needs to Know, April 2012, CERES

Policies & Subsidies promote high-‐Emission investments over Zero-‐E OpAons

128

Total GlobalInvestments inRenewables

Billions of Dollars Invested

2012 Investments in Fossil Fuel Reserves Versus Clean Energy

0 100 200 300 400 500 600 700

$674

$281

Corporate Investments in Developing

Fossil Fuel Reserves

www.ceres.org www.carbontracker.org

Legacy policies, subsidies, and regulaAons (or lack thereof) conAnue to steer investments into energy opAons with high-‐emission output. The IMF esAmates $2 trillion per year worldwide in subsidies to the fossil fuel industry.

Another $4 trillion per year in economic losses are due to fossil fuel externaliAes that go unpriced or unregulated, according to esAmates by UN Finance IniAaAve. This skewing of decisionmaking creates uncertainty as to whether emissions will steeply rise (BAU) or major policy changes will occur.

Chart source: CERES & CarbonTracker, Investors ask fossil fuel companies to assess how business plans fare in low-‐carbon future -‐-‐ coaliAon of 70 investors worth $3 trillion call on world’s largest oil & gas, coal and electric power companies to assess risks under climate acAon and ‘business as usual’ scenarios, Nov 2013

Huge opportunity to eliminate coal, most gas with LCR Por�olio of efficiency, wind, solar


(LCR= Least-‐Cost-‐and-‐Risk)

Risk factor: Fuel cost comparisons

130

40

Graph 1 (http://blogs-images.forbes.com/jamesconca/files/2012/07/Fuel-Costs.jpg)

To measure the true value of power generation, one must not only take into account the

cost of the fuel but also the cost of installation/construction of the energy providing source along

with the maintenance cost over the lifespan of the resource. To calculate the cost for

construction, the following equation was used:

Total Construction cost ((MW ratting x 1000) x Useful life x (Capacity Factor X 8760)

The megawatt rating was multiplied by 1,000 to convert the energy value to kilowatts and the

8,760 was the number of hours of energy production over the course of a year. While the

production values may vary depending on the provider and area that the resource was used, the

average was taken from multiple years of costs. With all of this information, hydropower was

shown to be the cheapest but is strongly limited by the terrain requirements and the geographical

locations of the dams. Coal and nuclear are the next cheapest with wind being almost double the

price showing that while the alternative energies may be the cleaner form of energy, they are far

Vulnerability of Natural Gas to Higher Prices and VolaAlity


AccounAng for VolaAlity

132

Utility&Scale+Wind+and+Natural+Gas+Volatility+|+Rocky+Mountain+Institute+|+RMI.org+ 8!

in! the!underlying! asset’s! price,! volatility,! time! to! expiration,! and! riskbfree! interest!rate,!and!the!sensitivity!of!delta!to!changes!in!the!underlying!asset!price.!!Sensitivity!to! volatility,! as!measured!by!vega,! is! one!of! the!most! significant! factors! in!pricing!commodity! options.! ! In! fact,! implied! volatility! levels! can! be! derived! from! listed!option!premiums!to!determine!the!magnitude!of!natural!gas!movements!“pricedbin”!by! the!options!market!at!a!given! future!date! (Figure!3).! !For!example,!options!are!currently! pricing! in! a! potential! range! of! $1.18! to! $13.80! per! mmBtu! at! the! 99%!confidence!interval!by!June!2015.!!!!

!Figure! 3:! Using! implied! volatility! levels! and! option! premiums! to! determine! future! natural! gas! price!ranges!at!68%,!95%,!and!99%!confidence!intervals!

RISK+DISTRIBUTION+!Assets!generally!face!two!types!of!risk:!risk!associated!strictly!with!the!underlying!asset! (alpha),!and!risk!correlated!with! the!broader!market! (beta).! !A!positive!beta!value!represents!a!positive!correlation!with!the!broader!market,!whereas!a!negative!beta!value!represents!an! inverse!correlation.! !Calculating!the!beta!value!of!natural!gas!has!previously!been!attempted,!but!most!studies!conducting!this!analysis!were!published! over! 10! years! ago! (Table! 1).! ! It! should! be! noted,! however,! that! results!have!consistently!shown!negative!beta!values12.!!!

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!12!Bolinger,!M.!and!Wiser,!R.!LBNL!2002.!“Quantifying!the!Value!that!Wind!Power!Provides!as!a!Hedge!Against!Volatile!Natural!Gas!Prices”!

$13.80+++

++June+2015+

++++

$1.18+

Potential NYMEX Henry Hub Prices

RMI, UKlity-‐Scale Wind and Natural Gas VolaKlity: Uncovering the Hedge Value of Wind for UKliKes and Their Customers, 2012

Using implied volaKlity levels and opKon premiums to determine future natural gas prices ranges at 68%, 95% and 99% confidence intervals.

NYMEX Henry Hub Futures 68%CI 99%CI 95%CI

AccounAng for VolaAlity

133

CCGT New Build (No VolaKlity Premium included) CCGT New Build (AccounKng for VolaKlity) Wind PPA (No PTC)

AccounKng for volaKlity shows wind out-‐compeKng

gas in the long-‐term CCGT curve shics up with volaKlity

premium added

AccounKng for volaKlity shows wind out-‐compeKng gas

in the long-‐term

Low gas prices seemed to out-‐compete wind

RMI, UKlity-‐Scale Wind and Natural Gas VolaKlity: Uncovering the Hedge Value of Wind for UKliKes and Their Customers, 2012

Vulnerability of Natural Gas to Carbon Emissions Budget Cost Impacts


UCS Reference Case (BAU)

To limit some of the worst consequences of climate change, the NaAonal Research Council (NRC) recommended an economy-‐wide carbon budget for the U.S. of 170 billion metric tons of cumulaAve CO2eq emissions from 2012 to 2050 (NRC 2010). This budget would cut power sector carbon 9 % from current levels by 2050, with most of the reducAons in the first 20 years, as part of an economy-‐wide emissions reducAon goal of greater than 80% by 2050.

Vulnerability of Natural Gas to LCR opAons to meet carbon budget -‐ UCS USA case

135

UCS, Gas Ceiling, Assessing the Climate Risks of an Overreliance on Natural Gas for Electricity, Sept. 2013, Union of Concerned ScienAsts; and, Clemmer, S., J. Rogers, S. Sa-ler, J. Macknick, and T. Mai. 2013. Modeling low-‐carbon U.S. electricity futures to explore impacts on naAonal and regional water use. Environmental Research LeWers 8(1). Online at iopscience.iop.org/1748-‐ 9326/8/1/015004

Union of Concerned ScienKsts (UCS) modeled three possible electricity pathways for the United states to meet the NRC carbon budget. The no

Technology Preference pathway leads to high levels of renewables; natural gas with CCS plays a modest role. The renewables and efficiency pathway leads to the least-‐cost-‐risk (LCR) consumer electricity bills. Natural gas plays a more

limited long-‐term role in all three pathways compared with the reference Case.

Vulnerability of Natural Gas to lower-‐cost-‐and-‐risk (LCR) opAons – PJM power pool case

136 Cory Budischak et al, Cost-‐minimized combinaAons of wind power, solar power and electrochemical storage, powering the grid up to 99.9% of the Ame , Journal of Power Sources 225 (2013) 60e74

Univ. of Delaware engineers modeled wind, solar, and storage to meet demand for 1/5 of the US electric grid (PJM). 28 billion combinaAons of wind, solar and storage were simulated to derive least-‐cost. Least-‐cost combinaAons have excess generaAon (3X load), thus minimizing more expensive storage. 99.9% of hours of load can be met by renewables with only 9 to 72 hours of storage. At 2030 technology costs, 90% of load hours are met at electric costs below today’s.

Cost-minimized combinations of wind power, solar power and electrochemicalstorage, powering the grid up to 99.9% of the time

Cory Budischak a,b,*, DeAnna Sewell c, Heather Thomson c, Leon Mach d, Dana E. Veron c,Willett Kempton a,c,e

aDepartment of Electrical and Computer Engineering, University of Delaware, Newark, DE 19716, USAbDepartment of Energy Management, Delaware Technical Community College, Newark, DE 19713, USAcCenter for Carbon-Free Power Integration, School of Marine Science and Policy, College of Earth Ocean and Environment, University of Delaware, Newark, DE 19716, USAd Energy and Environmental Policy Program, College of Engineering, University of Delaware, Newark, DE 19716, USAeCenter for Electric Technology, DTU Elektro, Danmarks Tekniske Universitet, Kgs. Lungby, Denmark

h i g h l i g h t s g r a p h i c a l a b s t r a c t

< We modeled wind, solar, andstorage to meet demand for 1/5 ofthe USA electric grid.

< 28 billion combinations of wind,solar and storage were run, seekingleast-cost.

< Least-cost combinations have excessgeneration (3! load), thus requireless storage.

< 99.9% of hours of load can be met byrenewables with only 9e72 h ofstorage.

< At 2030 technology costs, 90% ofload hours are met at electric costsbelow today’s.

a r t i c l e i n f o

Article history:Received 7 June 2012Received in revised form13 September 2012Accepted 15 September 2012Available online 11 October 2012

Keywords:Variable generationRenewable energyElectrochemical storageHigh-penetration renewables

a b s t r a c t

We model many combinations of renewable electricity sources (inland wind, offshore wind, andphotovoltaics) with electrochemical storage (batteries and fuel cells), incorporated into a large gridsystem (72 GW). The purpose is twofold: 1) although a single renewable generator at one site producesintermittent power, we seek combinations of diverse renewables at diverse sites, with storage, that arenot intermittent and satisfy need a given fraction of hours. And 2) we seek minimal cost, calculating truecost of electricity without subsidies and with inclusion of external costs. Our model evaluated over 28billion combinations of renewables and storage, each tested over 35,040 h (four years) of load andweather data. We find that the least cost solutions yield seemingly-excessive generation capacitydattimes, almost three times the electricity needed to meet electrical load. This is because diverse renew-able generation and the excess capacity together meet electric load with less storage, lowering totalsystem cost. At 2030 technology costs and with excess electricity displacing natural gas, we find that theelectric system can be powered 90%e99.9% of hours entirely on renewable electricity, at costs compa-rable to today’sdbut only if we optimize the mix of generation and storage technologies.

! 2012 Published by Elsevier B.V.

* Corresponding author. Department of Energy Management, Delaware Technical Community College, 400 Stanton-Christiana Road, Newark, DE 19713, USA. Tel.: þ1 302453 3099; fax: þ1 302 368 6620.

E-mail address: [email protected] (C. Budischak).

Contents lists available at SciVerse ScienceDirect

Journal of Power Sources

journal homepage: www.elsevier .com/locate/ jpowsour

0378-7753/$ e see front matter ! 2012 Published by Elsevier B.V.http://dx.doi.org/10.1016/j.jpowsour.2012.09.054

Journal of Power Sources 225 (2013) 60e74

Load met with renewable generaKon & storage 99.9% of hours over 4 years; fossil backup needed on only five occasions.

39

The methods just described for reducing energy use and improving efficiency of buildings can be incorporated into a microgrid, which is a self-contained combined heat and power (CHP) system for a community, hospital, industrial or military complex, or city block. Microgrids, which generally produce less than 50 MW of power, are attractive because they are not centrally planned by a power utility and they reduce reliance on long-distance transmission and offer protection against large-scale grid failure. The main drawback is that, with a small CHP system, matching electric power demand with supply is often more difficult than with a big system with more generators. However, by combining electric power generation with thermal storage, such as described above, this problem can be reduced or eliminated. In many cases, the microgrid can rely on the regular grid for backup as well. 12. Timeline for Implementation of the Plan Figure 5 shows one timeline scenario for the implementation of this plan in California. Other scenarios are possible. Figure 5. Change in percent distribution of California energy supply for all purposes (electricity, transportation, heating/cooling, industry) among conventional fuels and WWS energy over time based on the roadmap proposed here. Total power demand decreases over time due to energy reductions due to conversion to WWS and efficiency. The percentages above the fossils plus nuclear curve are of remaining penetration of those energy sources each decade. The percentages next to each WWS source are the final estimated penetration of the source. The 100% demarcation indicates that 100% of all-purpose power is provided by WWS technologies by 2050, and the power demand by that time has decreased. Neither the percentages each year nor the final percentages are exact – they are estimates of one possible scenario.

