116805823 Water and Shale Gas Development

8/12/2019 116805823 Water and Shale Gas Development

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Water and Shale Gas DevelopmentLeveraging the US experience in new shale developments


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Global development of shale gas resources hasthe potential to expand significantly outsidethe United States. However, there continue tobe environmental concerns, particularly withrespect to water use. As operators outside theUnited States explore shale gas, there are many

lessons that can be taken from the UnitedStates experience. This paper highlights areasthat operators of new shale developmentsshould consider. It also includes an analysisof considerations for Argentina, China, Polandand South Africa focusing on water regulation,water use and management, and water

movements during shale gas development.


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1 Introduction 4

Overview of shale gas life cycle activities 8

1.1 Shale resources outside the United States 9

In Focus: Shale developments in Argentina, China, Poland and South Africa 12

2 Water regulation 18

2.1 Regulatory history and the current landscape 19

2.2 Federal efforts to support regulatory consistency 21

2.3 Key trends 22

In Focus: Water regulation in Argentina, China, Poland and South Africa 23

3 Water management 26

3.1 Water use and production 27

Comparison: Managing produced water: unconventional vs. conventional 30

3.2 Water management options 31

Primer: Water treatment technologies 33

3.3 Key trends 34

In Focus: Water use/management in Argentina, China, Poland and South Africa 35

4 Water movements 42

4.1 Shale gas development life cycle: logistics requirements 43

4.2 Significance of water transportation 45

4.3 Rising to the water transportation challenge 45

4.4 Key trends 46

In Focus: Water movements in Argentina, China, Poland and South Africa 47

Concept Overview: Basin-wide water logistics management model 49

5 Lessons learned for new shale developments 52

In Focus: Implications for Argentina, China, Poland and South Africa 57

6 Implications for operators 60

Overview of the challenges in the shale gas lifecycle 63

Contents


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1IntroductionNatural gas production in the United States has grown significantlyin recent years as improvements in horizontal drilling and hydraulicfracturing technologies have made it commercially viable to recovergas trapped in tight formations, such as shale and coal. The UnitedStates is now the number one natural gas producer in the worldand, together with Canada, accounts for more than 25 percent ofglobal natural gas production.1Shale gas will play an ever-increasingrole in this resource base and is projected to increase to 49 percentof total US gas production by 2035, up from 23 percent in 2010,highlighting the significance of shale gas in the US energy mix inthe future. Lower and less volatile prices for natural gas in the pasttwo years reflect these new realities, with benefits for Americanconsumers and the nations competitive and strategic interests,including the revitalization of several domestic industries.2


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In its 2012 Annual Energy Outlook, theU.S. Energy Information Administration(EIA) referred to the enormouspotential of shale gas, and accordingto the Institute for Energy Research,the United States has enough naturalgas to meet domestic electricitydemand for 575 years at current fueldemand for generation levelsenough

natural gas to fuel homes heatedby natural gas in the United Statesfor 857 years and more natural gasthan Russia, Iran, Qatar, Saudi Arabiaand Turkmenistan combined.3

As Figure 1 illustrates, US shale gasreserves are vast and broadly dispersed;the EIA estimates that the lower 48states have a total of 482 trillion cubicfeet of technically recoverable shalegas resources with the largest portionsin the Northeast (63 percent), GulfCoast (13 percent), and Southwestregions (10 percent), respectively. Thelargest shale gas plays are the Marcellus(141 trillion cubic feet), Haynesville

(74.7 trillion cubic feet), and Barnett(43.4 trillion cubic feet). Activity innew plays has increased shale gasproduction in the United States from11 billion cubic meters (bcm) in 2000to 140 bcm in 2010.4Such productionpotential has the ability to change thenature of the North American energymix and according to the National

Petroleum Council 2011 study, PrudentDevelopment: Realizing the Potentialof North Americas Abundant NaturalGas and Oil Resources, the naturalgas resource base could support supplyfor five or more decades at current orgreatly expanded levels of use.5

Water regulationThis rapid expansion in shale gasproduction has given rise to concernsaround the impact of operations inareas such as water, road, air quality,seismic and greenhouse gas emissions(GHG). The process of hydraulicfracturing (fracking) in a shale gas well

requires significant volumes of waterand causes additional greenhouse gasemissions compared to conventionalgas wells. There is already significantresistance to shale gas developmentdue to these water and emissionconcerns in many parts of the UnitedStates and Western Europe, with Franceand Bulgaria imposing nationwidemoratoriums on shale gas productionthrough fracking. The regulation ofshale gas is an evolving landscapeas the industry has developed sorapidly that it has often outpacedthe availability of information forregulators to develop specific guidance.

Woodford

Bakken***

EagleFord

Haynesville-Bossier

Black Warrior

Basin

Floyd-Neal

Arkoma Basin

Anadarko

Basin

Valley & RidgeProvince

Tuscaloosa

TX-LA-MS

Salt Basin

IllinoisBasin

Forest

City Basin

MichiganBasin

NewAlbany

ChattanoogaFayetteville

Excello-Mulky Cherokee Platform

DenverBasin

Raton

BasinSan Juan

Basin

Palo DuroBasin

Williston

Basin

Gammon

Mowry

Niobrara*ParkBasin

Piceance

Basin

Paradox BasinHermosa

Uinta Basin

Powder RiverBasin

Heath**

MontanaThrustBelt

Niobrara*

Cody

Big HomBasinHilliard

BaxterMancos

Greater GreenRiver Basin

Permian

Basin

PearsallWesternGulf

Marfa

Basin

Pierre

Lewis

Ft. WorthBasin

ArdmoreBasin

Monterey-Temblor

San Joaquin

Basin

MontereySanta Maria

Ventura,

Los Angeles

Basins

Antrim

Appalachian

Basin

Avalon-Bone Spring

Mancos

Devonian (Ohio)

ManningCanyon

Barnett-Woodford

Utica

Marcellus

Bend Conasauga

Barnett

Shale plays Current plays

Prospective plays

Stacked plays Shallowest/youngest Intermediate depth/age

Deepest/oldest

Basins

* Mixed shale &chalk play

** Mixed shale &Iimestone play

*** Mixed shale &tight dolostone-

siltstone-sandstone

Source: Shale Gas and Oil Plays, Lower 48 States, U.S. Energy Information Administration, www.eia.gov.