Vulnerability Natural Gas to LCR opKons to meet carbon

budget in CALIFORNIA

137 Mark Jacobson et al, EvaluaKng the Technical and Economic Feasibility of Repowering California for all Purposes with Wind, Water, and Sunlight, Energy Policy Journal,May 2013.

MulA-‐university team modeled an all-‐renewable power system for California, with natural gas serving as back-‐up reserve during peak periods. System capaciAes are 74 GW of wind, 26 GW of CSP, 28 GW of solar PVs, 5 GW of geothermal, 21 GW of hydroelectric, and 25 GW of natural gas.

17

Notes: System capacities are 73.5 GW of wind, 26.4 GW of CSP, 28.2 GW of photovoltaics, 4.8 GW of geothermal, 20.8 GW of hydroelectric, and 24.8 GW of natural gas. Transmission and distribution losses are 7% of the demand. The least-cost optimization accounts for the day-ahead forecast of hourly resources, carbon emissions, wind curtailment, and 8-hour thermal storage at CSP facilities, allowing for the nighttime production of energy by CSP. The hydroelectric supply is based on historical reservoir discharge data and currently imported generation from the Pacific Northwest. The wind and solar supplies were obtained by aggregating hourly wind and solar power at several sites in California estimated from wind speed and solar irradiance data for those hours applied to a specific turbine power curve, a specific concentrated solar plant configuration (parabolic trough collectors on single-axis trackers), and specific rooftop PV characteristics. The geothermal supply was increased over 2005 but limited by California's developable resources. . Natural gas capacity (grey) is a reserve for backup when needed and was not actually needed during the two simulation days. Source: Hart and Jacobson (2011). 6.B. Using Demand-Response Grid Management to Adjust Demand to Supply Demand-response grid management involves giving financial incentives to electricity users and developing appropriate system controls to shift times of certain electricity uses, called flexible loads, to times when more energy is available. Flexible loads are electricity demands that do not require power in an unchangeable minute-by-minute pattern, but instead can be supplied in adjustable patterns over several hours. For example, electricity demands for a wastewater treatment plant and for charging BEVs are flexible loads. Electricity demands that cannot be shifted conveniently, such as electricity use for computers and lighting, are inflexible loads. With demand-response, a utility may establish an agreement with (for example) a flexible load wastewater treatment plant for the plant to use electricity during only certain hours of the day in exchange for a better electricity rate. In this way, the utility can shift the time of demand to a time when more supply is available. Similarly, the demand for electricity for BEVs is a flexible load because such vehicles are generally charged at night, and it is not critical which hours of the night the electricity is supplied as long as the full power is provided sometime during the night. In this case, a utility can contract with users for the utility to provide electricity for the BEV when wind is most available and reduce the power supplied when it is least available. Utility customers would sign up their BEVs under a plan by which the utility controlled the supply of power to the vehicles (primarily but not necessarily only at night) in exchange for a lower electricity rate. 6.C. Oversizing WWS to Match Demand Better and Provide Hydrogen and District Heat

17

Notes: System capacities are 73.5 GW of wind, 26.4 GW of CSP, 28.2 GW of photovoltaics, 4.8 GW of geothermal, 20.8 GW of hydroelectric, and 24.8 GW of natural gas. Transmission and distribution losses are 7% of the demand. The least-cost optimization accounts for the day-ahead forecast of hourly resources, carbon emissions, wind curtailment, and 8-hour thermal storage at CSP facilities, allowing for the nighttime production of energy by CSP. The hydroelectric supply is based on historical reservoir discharge data and currently imported generation from the Pacific Northwest. The wind and solar supplies were obtained by aggregating hourly wind and solar power at several sites in California estimated from wind speed and solar irradiance data for those hours applied to a specific turbine power curve, a specific concentrated solar plant configuration (parabolic trough collectors on single-axis trackers), and specific rooftop PV characteristics. The geothermal supply was increased over 2005 but limited by California's developable resources. . Natural gas capacity (grey) is a reserve for backup when needed and was not actually needed during the two simulation days. Source: Hart and Jacobson (2011). 6.B. Using Demand-Response Grid Management to Adjust Demand to Supply Demand-response grid management involves giving financial incentives to electricity users and developing appropriate system controls to shift times of certain electricity uses, called flexible loads, to times when more energy is available. Flexible loads are electricity demands that do not require power in an unchangeable minute-by-minute pattern, but instead can be supplied in adjustable patterns over several hours. For example, electricity demands for a wastewater treatment plant and for charging BEVs are flexible loads. Electricity demands that cannot be shifted conveniently, such as electricity use for computers and lighting, are inflexible loads. With demand-response, a utility may establish an agreement with (for example) a flexible load wastewater treatment plant for the plant to use electricity during only certain hours of the day in exchange for a better electricity rate. In this way, the utility can shift the time of demand to a time when more supply is available. Similarly, the demand for electricity for BEVs is a flexible load because such vehicles are generally charged at night, and it is not critical which hours of the night the electricity is supplied as long as the full power is provided sometime during the night. In this case, a utility can contract with users for the utility to provide electricity for the BEV when wind is most available and reduce the power supplied when it is least available. Utility customers would sign up their BEVs under a plan by which the utility controlled the supply of power to the vehicles (primarily but not necessarily only at night) in exchange for a lower electricity rate. 6.C. Oversizing WWS to Match Demand Better and Provide Hydrogen and District Heat

Vulnerability of Natural Gas to Water Demand from Wellhead to Power Plant

139

Environ. Res. Lett. 8 (2013) 015004 S Clemmer et al

Figure 5. Electricity generation in the southeast, by scenario. For purposes of this analysis, the region includes Mississippi, Alabama,Tennessee, Georgia, South Carolina, North Carolina, and Virginia. Scenario 1, reference case; scenario 2, carbon budget, no technologytargets; scenario 3, carbon budget with coal with CCS and nuclear targets; scenario 4, carbon budget with efficiency and renewable energytargets. Bus-bar demand is the amount of energy that needs to be delivered from the point of generation. Gas includes combustion turbineand combined cycle (CC) plants. Solar photovoltaics (PV) include residential, commercial, and utility scale systems.

Figure 6. National electricity sector water consumption, byscenarios. Scenario 1, reference case; scenario 2, carbon budget, notechnology targets; scenario 3, carbon budget with coal with CCSand nuclear targets; scenario 4, carbon budget with efficiency andrenewable energy targets.

trajectory until 2030, as conventional coal plant retirementsreduce consumptive uses. They then diverge, as consumptionincreases slightly between 2030 and 2050 under scenario2 as a result of building new natural gas combined cycleplants with CCS and continues to steadily decline under

scenario 4 due to a reduction in electricity demand andincreased penetration of renewable technologies. For scenario4, the result is a reduction of 1.1 trillion gallons (85.2%) by2050 from 2010 levels. For more detailed results on waterwithdrawals and consumption at the national and regionallevel, see Macknick et al (2012).

3.4. National electricity and natural gas costs

Because we modeled a carbon budget and specific technologytargets in scenarios 2–4, showing how those scenariosimpact consumer energy costs can provide policy-relevantinformation to decision makers. Average consumer electricityprices, for example, rise under the reference case, but risemore sharply under scenarios 2, 3, and 4, with scenario 3producing the highest prices (figure 7). Changes in overallconsumer electricity bills (price times usage), arguably a moreimportant measure of the economic impact to consumers, varymore dramatically. Both scenarios 2 and 3 show increasesin consumer electricity bills consistent with the respectiverate increases because there is little projected change inconsumer electricity use under these scenarios. In contrast,consumer electricity bills under scenario 4 drop below thereference case because of energy efficiency investments(figure 8). Because of natural gas’s importance outside of the

8

NaAonal electricity sector water consumpAon, by scenarios. Scenario 1, reference case; scenario 2, carbon budget, no technology targets; scenario 3, carbon budget with coal with CCS and nuclear targets; scenario 4, carbon budget with efficiency & renewable energy targets.

, Clemmer, S. et al. 2013. Modeling low-‐carbon U.S. electricity futures to explore impacts on naAonal and regional water use. Environmental Research LeWers 8(1), iopscience.iop.org/1748-‐ 9326/8/1/015004

All thermal power plants, whether fossil, nuclear or solar-‐thermal-‐electric, use water for cooling. In sharp contrast, wind, solar PV and solar-‐electric dishes require 95% less water to operate.

The power sector uses 45% of total U.S. water withdrawals. With expanding demand for both power and water, rising prices for water is occurring. So is increased price volaKlity, given weather-‐triggered water shortages.

Water-‐stressed states like Arizona now mandate air-‐cooling for new power plants, which is more expensive.

CCS nearly doubles the amount of water required.

Vulnerability of Shale Gas Wells to Water Demand and Disposal Costs

140

HF shale gas wells vary in water demand by a factor of four depending on a number of parameters (see next slide). EPA esAmates the 35,000 oil and gas wells operaAng in 2011 consumed 70 to 140 billion gal. water per year. About the water use in 40 to 80 ciAes with populaAons of 50,000 people, or 1 to 2 metropolitan areas with 2.5 million pop. each.

Clark, CE, Horner RM, and Harto, CB. Life Cycle Water ConsumpAon for Shale Gas and ConvenAonal Natural Gas, Environ. Sci. Technol., 2013, 47 (20), pp. 11829–11836; Dram Plan to Study the PotenAal Impacts of Hydraulic Fracturing on Drinking Water Resources, Office of Research and Development U.S. Environmental ProtecAon Agency Washington, D.C. February 7, 2011, Report EPA/600/D-‐11/001

Results - Fuel

� Variability and uncertainty within plays is as great or greater than between plays � While recycling is important in many plays from a water management standpoint,

low flowback rates limit the impact on total water requirements

Key Parameters for Life Cycle Water Analysis Associated with Natural Gas

141 Christopher Harto, Corrie Clark, Todd Kimmell, and Robert Horner, Water consumpAon for fossil fuel exploraAon and producAon, Argonne NaAonal Laboratory, Groundwater ProtecAon Council Annual Forum St. Louis, MO, September 23-‐25, 2013

Key Parameters

Parameter

unit

Shale Play

conventional

source

Barnett

Fayetteville

Haynesville

Marcellus

Well lifetime years 30 30 30 30 30 Industry and Argonne Assumption

Bulk gas methane content % 80 (40–97) 80 (40–97) 80 (40–97) 80 (40–97) 85 (69–95) Ref. 4

Hydraulic fracturing jobs per well jobs/well

1 for low EUR 3 for high

EUR 1 for low EUR, 3 for high EUR

1 for low EUR, 3 for high EUR

1 for low EUR, 3 for high EUR –a Argonne

assumption

Estimated ultimate recovery BCF/well 1.4–3.0 1.7–2.6 3.5–6.5 1.4–5.2 0.79–1.25

Shale: Refs. 5, 6 Conv.: Refs. 7, 8

Water for drilling gal/well 240,000 170,000 280,000 180,000 78,000–110,000

Assumptions based upon well designs: Refs. 9, 10

Water for cement gal/well 27,000 19,000 37,000 24,000 7,200–9,800 Assumptions based upon well designs: Refs. 9, 10

Water for hydraulic fracturing gal/job 1,800,000–

6,200,000 3,700,000–6,700,000

3,400,000–8,800,000

2,600,000–5,800,000 –a Sampled from:

Ref. 11 Flowback fraction (0–10 days)

gal flowback/ gal/job 0.2 0.1 0.05 0.1 –a Ref. 12

Recycled fraction gal recycled /gal flowback 0.20 0.20 0.00 0.95 –a Ref. 12

Water for gas processing gal/mmBtu 1.67 Ref. 13

Water for pipeline operation gal/mmBtu 0.84 Ref. 13

Water for electricity for gas compression gal/SCF 0.005–0.007 Ref. 14

a Not applicable. Hydraulic fracturing was not assumed for the conventional natural gas life cycle pathway.

See Paper linked on slide 10 for references

Ranges of wastewater & consumpAve freshwater use in 3 shale plays:

142

The Next Frontier in United States Shale Gas and Tight Oil Extraction: Strategic Reduction of Environmental Impacts

52

Figure 17. Estimated reductions in fresh water consumption and wastewater production using optimized completions for a typical well in each of the three focus plays. Bars are bounded by low case and high case estimates. In each of the low cases, an injection volume reduction of 10% is assumed; in the high cases, 20%. Note that the indicated fresh water consumption values account for average regional intra-operator rates of recycling; that is, water that is sourced from operators’ recycled stores is not included.

Estimated reduction in water transport-related carbon dioxide emissions using optimized completions

The industrial-scale operations on a hydraulically fractured horizontal well site require several

hundred truck trips for water-related supplies and equipment alone (NY DEC 2011, Prozzi 2011). A

reduction in water volume via an optimized completion would be accompanied by a proportionate

reduction in truck trips and associated carbon dioxide emissions. To model emissions reductions

stemming from reduced water usage, we assumed that all water transport is via truck rather than pipeline,

as this is the dominant practice in all three plays.28 All truck trips are modeled as two-way; trips both to

and from the well site are included. Fuel economy is assigned as the average across all commercial-

weight truck classes from 2000-2010 (US DOE 2012); differences in miles per gallon based on freight are

ignored. It was assumed that completions additives, such as fracturing chemicals and sand, vary

proportionally with injected water volume, but that completions equipment (e.g., trucks and tanks) does

28 Relative to trucking, piping would almost certainly reduce the carbon cost of all water transportation, though this would depend on site topography and transport distance. In addition, spill risk concerns exist for the piping of wastewater.

Clark, CE, Horner RM, and Harto, CB. Life Cycle Water ConsumpAon for Shale Gas and ConvenAonal Natural Gas, Environ. Sci. Technol., 2013, 47 (20), pp 11829–11836

Impact of natural gas fuel source & power plant type on lifecycle water consumpAon for electricity generaAon.

143

scenario and the second lowest in the maximum scenario. TheEUR and the volume of fracturing fluid required appear to havethe greatest impact on the life cycle water consumption per unitof energy produced. While the recycling of flowback water isoften cited as a means to reduce the water footprint of shale,these results show the effect to be relatively small. This holdseven for the Marcellus shale where 95% of flowback water wasassumed to be recycled, due to the limited quantity of flowbackwater recovered. These numbers could be increased if allproduced water collected over the lifetime of the well werecollected and reused, but this introduces the logistical challengeof collecting and aggregating smaller volumes of water fromhundreds or thousands of wells across a play that may not bepractical or economical.Life Cycle Water Consumption for Natural Gas versus

Other Vehicle Fuels. Although natural gas can be combusteddirectly with no additional water consumption, additional wateris likely needed if the end use of the gas is a vehicle tank. In thecase of natural gas vehicles, the natural gas may first becompressed via an electric compressor prior to entering thevehicle tank. The electricity required for this compressionconsumes 0.6−0.8 L of water for cooling per LGE (18.3−25.5L/GJ) for both natural gas pathways).22 This is incorporatedinto the total life cycle water consumption for natural gas foundin Figure 2.Of the fuels evaluated, conventional natural gas consumes the

least amount of water over its life cycle with 0.88−1.12 Lconsumed per LGE. Shale natural gas consumes slightly more,ranging from a minimum of 0.99 L/LGE in the Haynesvilleshale to a maximum of 2.02 L/LGE in the Fayetteville shalewhen not accounting for flowback water recycling (SI TableS1). Both natural gas pathways ultimately consume less waterthan conventional gasoline or the other alternatives reported inFigure 2. Variations in water consumption estimates forgasoline are primarily due to the crude oil production stage,where water consumption is highly dependent upon the age ofthe oil well, the type of recovery technology in place, and theextent that formation water or alternative water is recycled andreused.39 Because the majority of wells in Saudi Arabia areyounger and require less injection water to maintain wellpressure than U.S. wells, less water is consumed.39 The fuel thatconsumes the most water per LGE is corn ethanol due to theirrigation requirements for growing corn, which depend onlocation and regional climate.39 Ethanol produced fromswitchgrass requires considerably less water than corn ethanoldue to an assumption of no irrigation. The majority of waterconsumption for switchgrass ethanol occurs during theproduction stage at the refinery. Similarly, while water isconsumed for mining, washing, and transporting coal, Fischer−Tropsch diesel (FTD) produced from coal gasificationconsumes the majority of its water during liquids production.Although water is used directly in the Fischer−Tropschprocess, the majority of water consumption for FTD is dueto cooling water losses at the plant.40

Life Cycle Water Consumption for Natural GasElectricity Generation versus Other Fuels. A large andgrowing quantity of natural gas is consumed for electricitygeneration. A few recent papers have analyzed waterconsumption for electricity production across technologiesand have found that water consumption for natural gas powerplants is on the low end of the range for conventionalthermoelectric power generation.41−43 To differentiate thisanalysis from those studies, the impact of natural gas fuel source

on the life cycle water consumption across different natural gaspower plant types was evaluated and is shown in Figure 3.

The results of this analysis show that the addition of waterconsumption for fuel production adds incrementally to the totallife cycle impact; the effect, however, is much smaller than thatof the power plant type. In most cases, the variability in waterconsumption from the fuel type is less than the variability inwater consumption for the same power plant type shown inTable 2. While the water consumption for combustion turbinesand power plants utilizing once-through cooling is on the lowend, these power plants have significant drawbacks. Theefficiency of combustion turbines is low, leading to muchhigher fuel consumption and operating costs. This makes themonly suitable for short-term operation to meet peak load. Once-through cooling systems reduce water consumption at the costof significant water withdrawals. High water withdrawal ratesintroduce their own ecological impacts, including, but notlimited to, entrainment, entrapment, and increased temper-atures near the discharge location.The majority of new natural gas power plants being built are

high-efficiency combined-cycle plants utilizing recirculatingcooling. Switching to shale gas from conventional natural gasin one of these plants would result in an average increase of 7%in life cycle water consumption. Macknick et al., however,showed that these power plants have the lowest waterconsumption among all power plant types utilizing recirculatingcooling, with just over half the water consumption of the mostwater efficient coal power plants, and less than one-third thewater consumption of a nuclear power plant when utilizing thesame cooling technology.41 Because of this, the net effect of ashift to increased reliance on natural gas power generation fromshale gas is likely to be positive in terms of overall waterconsumption. The incremental increase in water consumptionfrom shale gas production should be more than offset by thesignificantly lower operational water consumption from naturalgas power plants relative to the other power generationtechnologies that they are likely to displace.

■ IMPLICATIONSThe production of shale gas is more water intensive thanconventional natural gas, primarily due to water consumptionfor hydraulic fracturing. How much more water intensive variessignificantly both across plays and within each play. The

Figure 3. Impact of natural gas fuel source and power plant type onlife cycle water consumption for electricity generation.

Environmental Science & Technology Article

dx.doi.org/10.1021/es4013855 | Environ. Sci. Technol. XXXX, XXX, XXX−XXXF

Clark, CE, Horner RM, and Harto, CB. Life Cycle Water ConsumpAon for Shale Gas and ConvenAonal Natural Gas, Environ. Sci. Technol., 2013, 47 (20), pp 11829–11836

The addiAon of water consumpAon for fuel producAon adds incrementally to the total life cycle impact; the effect, however, is much smaller than that of the power plant type. In most cases, the variability in water consumpAon from the fuel type is less than the variability in water consumpAon for the same power plant type.

fracturing improves the flow of gas by creating fracturepathways. The fracture fluid for shale formations is typicallywater based and contains a proppant and chemical additives.The amount of water and the fluid constituents used forhydraulic fracturing vary according to the geology and thespecific characteristics of the fracturing techniques used,including the length of the lateral portion of the well and thenumber of fracture stages.Typical water volumes required for hydraulic fracturing in

each play were estimated from industry-reported data obtainedfrom the FracFocus.org Web site.18 FracFocus is a nationalregistry of hydraulic fracturing chemical data operated by theGround Water Protection Council (GWPC) and the InterstateOil and Gas Compact Commission (IOGCC). FracFocus dataare entered either voluntarily by operators or in accordancewith state chemical disclosure laws. In addition to chemicalinformation, FracFocus also includes the volume of water usedto hydraulically fracture each well.FracFocus data are not available in an aggregated format.

Data for each well are stored separately in a portable documentformat (PDF). This analysis relied upon a data set madeavailable by Skytruth. The data set consists of data reported in2012 to FracFocus, and contains hydraulic fracturing data foractivities completed in 2011 and 2012.19 Wells were selectedgeographically by county for the four plays of interest. The datawere screened to remove hydraulic fracturing jobs that mayhave been performed on vertical wells in the area, and toremove obvious typos or erroneous entries (included onlywater volumes above 500 000 gallons and below 20 000 000gallons). The total number of wells evaluated for each playvaried from 1124 for the Haynesville play to 1705 for theBarnett play (see SI Table S2 for summary statistics for eachplay). The range of water consumption shown in Table 1 wasdefined as plus or minus one standard deviation away from theaverage for each play (see SI Figure S4 for histograms). Overall,the average water requirements for each play estimated by thismethod, particularly for the Haynesville and Fayetteville plays,are slightly higher than the range of values presented by othersources.9,28

Management of Flowback Water. Another componentof fracturing a well is the management of flowback water andproduced water. Flowback water is the water that is producedfrom the well immediately after hydraulically fracturing the welland before commencing gas production; produced water iswater that is produced along with the gas over the life of thewell. Outside of the Marcellus play, flowback water is collectedand typically disposed of through underground injection.Within the Marcellus region, however, flowback water iscollected and typically reused in hydraulic fracturing activities.For the Marcellus, 95% of flowback was assumed to be recycledbecause of the long-distance transport requirements to disposeof the fluid via injection wells. For the other plays, whereinjection wells are located nearby, recycle rates were assumed tobe 20% of flowback for the Barnett and Fayetteville plays and0% for the Haynesville play.20 The total volume of recycledfluid depends on the amount of fluid that flows back up the wellafter hydraulic fracturing, which varies considerably among thedifferent shale plays. For this study, flowback fractions andrecycle fractions were based upon input from industry experts.Flowback fractions for the Marcellus shale fall within estimatesreported by others.27,29

Data for Natural Gas Processing, Transmission, andUse. Downstream from the recovery stage, natural gas passes

through a processing stage in which it is purified for pipelinetransportation. The processed natural gas enters the trans-mission and storage stage, where natural gas is moved longdistances through high-pressure pipelines. Compressor stationfacilities are located along the transmission pipeline network toforce the gas through the large-diameter pipes. After trans-mission through such pipelines, gas may be stored under-ground, liquefied, and stored in aboveground tanks, and/ordistributed to customers for use. All of these steps consumewater, primarily for cooling.30 Estimates for this water use aretaken from a widely cited paper by Gleick,21 as indicated inTable 1. This paper is dated, and the values for these processesare poorly supported. However, there are few alternativesources for data on these processes. It is recognized that there isa high level of uncertainty in applying these numbers tomodern practices, and new primary data are needed to betterunderstand the water consumption from natural gas transportand processing.Because this study examines transportation as a specific end

use for natural gas, water used for the compression of naturalgas into vehicle tanks was also considered. To compare theenergy content of natural gas to that of gasoline fortransportation use (assuming 3% ethanol blend), a conversionof 32 000 GJ/LGE was used.31 Table 2 gives the parametersused to compare the impact of natural gas fuel source on waterconsumption for electricity generation.

■ RESULTS AND DISCUSSION OF WATERCONSUMPTION

The life cycle water consumption of both shale andconventional natural gas pathways was evaluated according tothree functional unitsL/GJ produced, L/LGE, and L/kWh ofelectricity generated. The results in L/GJ are displayed by lifecycle stage, and overall water consumption in L/LGE iscompared to that for other transportation fuels. The results inL/kWh are presented across natural gas fuel sources and powerplant types. Parameter variability and uncertainty are discussed,and some key factors affecting water consumption estimates areidentified.

Water Consumption by Life Cycle Stage. An overviewof water consumption for the shale gas and conventional gas lifecycles per GJ is presented in Figure 1. Results are presented bylife cycle stage and utilize the minimum and maximumparameter values in Table 1 to illustrate the range ofuncertainty and variability among wells within each play. The

Table 2. Power Plant Water Use Parameters

plant type cooling typepower plantefficiencya

operational waterconsumption (L/kWh)b

steam turbine(ST)

once through(OT)

32.3 1.1−1.3 (1.2)

recirculating(RC)

32.3 1.8−2.6 (2.2)

combustionturbine (CT)

NAc 29.5 0.19

combined cycle(CC)

once through(OT)

44.9 0.38

recirculating(RC)

44.9 0.68−1.2 (0.91)

aBased on higher heating value (HHV) Source: ref 32. bRange ofliterature values; value in parentheses is average value used in analysis.Sources: refs 21, 33−38. cNA, do not require water for cooling butoften require water for emission control.

Environmental Science & Technology Article

dx.doi.org/10.1021/es4013855 | Environ. Sci. Technol. XXXX, XXX, XXX−XXXD

Power Plant Water Use Parameters

a Based on higher heaAng value (HHV) Source. b Range of literature values; value in parentheses is average value used in analysis. c NA, do not require water for cooling but omen require water for emission control.

Slide&4&Labyrinth&Consul4ng&Services,&Inc.& South&Texas&Money&Management&

Shale&Plays&Discussed&In&This&Presenta4on&

EsAmates of water use for hydraulic fracturing vary (median values)

144

2.8 million gal per horizontal well for the Barne- 4.3 million gal for the Eagle Ford 5.7 million gal for Texas porAon of the Haynesville 4.5 million gal for the Marcellus

While statewide water use for shale gas development is expected to be less than 1% of total water withdrawals in Texas, local impacts may vary depending upon seasonal water availability, wastewater management strategies, and compeAng demands.

Clark, CE, Horner RM, and Harto, CB. Life Cycle Water ConsumpAon for Shale Gas and ConvenAonal Natural Gas, Environ. Sci. Technol., 2013, 47 (20), pp 11829–11836.

WasteWater ContaminaAon A Mountain or a Molehill?

145

“…with over 20,000 shale wells drilled from 2001-‐2010, the environmental record of shale gas development has for the most part been a good one— only 43 ‘widely reported’ water contaminaAon incidents-‐-‐ but it is important to recognize the inherent risks and the damage that can be caused by just one poor operaAon.... In the studies surveyed, no incidents are reported which conclusively demonstrate contaminaAon of shallow water zones with fracture fluids.” MIT Gas Report 2011, Massachuse-s InsAtute of Technology

7

recycling. Innovative water management solutions are required to address the long-term sustainability of water use in shale gas production.

Water movementsThe volume of equipment, materials and water required to support shale gas operations presents a significant logistics challenge. Given the remote nature of most locations and the frequent operations movements across highly dispersed and numerous well site locations, flexibility is required in the transport model making road transport the logistics model of choice for most environments. While pipeline and rail movements can be effective for long- distance or point-to-point movements, the final distribution to and from the well pad is almost exclusively managed via road transport. Road transport volumes and types vary significantly depending on the operational phase of the project, with the majority of demand during the fracking and completion phases, which can account for 60–85 percent of total transport volumes. Some large operations are required to source, plan and manage up to 300 truck movements per day within a single basin, which is the equivalent of a pan-regional transport operation in many other sectors. This concentration creates significant challenges, with on-site congestion causing issues to the operations teams and local residents, and leading to significant cost exposure to an already marginal cost operation.

The high volume and intensity of road transport associated with shale gas production present some unique challenges for operators. A shortage of transport operators with sufficient knowledge, difficulties in tracking and optimizing delivery schedules, reducing burden on strained road infrastructure, and a lack of standardized reporting and regulatory data can all lead to high costs, Health Safety Security Environment (HSSE) exposure, and regulatory compliance issues. With up to 30 percent of completion costs related to transportation, operators are exploring different options to reduce transport activity, with a key focus on water hauling, which

can represent up to 80 percent of logistics activity. Research into water-free fracking, on-site treatment and disposal and assessment of alternative modes of transport are all being pursued, but are currently unable to generate significant impact. Within the boundaries of current capabilities, the adoption and integration of logistics leading practice provide the most straightforward, technology-ready approach to reducing transport cost and regulatory and HSSE exposure.

Improvements in water movements also have an impact on other aspects of shale operations, specifically HSSE exposure, operational performance and compliance.

HSSE exposureImproved transport planning processes and systems can reduce the number of truck moves, while telematics systems can provide real-time visibility of truck movements and driver performance, supporting reduction in wait times, less congestion and better driver HSSE compliance.

Operational performanceBetter monitoring and planning capabilities will reduce bottlenecks and smooth delivery into a site (e.g., managed slot windows, dynamic re-routing to avoid congestion). Availability of accurate operational data can allow operators to identify issues and enable continuous improvement in both drilling and transportation. Logistics costs can be reduced through efficiency gains (e.g., reduction of waiting time) and automated processes can reduce administrative costs. Past implementations have shown that consistent adoption of logistics leading practices can deliver up to 45 percent reduction in transport costs.

ComplianceThe use of a water inventory monitoring tool can support water management regulatory compliance through visibility of water draw, usage and movements. Automated end-to-end processes and systems enable accurate and rapid data capture, storage and reporting. A cross-operator, basin-wide solution would also confirm consistent basin-wide reporting standards across multiple sites and operators.

Groundwater contamination

On-site surface spills

Water withdrawal and air quality issues, and blowouts

Off-site disposal issues

48%

33%

10%

9%

Figure 2. Chart of water contamination incidents related to gas well drilling.

Source: Massachusetts Institute of Technology 2011 Gas Report.

7

recycling. Innovative water management solutions are required to address the long-term sustainability of water use in shale gas production.

Water movementsThe volume of equipment, materials and water required to support shale gas operations presents a significant logistics challenge. Given the remote nature of most locations and the frequent operations movements across highly dispersed and numerous well site locations, flexibility is required in the transport model making road transport the logistics model of choice for most environments. While pipeline and rail movements can be effective for long- distance or point-to-point movements, the final distribution to and from the well pad is almost exclusively managed via road transport. Road transport volumes and types vary significantly depending on the operational phase of the project, with the majority of demand during the fracking and completion phases, which can account for 60–85 percent of total transport volumes. Some large operations are required to source, plan and manage up to 300 truck movements per day within a single basin, which is the equivalent of a pan-regional transport operation in many other sectors. This concentration creates significant challenges, with on-site congestion causing issues to the operations teams and local residents, and leading to significant cost exposure to an already marginal cost operation.

The high volume and intensity of road transport associated with shale gas production present some unique challenges for operators. A shortage of transport operators with sufficient knowledge, difficulties in tracking and optimizing delivery schedules, reducing burden on strained road infrastructure, and a lack of standardized reporting and regulatory data can all lead to high costs, Health Safety Security Environment (HSSE) exposure, and regulatory compliance issues. With up to 30 percent of completion costs related to transportation, operators are exploring different options to reduce transport activity, with a key focus on water hauling, which

can represent up to 80 percent of logistics activity. Research into water-free fracking, on-site treatment and disposal and assessment of alternative modes of transport are all being pursued, but are currently unable to generate significant impact. Within the boundaries of current capabilities, the adoption and integration of logistics leading practice provide the most straightforward, technology-ready approach to reducing transport cost and regulatory and HSSE exposure.

Improvements in water movements also have an impact on other aspects of shale operations, specifically HSSE exposure, operational performance and compliance.

HSSE exposureImproved transport planning processes and systems can reduce the number of truck moves, while telematics systems can provide real-time visibility of truck movements and driver performance, supporting reduction in wait times, less congestion and better driver HSSE compliance.

Operational performanceBetter monitoring and planning capabilities will reduce bottlenecks and smooth delivery into a site (e.g., managed slot windows, dynamic re-routing to avoid congestion). Availability of accurate operational data can allow operators to identify issues and enable continuous improvement in both drilling and transportation. Logistics costs can be reduced through efficiency gains (e.g., reduction of waiting time) and automated processes can reduce administrative costs. Past implementations have shown that consistent adoption of logistics leading practices can deliver up to 45 percent reduction in transport costs.

ComplianceThe use of a water inventory monitoring tool can support water management regulatory compliance through visibility of water draw, usage and movements. Automated end-to-end processes and systems enable accurate and rapid data capture, storage and reporting. A cross-operator, basin-wide solution would also confirm consistent basin-wide reporting standards across multiple sites and operators.

Groundwater contamination

On-site surface spills

Water withdrawal and air quality issues, and blowouts

Off-site disposal issues

48%

33%

10%

9%

Figure 2. Chart of water contamination incidents related to gas well drilling.

Source: Massachusetts Institute of Technology 2011 Gas Report.

Fracking & Earthquake Links

146

USGS and Oklahoma Geological Survey issued a warning of increased risk of earthquakes in central Oklahoma. The quakes are likely due to induced seismicity from deep injecAon of wastewater from unconvenAonal oil an gas drilling that can lubricate geologic faults and trigger man-‐made earthquakes.

More than 200 earthquakes of magnitude 3.0 or larger have shaken central Oklahoma since 2009 -‐-‐ about 40 a year. Before that, there were usually one to three earthquakes in that region annually. Earthquakes are now six Ames more likely in central Oklahoma than prior to 2009.

St. Gregory's University in Shawnee, Okla. on Nov. 6, 2011. Two earthquakes in the area in less than 24 hours caused one of the towers to topple, and damaged the remaining three.

This increased seismic risk from fracking wastewater disposal adds to the ever-‐growing need or widespread adopAon of alternaAve, waterless technologies.

John H Quigley, In Oklahoma, a whole lo-a shakin' goin' on, h-p://johnhquigley.blogspot.com/2013/10/in-‐oklahoma-‐whole-‐lo-a-‐shakin-‐goin-‐on.html

Fracking & Earthquake links

147

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Dallas-Ft. Worth, TexasMay 16, 2009 - M 3.3

Guy, ArkansasFeb. 27, 2011 - M 4.7

Youngstown, OhioDec. 31, 2011 - M 4.0

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wastewater injection occurred on Christmas Eve and New Year’s Eve near Youngstown, Ohio, the largest of which was a magnitude 4.0. Although there has been speculation that the magnitude-5.6 earthquake that occurred in Oklahoma on Nov. 5 may have been triggered by similar fluid injection, no linkage between this earthquake and fluid injection has been established.

The occurrence of injection-related earthquakes is understandably of concern to the public, govern-ment regulators, policymakers and industry alike. Yet it is important to recognize that with proper planning, monitoring and response, the occurrence of small-to-moderate earthquakes associated with fluid injection can be reduced and the risks associ-ated with such events effectively managed.

First, the FactsNo earthquake triggered by fluid injection has

ever caused serious injury or significant damage. Moreover, approximately 140,000 wastewater disposal wells have been operating safely and without incident in the U.S. for many decades.

That said, we have known for more than 40 years that earthquakes can be triggered by

fluid injection. The first well-studied cases were earthquakes triggered by waste disposal at the Rocky Mountain arsenal near Denver, Colo., in the early 1960s, and by water injection at the Rangely oilfield in western Colorado in the late ‘60s and early ‘70s.

Such quakes occur when increasing pore pres-sure at depth caused by fluid injection reduces the effective normal stress acting perpendicular to pre-existing faults. The effective normal stress on a fault can be thought of as a force that resists shear movement — much as how putting a weight on a box makes it more difficult to slide along the floor. Increasing pore pressure reduces the effec-tive normal stress, allowing elastic energy already stored in brittle rock formations to be released in earthquakes. These earthquakes would some-day have occurred anyway as a result of slowly accumulating forces in the earth resulting from natural geologic processes — injection just speeds up the process.

No earthquake triggered by fluid injection has ever caused serious injury or significant damage.

Earthquakes above magnitude-3.0 have been recorded by the U.S. Geological Survey in the Central and Eastern United States and southeastern Canada since 1960. The dates and largest magnitudes associated with recent earthquakes apparently triggered by fluid injection are noted.

EARTH April 2012 Q 39www.earthmagazine.org

Earthquakes above magnitude-‐3.0 have been recorded by the USGS in the Central and Eastern U.S. and southeastern Canada since 1960. The dates and largest magnitudes associated with recent earthquakes apparently triggered by fluid injecAon are noted.

These earthquakes would someday have occurred anyway as a result of slowly accumulaAng forces in the earth resulAng from natural geologic processes — injecAon just speeds up the process. No earthquake triggered by fluid injecAon has ever caused serious injury or significant damage. Moreover, approximately 140,000 wastewater disposal wells have been operaAng safely and without incident in the U.S. for many decades. That said, it has been known for 40+ years that earthquakes can be triggered by fluid injecAon.

MarAn D. Zoback, Managing the Seismic Risk Posed by Wastewater Disposal, Earth magazine, April 2012

Reducing Probability Of Triggering Earthquake

148

1.  Avoid injecAon into acAve faults and faults in bri-le rock. 2.  FormaAons should be selected for injecAon (and injecAon rates should

be limited) to minimize pore pressure changes. 3.  Local seismic monitoring arrays should be installed when there is a

potenAal for injecAon to trigger seismicity. 4.  Protocols should be established in advance to define how operaAons will

be modified if seismicity is triggered. 5.  Operators need to be prepared to reduce injecAon rates or abandon

wells if triggered seismicity poses any hazard. MarAn D. Zoback, Managing the Seismic Risk Posed by Wastewater Disposal, Earth magazine, April 2012

Experts point to 5 straigh�orward steps to reduce the probability of triggering seismicity whenever injecAng any fluid into the subsurface:

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same saline aquifers from which the water used for hydraulic fracturing was produced, pressure in the aquifers decreases over time as more water is pro-duced for hydraulic fracturing than injected following flowback.

Alternatively, weak, poorly cemented and highly permeable sandstone formations would also be ideal for injection. Such formations deform plastically and do not store elastic strain energy that can be released in potentially damaging earthquakes. No earthquakes have been triggered in the 15 years during which a million metric tons per year of carbon dioxide from the Sleipner gas- and oilfield in the North Sea has been injected into the Utsira sand, a highly porous, regionally extensive saline aquifer.

Obviously, cases will arise where well-cemented, less permeable and more brittle formations must be used for injection. In those cases, care must be taken to avoid large pore pressure changes. This can be done through modeling prior to injection once the permeability and capacity of the injection intervals have been determined. Well-established procedures have been developed over many decades by petroleum engineers to do this.

Step 3: Install Local Seismic Monitoring Arrays

Potentially active faults that might cause large and damaging earthquakes should be identifiable during the site characterization phase of permit-ting potential injection wells. Because smaller faults can escape detection, seismic monitoring

arrays should be deployed in the vicinity of injec-tion wells when there is a cause for concern that injection might trigger seismicity.

The locations and magnitudes of naturally occurring earthquakes are routinely determined on a real-time basis in numerous seismically active regions around the world. The instrumenta-tion, data telemetry and analysis techniques used to accomplish this monitoring are well developed and easily implemented at relatively low cost. By supplementing regional networks with local seismic arrays near injection wells, accurate loca-tions of earthquakes that might be triggered by injection can be used to determine the locations and orientations of the causative faults.

Although small faults cannot cause large earthquakes, even small earthquakes felt by the public will be a cause for concern and should be monitored.

Step 4: Establish Modification Protocols in Advance

Following precedents established to deal with earthquakes triggered during the development of enhanced geothermal systems, operators and regulators should jointly establish operational protocols for injection sites located in areas where there is concern about the potential for triggered seismicity. These protocols are sometimes referred to as “traffic light” systems.

Green means go: Once operational protocols and local seismic networks are in place and injection begins at agreed-upon rates, operators would have a green light to continue unless earthquakes begin to occur that appear to be

Operators and regulators should establish operational protocols — like perhaps a “traffic light” system — for wastewater injection sites located in areas where there is concern about the potential for triggered seismicity: Green means go, all systems working correctly; yel-low means proceed with caution, seismicity detected; red means stop, seismicity poten-tially presents a hazard.

In the same way that it’s important to plan for the possibility of triggered seismicity in advance, we have to be prepared to reduce

injection rates, or even abandon wells if triggered seismicity cannot be stopped by

limiting injection rates.

stop:seismicity

potentially presents a

hazard

proceed with caution:

seismicity detected

go:all systems

working correctly

42 Q EARTH April 2012 www.earthmagazine.org

Water & CCS Nexus

149

The Water and CCS Nexus

Travis McLing, Regional Carbon SequestraAon Partnership Water Working Group, Idaho Engineering NaAonal Laboratory,

Water & CCS impact by power plant

150

Water and Carbon Capture Impact

Source: Gerdes, K.; Nichols, C. Water Requirements for Existing and Emerging Thermoelectric Plant Technologies; DOE/NETL Report 402/080108; U.S. Department of Energy National Energy Technology Laboratory: Morgantown, WV, 2009.

0.00.10.20.30.40.50.60.70.80.91.0

Subcritical pc

Supercritical pc

IGCC – Dry Feed

IGCC –Slurry Feed NGCC

No Capture 0.52 0.45 0.30 0.31 0.19With Capture 0.99 0.84 0.48 0.45 0.34

Estimated Water Consumption Increase with CO2 Capture and Compression

gal/kWh

% Increase 91 87 61 46 76

pc= pulverized coal; IGCC= integrated gasificaAon combined cycle coal plant; NGCC-‐ natural gas combined cycle

Gerdes, K.; Nichols, C. Water Requirements for ExisAng and Emerging Thermoelectric Plant Technologies; DOE/NETL Report 402/080108; U.S. Department of Energy NaAonal Energy Technology Laboratory: Morgantown, WV, 2009.

Western water use for coal, oil & natural gas extracAon

151

Combined Results

Christopher Harto, Corrie Clark, Todd Kimmell, and Robert Horner, Water consumpAon for fossil fuel exploraAon and producAon, Argonne NaAonal Laboratory, Groundwater ProtecAon Council Annual Forum St. Louis, MO, September 23-‐25, 2013

Water ConsumpAon for Energy ExtracAon in the Western US –Argonne Natl Lab study

152 Christopher Harto, Corrie Clark, Todd Kimmell, and Robert Horner, Water consumpAon for fossil fuel exploraAon and producAon, Argonne NaAonal Laboratory, Groundwater ProtecAon Council Annual Forum St. Louis, MO, September 23-‐25, 2013

•  Overall energy extracAon does not appear to be a major water user in most areas in the Western U.S.

•  According to USGS, in 2005 all mining, including energy extracAon, accounted for only 1% of total US water withdrawals. However water use does appear to be concentrated in relaAvely few areas

•  Moreover, even these relaAvely small volumes can sAll result in conflicts between the energy industry and agricultural and/or municipal water users in areas with high water stress/low water availability or in Ames of drought.

Reduced Streamflow ProjecAons for Most River Basins in the Western US

153

Climate impacts of 3-‐5°C temperature rise on the Upper Colorado River Basin projected to reduce Spring streamflow 36% and Summer streamflow declines with median decreases of 46%. AddiKonal worsening from warmer temperatures, with increased average annual evapotranspiraKon by ~23%.

DECLINE

DECLINE

DECLINE

DECLINE

DECLINE

Darren L. Ficklin, IT Stewart, EP Maurer, Climate Change Impacts on Streamflow and Subbasin-‐Scale Hydrology in the Upper Colorado River Basin PLoS, Aug 19, 2013, DOI: 10.1371/journal.pone.0071297

Industry InnovaAons

155

The vocal opposiAon to fracking by so many ciAzen groups, rising number of town bans, and moratoriums in states like New York and North Carolina have caught the a-enAon of the fracking industry.

There is a pipeline of technology innovaAons to address public concerns on water use, fracking chemicals, wastewater disposal, watershed contaminaAon, methane and VOC emissions, etc. Some of these innovaAons offer win-‐win outcomes – gaining environmental benefits while also reducing producAon costs. A few are highlighted in the next few slides.

David Wethe, Be-er Fracking Through Sound-‐Sensing Fiber OpAcs, Bloomberg BusinessWeek, July 11, 2013

Industry InnovaAons Micro Seismic Monitoring

156

Microseismic fracture mapping provides an image of the fractures by detecAng microseisms or micro-‐earthquakes that are triggered by shear slippage on bedding planes or natural fractures adjacent to the hydraulic fracture. The locaAon of the microseismic events is obtained using a downhole receiver array that is posiAoned at the depth of the fracture in an offset wellbore.

h-p://www.halliburton.com/en-‐US/ps/sAmulaAon/sAmulaAon/microseismic-‐fracture-‐mapping-‐fracture-‐modeling.page?node-‐id=hgoxbxoc

Microseismic fracture mapping is employed to improve producAon economics by increasing reservoir producAvity and/or reducing compleAon costs. This capability helps assure the fracture stays in the intended zone and that the complete zone is sAmulated. This capability can help opAmize producAon and minimize the number of wells and fractures required.

Industry InnovaAons Fiber OpAcs Monitoring

157

Drilling companies omen fire the mixture of chemicals, sand, and water more or less blindly at rocks that hold oil and natural gas to create fissures and extract the seeping fuel.

Fracking each well typically takes 15 “stages” of mixture-‐firing at about $100,000 each.

Success is hard, with 80% of the stages delivering less than 20% of the producAon. Drillers spend more than $30 billion on “sub-‐opAmal” fracking stages across 26,100 U.S. wells.


Industry InnovaAon Fiber OpAc Monitoring

158

Halliburton and others are tesAng fiber-‐opAc cables that are used in U.S. submarines. These so-‐called distributed fiber-‐opAc lines record sound and temperature along their enAre length. With steel-‐encased lines clamped between fracking wells and rock, drillers can record sounds that signal the perfect frack. The Halliburton team is refining somware to convert the sounds to a graph, showing how thoroughly the rock hiding the fuel has fractured. In addiAon to discerning between good and bad fracking stages, the fiber picks up subtle noises that can indicate when the cement sealing of a spent well isn’t working—a safety threat that could allow residual gas to reach the surface and trigger an explosion. Fewer fracking stages mean less toxic sludge pumped down toward a community’s water table, but it doesn’t make the chemical cocktail itself any cleaner. And while fiber lines can save drillers money on ill-‐aimed or unnecessary fracking stages, efficiency-‐hungry companies may balk at using fiber opAcs on smaller operaAons. Installing the fiber can cost as much as several hundred thousand dollars per well.


Industry InnovaAon Gravity & Solar PV “SandCastle”

159

The vast majority of fracking sites in America are powered by emissions-‐spewing, noisy diesel engines. Halliburton has begun using SandCastles, a fracking machine that uses gravity and electricity generated from solar panels to send sand more quietly into a labyrinth of tubes before ulAmately being shot underground to prop open Any cracks in gas-‐ or oil-‐bearing rock.

By replacing diesel engines to move sand from the trailers, Halliburton esAmates the devices have saved 950,000 gallons of diesel and reduced CO2 emissions by 20 10,000 tons in the first nine months of 2012

Industry InnovaAon Ecologix – Wastewater Recycling

160

Cleaning up wastewater from fracked and convenAonal wells already is an $18 billion annual business. The industry sees innovaAon as a key way of somening calls for government regulaAons. Ecologix is markeAng technology that can recycle fracking wastewater by using air bubbles to separate out polluAng solids, forming them into a sludge blanket that can be scooped up.

Ecologix Environmental Systems, Integrated Treatment System (ITS) for Frac Water Management, h-p://www.ecologixsystems.com/system-‐its.php

Industry InnovaAon Verenium Non-‐toxic Enzymes

161

Verenium is markeAng nontoxic enzymes aimed at reducing a causAc chemical, ammonium persulfate—a standard ingredient in hair bleach—used during fracking.

Guar gum is a natural polymer found in guar beans, and India supplies 80% of the world guar gum supply. The biggest use of guar gum in recent years has been as an addiAve in fracking.

Fracking uses guar gum to increase viscosity of the iniAal fluid pumped down wells, followed by treatment with a guar breaker to decrease viscosity and allow hydrocarbons to flow through the newly formed cracks in the well. Though chemical guar breakers like chlorine sources, ammonium persulfate, and hydrochloric acid are omen used, the push toward more environmentally friendly alternaAves has intensified.

Industry InnovaAon GE Mobile Evaporator

162

GE has come up with the Mobile Evaporator, a boiler-‐on-‐wheels the size of a semi that can be towed from well to well and cleans about 50 gallons of water per minute by boiling it to separate out contaminants. The cleaned water can be reused or fed into waterways.

Industry InnovaAon Halliburton CleanSAm

163

CleanSAm is a fracking fluid with addiAves made, it says, almost enArely of enzymes from fruit and vegetable compounds. Halliburton won’t disclose the new ingredients, so far used in 23 wells, calling them proprietary. How convinced is Halliburton of the elixir’s safety? In front of hundreds of oil and gas execuAves in San Antonio for the Society of Petroleum Engineers annual conference in October, CEO David Lesar took a swig of CleanSAm from a small jar. “There’s not one petroleum product in it,” he said. But, he added, “It doesn’t taste very good.”

David Wethe, For Fracking, It's Geong Easier Being Green, Bloomberg BusinessWeek, Nov. 29, 2012

Industry InnovaAon Using Acid Mine Drainage

164

Winner Water Services, a Ba-elle subsidiary, runs a treatment facility in Sykesville, Pennsylvania that removes iron from the water that flows through an abandoned coal mine. The company would like to sell the water to fracking companies.

PA’s Dept. of Environmental ProtecAon is encouraging the use of contaminated water flowing from hundreds of abandoned coal mines. Over 300 million gallons of contaminated water flow from the state’s abandoned mines every day, polluAng roughly 5,500 streams.

PA DEP, UAlizaAon of Mine Influenced Water for Natural Gas ExtracAon AcAviAes, White Paper, January 2013, PA Dept. of Environmental ProtecAon. Bre- Walton, Pennsylvania Encourages New Source of Water for Fracking – Discharge from Abandoned Mines, Circle of Blue, July 25, 2013

Acid mine drainage (AMD), as the metal-‐ and salt-‐laden water is commonly known, can be treated and then developed as a source of fracking water. By doing so, the state hopes for a double benefit: cuong the flow of contaminated water from mines into rivers while decreasing the amount of freshwater used in fracking.

U.S. ConAnental Shale Plays

165

BUT Resources ≠ Reserves ≠ Supply

166

Shale Resource SkepAcs

167

Arthur E. Berman, petroleum geologist and Shale Resource Industry Analyst

•  USA does not have 100 years of natural gas. •  Less than 22 years of possible reserves. •  Shale gas reserves are over-‐stated by at least

100%. •  E&P business succeeds or fails based on earnings

and profit, and not on producAon growth, resource or even reserve addiAons

•  True break-‐even cost of shale gas is $7/mcf. Price must rise above this cost for companies to survive.

•  ProducAon is impressive but most wells are not profitable.

•  All plays have contracted to core areas a fracAon of the size of the play as originally adverAsed.

•  Shim to liquid-‐rich shale plays will deflate the gas over-‐supply and cause prices to rise.

•  Environmental problems will limit the contribuAon of the Marcellus Shale.

Arthur E. Berman, Amer The Gold Rush: A PerspecAve on Future U.S. Natural Gas Supply and Price, ASPO Conference 2012 Vienna, Austria, May 30, 2012

A View from the BoQom of the Resource Pyramid

168

Slide 3 Labyrinth Consulting Services, Inc. ASPO Conference 2012

A view from the bottom of the resource pyramid • Unconventional plays became important as better plays were exhausted. • There is no technological revolution, just improvement through extensive & expensive trial-and-error. • Shale reservoirs will not perform as well as conventional reservoirs. • Economics depend on high prices. • Except that entry, drilling & completion costs are enormous. • And the drilling treadmill never ends because of high decline rates. • Demand destruction will limit product price and, therefore, the long end of the unconventional production curve.

“Shale plays are not a renaissance or a revolution. This is a retirement party.”


Arthur E Berman

A race between increased pricing & improved technology

EsAmated UlAmate Recovery (EUR)

169

EUR is defined as the total amount of gas expected to be economically recovered from a reservoir or field during each well’s producAon lifeAme. Life Cycle Assessment (LCA) studies frequently highlight EUR as a significant area of uncertainty for shale gas wells. While shale wells are expected to have up to a 30-‐year lifespan, they only started to be developed in significant numbers in the last decade, so their full lifespan is not yet well-‐understood. LCA results are highly sensiAve to EUR because life cycle emissions are typically calculated as emissions per unit of energy output. Energy output is a direct funcAon of the total volume of natural gas produced by each well over its lifeAme; therefore, if a shale gas well turns out to be less producAve than expected, the life cycle emissions esAmates will be higher in nearly equal proporAons. Meanwhile, most upstream methane emissions appear to occur disproporAonately during the early stages of each well’s lifeAme

Key variable in esAmaAng life-‐cycle emissions

EUR Uncertainty

170

Significant uncertainty remains regarding the total recoverable quanAty of natural gas in the U.S., and the average EUR at wells in each producing basin. This uncertainty flows down to the level of an individual well; for example, the most recent assessment by the U.S. Geological Survey (USGS 2012) finds that most U.S. shale plays have EURs in the range of 0.7 to 1.3 Bcf per well.

This is considerably less than industry esAmates and less than half the esAmates used by previous LCA authors (Table A2-‐1). This would suggest that LCAs are generally underesAmaAng average well life cycle emissions.

On the other hand, today’s EUR esAmates are based on current informaAon, while unexpected future technology improvements (unknown knowns) could result in be-er economics and higher EURs.

Summary of parameters in different shale / unconvenKonal gas studies

171

46 |

During well completions, Howarth et al. (2012) assumes zero flaring; NETL assumes a 15 percent flaring rate (citing EPA’s 2011 technical support document for subpart W). A recent study by O’Sullivan and Paltsev (2012) assumed 70 percent of potential fugitive emissions were captured, 15 percent vented, and 15 percent flared. The authors argued that this was a “reasonable representation of current gas handling practices in the major shale plays.” Industry representatives have claimed as high as 97 percent of 2011 well completions were either flared or captured using green completion technolo-gies (ANGA 2011).

Production stage workovers and liquids unloadingA recent oil and gas industry report (Shires and Lev-On 2012) concluded that 16 percent of their surveyed unconventional (including shale gas) wells vented methane in the process of liquids unloading (versus 11 percent for surveyed conventional wells).127 While these are fairly high activity rates, the report assigns much lower emissions to each liquids unloading event, yield-ing emissions estimates roughly 80 percent lower than 2012 GHG inventory estimates (EPA 2012a). EPA’s draft 2013 GHG inventory cites this industry survey as the basis for changing assumptions previously held in the 2011 and 2012 GHG Inventories—now assuming that liquids unloading occurs at both conventional and unconventional wells, but with significantly reduced associated emissions (EPA 2013a).

There is also uncertainty regarding the frequency in which workovers with refracturing will be required to stimulate production at the typical unconven-tional natural gas well. In the TSD for the proposed NSPS, EPA assumed that refracturing would occur 3.5 times, on average, over the lifetime of uncon-ventional natural gas wells.128 However, in the TSD accompanying the final NSPS rule (EPA 2012c), EPA assumed that only 30 percent of all uncon-ventional wells would be refractured during their lifetimes. Of course, these projections are fraught with uncertainties and based on only a few years of limited data and experience.

Nevertheless, based on the TSD for the proposed rule,129 NETL (2012) and Burnham et al. (2011) assumed multiple well workovers with refracturing during the production stage, while others assumed zero workovers (see Table A1). It is common to assume that refracturing during workovers results in roughly the same GHG emissions as well completions. For example, NETL and Burnham et al. calculate emissions associated with well workovers by multiplying the number of workovers per well life-time by the level of emis-sions associated with well completion. However, this likely overestimates emissions associated with workovers, since offtake pipes and gathering lines are always in place when workovers occur (though they may not be in place when the well is initially developed) and this increases the chances that operators will use green completions during refracturing operations.

PARAMETER HOWARTH JIANG NETL BURNHAM

Geographic area Barnett, Haynesville, Piceance tight sand, Uinta tight sand, Den-Jules

Marcellus Barnett & Marcellus Barnett, Marcellus, Fay-etteville, Haynesville

EUR, BCF (with range) 2.7 3.13* 3.5 (1.6–5.3)

GWP (integrated time frame) 20-year = 105100-year = 33

100-year = 25 20-year = 72 100-year = 25

20-year = 72100-year = 25

GWP (source) Shindell et al., 2009 IPCC, 2007 IPCC, 2007 IPCC, 2007

Flaring rate for well completions 0 76% 15% 41%

Number of workovers (or refracture) per well lifetime

0 0 3.5 2

Methane emissions per well completion (or workover)

95 to 4,608 tons 26 to 1000 tons 177 tons 177 tons

Primary methane emissions data sources

EPA, GAO, and others EPA EPA EPA

Table A2-1 | Summary of parameters in different shale / unconventional gas studies

Sources: Howarth et al. 2011; Jiang et al. 2011; NETL 2012; Burnham et al 2011.

Notes: *NETL’s EUR value is a simple average of EURs for Marcellus Shale and Barnett Shale, based on data provided in NETL’s Table 4-6.


Table A2-‐1

USGS Shale Gas EUR Assessments

172

3

Table 1. Input data for estimated ultimate recovery distributions for United States shale-gas assessment units, values in billions of cubic feet of natural gas. [AU, assessment unit; and EUR, estimated ultimate recovery]

AU number AU name Province Year

assessed Minimum

EUR Median

EUR Maximum

EUR Mean EUR

50490161 Haynesville Sabine Platform Shale Gas Gulf Coast Mesozoic 2010 0.02 2 20 2.617 50490163 Mid-Bossier Sabine Platform Shale Gas Gulf Coast Mesozoic 2010 0.02 1 10 1.308 50580161 Woodford Shale Gas Anadarko Basin 2010 0.02 0.8 15 1.233 50670468 Interior Marcellus Appalachian Basin 2011 0.02 0.8 12 1.158 50490167 Eagle Ford Shale Gas Gulf Coast Mesozoic 2010 0.02 0.8 10 1.104 50620362 Fayetteville Shale Gas - High Gamma-Ray Depocenter Arkoma Basin 2010 0.02 0.8 10 1.104 50450161 Greater Newark East Frac-Barrier Continuous Barnett Shale Gas Bend Arch-Fort Worth Basin 2003 0.02 0.7 10 1.000 50440161 Delaware/Pecos Basins Woodford Continuous Shale Gas Permian Basin 2007 0.02 0.6 8 0.842 50440162 Delaware/Pecos Basins Barnett Continuous Shale Gas Permian Basin 2007 0.02 0.6 8 0.842 50580261 Thirteen Finger Limestone-Atoka Shale Gas Anadarko Basin 2010 0.02 0.5 10 0.785 50620261 Woodford Shale Gas Arkoma Basin 2010 0.02 0.5 10 0.785 50210364 Gothic, Chimney Rock, Hovenweep Shale Gas Paradox Basin 2011 0.02 0.4 10 0.672 50630561 Devonian Antrim Continuous Gas Michigan Basin 2004 0.02 0.4 4 0.523 50620363 Fayetteville Shale Gas - Western Arkansas Basin Margin Arkoma Basin 2010 0.02 0.3 6 0.470 50210362 Cane Creek Shale Gas Paradox Basin 2011 0.02 0.3 5 0.446 50440163 Midland Basin Woodford/Barnett Continuous Gas Permian Basin 2007 0.02 0.3 5 0.446 50490165 Maverick Basin Pearsall Shale Gas Gulf Coast Mesozoic 2010 0.02 0.25 5 0.391 50450162 Extended Continuous Barnett Shale Gas Bend Arch-Fort Worth Basin 2003 0.02 0.2 5 0.334 50390761 Niobrara Chalk Denver Basin 2001 0.025 0.2 2 0.261 50620262 Chattanooga Shale Gas Arkoma Basin 2010 0.02 0.1 6 0.223 50670467 Foldbelt Marcellus Appalachian Basin 2011 0.02 0.1 5 0.208 50620364 Caney Shale Gas Arkoma Basin 2010 0.02 0.08 5 0.179 50670469 Western Margin Marcellus Appalachian Basin 2011 0.02 0.05 5 0.129 50640361 Devonian to Mississippian New Albany Continuous Gas Illinois Basin 2007 0.01 0.08 1 0.110 50670462 Northwestern Ohio Shale Appalachian Basin 2002 0.01 0.04 0.5 0.055 50670463 Devonian Siltstone and Shale Appalachian Basin 2002 0.01 0.03 0.5 0.044

USGS, Variability of DistribuKons of Well-‐Scale EsKmated UlKmate Recovery for ConKnuous (UnconvenKonal) Oil and Gas Resources in the U.S., Report 2012-‐1118, U.S. Geological Survey. TABLE 1

Table 1. Input data for esAmated ulAmate recovery distribuAons for U.S. shale-‐gas assessment units, values in billions of cubic feet of natural gas. [AU, assessment unit; and EUR, esAmated ulAmate recovery]

CLOUD PLOT USGS Shale Gas EUR Assessment Units (AUs)

173 USGS, Variability of DistribuKons of Well-‐Scale EsKmated UlKmate Recovery for ConKnuous (UnconvenKonal) Oil and Gas Resources in the U.S., Report 2012-‐1118, U.S. Geological Survey

8

Results The results are presented in figures 1 through 4. Each line shows the range of EURs for a

single AU. Only those EURs greater than the minimum assessed value (for that particular AU assessment) are included. Individual AU distributions show approximately two orders of magnitude difference between the smallest and largest EURs within a single AU. This range would be even larger if the distributions were not truncated.

Figure 1. Cloud plot for United States shale-gas assessment units. Each curve represents one assessment unit and is based on the input data in table 1. Black diamonds indicate the mean value for each curve. [AU, assessment unit; EUR, estimated ultimate recovery; and BCF, billions of cubic feet]

Semi-‐log Cloud or Spagheo plot for U.S. shale-‐gas AUs. Each curve represents one AU and is based on the input data in table 1.

FracAles indicate what percent of wells have an EUR of at least the indicated amount. Note the EURs range more than two orders of magnitude.

The EUR distribuAons tend to “collapse” around the mean (u).

EUR, esAmated ulAmate recovery; BCF, billions of cubic feet]

uBlack diamonds indicate the mean value for each curve.

Why Reserves (EURs) are Over-‐stated: Decline Rates are Higher than AnAcipated

174

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48% Annual Decline Rate

Why Reserves are Over-stated—Decline Rates are Higher than Anticipated

11.5% of total U.S. gas supply. Haynesville Shale annual base decline rate is ~48-‐53%, which means ~3.8 Bcf per day of gas producAon needs to be replaced annually.

Arthur Berman, Labyrinth ConsulAng Services, Amer the Gold Rush: A PerspecAve on Future U.S. Natural Gas Supply and Price, presented at South Texas Money Management Ltd 7th Annual Energy Symposium, May 16, 2012

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Number of Wells & Cost to Replace 3.5 Bcf/day in Haynesville Shale

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Total Cost: $8 Billion


Total Cost: $13 Billion Jan 2008 - Jun 2010

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Red Queen Syndrome “…it takes all the running you can do, to keep in the same place.”

3.5

7

Barne- Shale Gas ProducAon decline

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9% of U.S. gas supply. Current producAon appears to be in decline despite adding new wells. 1250 new producing wells added in 2011. 50 rigs drilling, down from 185.

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Barne- Shale – Why Reserves over-‐stated & decline rates higher than anAcipated

177

30% annual decline rate. Must replace 1.6 Bcf per day to maintain supply. Devon Energy-‐ the largest operator in the Barne- – announced that it will drill no dry gas wells.

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Red Queen Syndrome “…it takes all the running you can do, to keep in the same place.”

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Jan 2003 - Jan 2007

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Total U.S. Decline Rates Have Increased Since the Advent of Shale Gas Plays

179 Arthur Berman, Labyrinth ConsulAng Services, Amer the Gold Rush: A PerspecAve on Future U.S. Natural Gas Supply and Price, presented at South Texas Money Management Ltd 7th Annual Energy Symposium, May 16, 2012


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• &In&2001,&annual&decline&rate&for&&U.S.&natural&gas&produc4on&was&23%.&• &Now,&annual&decline&rate&is&32%.&

Source: ARC Financial Research

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Analysis of top 34 publicly traded gas producers indicates that the cost of replacement is $22 billion per quarter. 2010 cash flow for those companies was $12 billion per quarter so there is a $10 billion quarterly cash flow deficit.

Capex to Cash Flow RaAos


“Unsustainable capital expenditures will limit capability to deliver on supply. Service cost will compound this limitaAon. Further constrains on cost-‐of-‐capital will limit opAons.”

Arthur E. Berman, petroleum geologist and Oil&Gas industry

analyst


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•  Unsustainable capital expenditures will limit capability to deliver on supply. •  Service cost acceleration will compound this limitation. •  Further constraints on cost-of-capital will limit options.

Ticker

Share*Price**as*of04/10/12 Mkt*Cap*($B) EV*($B)

1>Year*Change**inPrice Production*4Q11*(kboepd)

Gas*as*%*ofProduction

Cash*Margin($/boe)

Debt*to*Total*Cap Capex>to>Cash*Flow*

(Yahoo*Finance)CRK $15.45 $0.70 $1.90 >48% 46 92% $17.32 54% 769%CRZO $26.09 $1.00 $1.70 >28% 22 86% $21.32 59% 542%ATPG $6.63 $0.30 $2.70 >60% 25 34% $28.70 96% 417%XCO $6.02 $1.30 $3.10 >71% 92 98% $15.19 55% 336%UPL $19.51 $3.00 $4.90 >60% 121 97% $22.10 54% 318%KWK $4.41 $0.70 $2.60 >67% 69 82% $7.82 65% 304%PVA $3.95 $0.20 $0.90 >75% 19 63% $32.75 45% 302%MUR $51.98 $10.10 $9.60 >31% 192 42% $46.50 6% 286%PXP $40.50 $5.20 $8.40 16% 105 50% $26.70 54% 282%FST $11.35 $1.30 $3.00 >68% 57 70% $18.99 59% 282%MMR $8.83 $1.40 $2.10 >50% 28 66% $24.17 22% 214%SM $64.58 $4.10 $5.00 >10% 93 56% $29.21 40% 203%PQ $5.66 $0.40 $0.50 >35% 15 83% $14.51 40% 196%RRC $56.79 $9.00 $10.90 1% 104 79% $23.80 46% 195%NBL $93.16 $16.50 $19.50 >2% 233 60% $34.47 36% 189%CXO $96.29 $9.90 $12.00 >7% 71 38% $48.55 41% 186%BBG $22.74 $1.10 $1.90 >45% 53 90% $24.62 42% 186%GDP $15.35 $0.60 $1.10 >29% 18 86% $11.01 80% 181%CHK $20.69 $13.20 $28.20 >38% 599 82% $21.65 37% 180%COG $30.63 $6.40 $7.30 17% 99 94% $18.91 31% 176%DNR $17.80 $6.90 $9.40 >24% 67 6% $62.47 36% 173%ROSE $47.03 $2.50 $2.70 3% 32 51% $28.00 27% 164%SFY $27.12 $1.20 $1.60 >34% 29 49% $34.55 42% 161%SWN $29.30 $10.20 $11.50 >26% 242 100% $16.39 25% 146%EOG $104.00 $28.00 $32.40 >8% 442 58% $33.96 28% 144%NFX $33.09 $4.40 $7.30 >54% 144 56% $32.26 43% 144%XEC $69.19 $5.90 $6.30 >39% 100 56% $30.94 11% 136%CWEI $72.99 $0.90 $1.40 >26% 15 24% $73.10 61% 132%BRY $44.20 $2.40 $3.80 >13% 36 28% $37.92 62% 126%CPE $5.52 $0.20 $0.30 >20% 5 42% $46.56 57% 124%PXD $105.12 $12.90 $15.10 3% 137 44% $31.02 31% 122%DVN $68.94 $27.90 $30.60 >23% 680 65% $23.07 31% 100%OXY $89.61 $72.70 $74.80 >11% 749 28% $50.89 13% 96%WTI $18.54 $1.40 $2.10 >16% 50 52% $35.73 57% 80%APA $93.50 $35.90 $44.10 >26% 759 50% $45.21 20% 66%APC $74.63 $37.70 $52.30 >8% 683 57% $31.18 46% 52%WLL $51.17 $6.00 $7.40 >28% 71 16% $51.16 31% 5%CNQ $31.29 $34.20 $42.70 >31% 580 35% $43.16 27% N/ACVE $33.38 $25.10 $30.40 >11% 231 47% $28.06 27% N/AECA $18.19 $13.30 $19.00 >43% 600 96% $17.29 33% N/ATLM $12.18 $12.50 $17.30 >47% 362 59% $31.72 33% N/A

Source: Bernstein Research & Yahoo Finance

Source: Bernstein Research & Yahoo Finance

Abundance or mirage? Why the Marcellus Shale will disappoint expectaAons

182

Industry analyst Arthur Berman argues, “Shale gas plays in the U.S. are commercial failures and shareholders in public exploraKon and producKon (E&P) companies are the losers. This conclusion falls out of a detailed evaluaKon of shale-‐dominated company financial statements and individual well decline curve analyses. Operators have maintained the illusion of success through producKon and reserve growth subsidized by debt with a corresponding destrucKon of shareholder equity. Many believe that the high iniKal rates and cumulaKve producKon of shale plays prove their success. What they miss is that producKon decline rates are so high that, without conKnuous drilling, overall producKon would plummet. There is no doubt that the shale gas resource is very large. The concern is that much of it is non-‐commercial even at price levels that are considerably higher than they are today.”

Arthur E. Berman, Abundance or mirage? Why the Marcellus Shale will disappoint expectaAons, ASPO USA, October 08, 2010

Abundance or mirage?

183

Berman explains, “Recent revisions to SEC rules have allowed producers to book undeveloped reserves that quesAonably jusAfy development costs based on their own projecAons in public filings. New reserves are being booked at the same Ame that billions of dollars in exisAng shale gas development costs are being wri-en down because the projects are not commercial. Concerns about the logic of ongoing gas-‐directed drilling while prices collapse have been partly diffused by a shim to liquids-‐rich plays like the Eagle Ford Shale in Texas. Shale gas operators have consistently told investors that their projects are profitable at sub-‐$5/Mcf natural gas prices. Yet company 10-‐K SEC filings show that this is untrue. They have invented a new calculus of parAal-‐cycle economics that excludes major capital draws for land costs, interest expense and overhead. They jusAfy these disclosure pracAces because excluded costs are either sunk or fixed and, therefore, supposedly should not affect their decisions to drill. Their point-‐forward plans are made at shareholder expense since the dollars spent were very real at the Ame, and their costs cannot be charged to a profit center other than the wells that they drill and produce.”

Arthur E. Berman, Abundance or mirage? Why the Marcellus Shale will disappoint expectaAons, ASPO USA, October 08, 2010

Abundance or Mirage?

184

A mulA-‐year evaluaAon of producAon costs for ten shale operators indicates a $7 per Mcf (thousand cubic feet) average break-‐even cost for shale gas plays in the U.S. taking hedging into account.

Price must rise to meet the true break-‐even cost, yet ~$4/Mcf is forecast unAl 2020.

Slide&7&Labyrinth&Consul4ng&Services,&Inc.& Duke&University&Nicholas&School&of&the&Environment&

Cost is Understated: The True Break-Even Price is $7.00/mcf

$0.00&

$2.00&

$4.00&

$6.00&

$8.00&

$10.00&

$12.00&

$14.00&

$16.00&

Selected Company 5 Year Imputed Production Costs/Mcfe

Weighted Realized Price/Mcfe with Hedges 5 Year Calculated "Break-Even" Price

•  Claims of profitability at less than $5.00 /mcfg are based largely on point-forward economics at odds with costs reported to the Securities and Exchange Commission in 10-K filings—all sunk costs written off. •  Price must rise to meet the true break-even cost. •  Several executives have recently said that $6/mcf is a minimum threshold to justify more drilling.

Source: Company Reports

$7/mcf avg.

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Well Life, NPV and EUR – overhyped?

185

The high shale gas reserve forecasts by operaAng companies are based on long individual well lives of as much as 65 years. In the Barne- Shale, wells were grouped by the year of compleAon and evaluated based on current monthly gas producAon.

yellow, or cooler, colors show areas of poorer production. The map shows extreme heterogeneity within the core area where high Barnett production volumes are unevenly distributed and many non-commercial wells have been drilled adjacent to excellent wells. The claim of repeatable and uniform results by the shale play promoters cannot be supported by case histories to date. We contend that the factory model is not appropriate because the geology of these plays is more complex than operators claim.

Well Life, NPV and EUR

The high shale gas reserve forecasts by operating companies are based on long individual well lives of as much as 65 years. In the Barnett Shale, wells were grouped by the year of completion and evaluated based on current monthly gas production. The percentage of wells from each group that are currently producing less than 1 million cubic feet of gas per month is shown in Figure 9. This gas volume only covers the cost of well compression assuming $5/Mcf without royalty payments or other costs. In other words, 25-35% of wells drilled over the past six or seven years are not paying for the cost of compression so what is the justification for 40-65 years of advertised commercial production?

When we examined Chesapeake Energy’s type curve for the Barnett Shale and assumed that all parameters were correct--initial production rate, decline rate, well life, etc.--we found that most of the discounted net present value (NPV10) occured in the first five years and that there is negligible value after Year 20 (Figure 10). The type curve, however, forecasts about half of the reserves in years 20 through 65. Since these volumes have no discounted value, reserves are

This gas volume only covers the cost of well compression assuming $5/Mcf without royalty payments or other costs. In other words, 20-‐35% of wells drilled over the past six or seven years are not paying for the cost of compression so what is the jusAficaAon for 40-‐65 years of adverAsed commercial producAon?

Arthur Berman, U.S. Shale Gas: Magical Thinking & The Denial of Uncertainty, Jan. 12, 2012, presentaAon at Duke Univ. Nicholas School of the Environment.

Percentage of wells from each group that are currently producing less than 1 million cubic feet of gas per month.

Barne- mortality rate casts doubt on 40-‐65 year well life

186

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Reserves based on very long well lives that assume flat decline rates. Barne- examples based on cumulaAve producAon show that EUR esAmates are improbable in a Ame frame where NPV is meaningful.


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Inaccuracy of Type Curve: Haynesville Shale and normalized producAon data

187

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Chesapeake Energy’s type curve for the Haynesville Shale, predicAng average well producAon (EUR) of 6.5 Bcf gas reserves. The difference lies in forecasAng future decline trends, parAcularly the hyperbolic b exponent. Type curves don’t work because of survivorship bias. Emphasis on mean in a highly variable and small populaAon commonly over-‐predict by 50%.


Hyperbolic exponents

188

Hyperbolic exponents cannot be whatever we like. The match with wells that have 12 months or more of producAon is good.

The problem lies in how future decline trends are projected and what hyperbolic exponents (curvature or b-‐factor) are assumed.

How these wells will decline only Ame will tell. Be-er to present a probabilisAc range of possible reserves rather than a fixed value.

This implies greater uncertainty and greater risk than operators represent. Companies should use an intermediate hyperbolic exponent (as recommended by Society of Petroleum Engineers peer-‐reviewed papers) to project reserves and revise them upward or downward later when producAon has stabilized.

Using a hyperbolic exponent of 0.5, Chesapeake’s average well will produce 3.0 Bcf based on their type curve, which is not commercial at $7.00/Mcf. For reputable companies to say that the least likely case (b = 1.1) is the most likely case does not prudently represent uncertainty. Arthur E. Berman, Amer The Gold Rush: A PerspecAve on Future U.S. Natural Gas Supply and Price, ASPO Conference 2012 Vienna, Austria, May 30, 2012

EUR is not NPV

189

Shale play promoters constantly try to divert a-enAon and analysis from current plays to newer plays. Newer plays have less data to analyze and, therefore, reserve claims are more difficult to quesAon. Because the Barne- and Faye-eville shale plays have under-‐performed expectaAons, a few years later the emphasis shimed to consider the future potenAal of the Haynesville Shale play. Now that the Haynesville looks disappoinAng, the emphasis is shiming to consider the Marcellus Shale play. And with the shim to liquids-‐rich plays like the Eagle Ford Shale, promoters that sold the under-‐performing plays in the past emphasize this Ame it will be different. There appear to be a host of foreign investment companies that may provide capital for the shale plays now that operator debt has reached extreme levels, and most available assets have been sold at considerable damage to shareholders.


Magical thinking

190

•  A tremendous amount of capital has been bet on shale and much of this is in the form of debt.

•  There is very li-le shale producAon history so the outcome is uncertain.

•  It is unclear that shale gas producAon will support even short-‐term expectaAons of abundance.

•  Capital expenditures exceed cash flow for most companies.

•  Full-‐cost and off-‐book accounAng mask the weak performance of most shale-‐dominated companies.

•  There is great uncertainty about reserves, and most are undeveloped.

•  Yet, the prevailing view is that success is certain. •  There are considerable risks in magical thinking.

"This is an industry that is caught in the grip of magical thinking," Arthur Berman says. "In fact, when you look at the level of debt some of these companies are carrying, and the quesAonable value of their gas reserves, there is a lot in common with the subprime mortgage market just before it melted down."

191

XX's goal is to reduce

CO2 emissions intensity to

0.45 tons (990 lbs) per MWh

by 2025

Current and Future Technologies for NGCC Power Plants

11

Exhibit ES-8 CO2 emission rates

Source: NETL

780.2

89.5 88.1

752.8

85.7 84.5

714.7

80.8 79.7

686.5

77.0 76.3

760.3

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734.5

78.6 77.8

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0

100

200

300

400

500

600

700

800

900

1000

1100

7FA.05 7FA.05 CCS 7FA.05 CCS EGR

H-frame H-frame CCS

H-frame CCS EGR

J-frame J-frame CCS J-frame CCS EGR

AdvFuture AdvFuture CCS

AdvFuture CCS EGR

CO2

Emis

sion

s (l

b/M

Wh)

CO2 Emissions (lb/MWhnet)

CO2 Emissions (lb/MWhgross)

NETL, Current and Future Technologies for Natural Gas Combined Cycle (NGCC) Power Plants, June 10, 2013, NaAonal Energy Technology Lab, US DPE, DOE/NETL-‐341/061013

GE 7FA.05 F frame

Siemens 8000 H H frame

MHI J frame

Future advanced X frame*

* Future advanced X frame assumes the 7FA.05 model with output 90% more & heat rate is 13% be-er. This turbine would require improvements in materials & cooling technologies to become feasible.

Power generaKon fleet goal in 2025

3 NGCC plants operaKng today, & 4th one in development (without CCS and with further CO2 reducKons w/ CCS)

192

XX's goal is to reduce

CO2 emissions intensity to

0.45 tons (990 lbs.) per MWh by 2025.

Current and Future Technologies for NGCC Power Plants

11

Exhibit ES-8 CO2 emission rates

Source: NETL

780.2

89.5 88.1

752.8

85.7 84.5

714.7

80.8 79.7

686.5

77.0 76.3

760.3

81.6 80.7

734.5

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698.8

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672.4

71.5 71.1

0

100

200

300

400

500

600

700

800

900

1000

1100

7FA.05 7FA.05 CCS 7FA.05 CCS EGR

H-frame H-frame CCS

H-frame CCS EGR

J-frame J-frame CCS J-frame CCS EGR

AdvFuture AdvFuture CCS

AdvFuture CCS EGR

CO2

Emis

sion

s (l

b/M

Wh)

CO2 Emissions (lb/MWhnet)

CO2 Emissions (lb/MWhgross)

NETL, Current and Future Technologies for Natural Gas Combined Cycle (NGCC) Power Plants, June 10, 2013, NaAonal Energy Technology Lab, US DPE, DOE/NETL-‐341/061013.

GE 7FA.05 F frame

Solar PV Large wind turbine

Power generaKon fleet goal in 2025

End-‐use efficiency

Least-‐risk opKons – two already compeKKve with natural gas

No fuels, near-‐zero emissions, near-‐zero water use

IPCC, 2011: IPCC Special Report on Renewable Energy Sources and Climate Change MiAgaAon. Prepared by Working Group III of the Intergovernmental Panel on Climate Change [O. Edenhofer, R. Pichs-‐Madruga, Y. Sokona, K. Seyboth, P. Matschoss, S. Kadner, T. Zwickel, P. Eickemeier, G. Hansen, S. Schlömer, C. von Stechow (eds)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 1075 pp. (Chapter 7 & 9).

VS

Lower Risk Profits &

Earnings Plays?

193

Focus on reAring & replacing the energy services from the 230+ GW of operaAng coal power plants. Bid to deliver power services at lower cost and lower risk through long-‐term PPAs. Efficiency power plants for replacing coal plants with lowest O&M costs, and wind and solar PV for coal plants with highest O&M costs.

Efficient Power Plants – core to smart networks for real-‐Ame dynamically

fluctuaAng load management

194

Delivering power services with BitWits (digital knowledge), instead of atoms & molecules (natural resources)

195

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