Figure 1. US lower 48 states shale gas plays.


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At present, the US shale gas industryis regulated by a patchwork of existingoil and gas regulations on drillingand well site activities, combinedwith environmental regulations onwater and air management. This looseregulatory landscape is beginningto change with growing state andfederal attention. In 2010, the U.S.

Environmental Protection Agency(EPA) launched a four-year field studyon the impact of shale gas hydraulicfracturing and, in 2011, the U.S.Department of Energy received a reportby the Secretary of Energy AdvisoryBoard (SEAB) for shale gas providingrecommendations on how to reducethe environmental impact and improvethe safety of shale gas production. Inaddition to these reports, numeroussmaller studies continue to provide

information to support improvementsin regulation and leading practice.

In 2010, New York issued a temporarymoratorium on additional shale gasdevelopment to allow the statesDepartment of EnvironmentalConservation (DEC) to finish itsSupplemental Generic EnvironmentalImpact Statement (SGEIS) on issuessurrounding natural gas drilling.New York published a Revised DraftSGEIS on September 28, 2011, which

was open for public comment untilJanuary 2012.6 There has been nofurther movement from the DEC on themoratorium. In June 2011, MarylandGovernor Martin OMalley issued anorder calling for a three-year study ofthe economic and environmental effectsof drilling the Marcellus Shale beforepermits to drill can be issued. And inAugust 2011, New Jersey GovernorChris Christie placed a one-yearmoratorium on hydraulic fracturing so

that the Department of EnvironmentalProtection can further evaluate thepotential environmental impacts ofthis practice in New Jersey, as wellas evaluate the findings of ongoingfederal studies.7 (Note, however, thatno hydraulic fracturing operations weretaking place in New Jersey when themoratorium was issued.) Several otherstates, howeverincluding Wyoming,Pennsylvania, Arkansas, Colorado,Louisiana and Texashave passed newlegislation or regulations in response

to the increased activity associatedwith natural gas development.

Water use andmanagementOne of the most contentious and widelypublicized issues in shale gas productionis water management. Shale gasproduction is a highly water-intensiveprocess, with a typical well requiringaround 5 million gallons of water to drilland fracture, depending on the basinand geological formation.8The vastmajority of this water is used during thefracturing process, with large volumesof water pumped into the well with sandand chemicals to facilitate the extractionof the gas; the remainder is used inthe drilling stage, with water being themajor component of the drilling fluids.Relatively small amounts of water arealso used for dust suppression on site,and for the cleaning and flushing of

drilling equipment. Although increasingvolumes of water are being recycled andreused, freshwater is still required in highquantities for the drilling operations asbrackish water is more likely to damagethe equipment and result in formationdamage that reduces the chance of asuccessful well. The need for freshwateris a growing issue, especially in water-scarce regions and in areas with highcumulative demand for water, leadingto pressure on sources and competition

for water withdrawal permits. Thepressure to increase efficiencies is highas industry demand for water grows withthe development of more wells.

Water contamination is anotheraspect of shale gas production thathas generated significant resistanceto current shale production processes.According to the MassachusettsInstitute of Technology (MIT) 2011 Gasreport, which reviewed three studiesof publicly reported incidents related

to gas well drilling, there were only 43widely reported water contaminationincidents related to gas well drillingin the past decade (to 2010) duringwhich time, there were about 20,000shale gas wells drilled with almost allof them being hydraulically fractured.Of these, 48 percent of the incidentsinvolved groundwater contaminationby natural gas or drilling fluids; 33percent involved on-site surface spills;10 percent involved water withdrawal

and air quality issues, and blowouts; and,the remaining 9 percent involved off-sitedisposal issues (see Figure 2).

Regarding contamination incidents,the MIT report stated that with over20,000 shale wells drilled in the last 10years, the environmental record of shalegas development has for the most partbeen a good onebut it is importantto recognize the inherent risks and thedamage that can be caused by justone poor operation. In the studies

surveyed, no incidents are reportedwhich conclusively demonstratecontamination of shallow water zoneswith fracture fluids.9

In areas with deep unconventionalformations, such as the Marcellusareas in Appalachia, the shale gasunder development is separated fromfreshwater aquifers by thousands offeet and multiple confining layers. Toreach these deep formations where thefracturing of rock occurs, drilling goesthrough the shallower areas, with thedrilling equipment and production pipesealed off using casing and cementingtechniques. A new voluntary chemicalregistry (FracFocus) for disclosingfracturing fluid additives was launchedin the spring of 2011 by the GroundWater Protection Council (GWPC) andthe Interstate Oil and Gas CompactCommission (IOGCC). Texas operatorsare required by law to use FracFocus.The IOGCC, comprised of 30 member

states in the United States, reportedin 2009 that there have been no caseswhere hydraulic fracturing has beenverified to have contaminated water.A key objective of the EPAs ongoingstudy is to better understand thefull life-cycle relationship betweenhydraulic fracturing and drinkingwater and groundwater resources.10

The movement and disposal of producedwater from fractured wells is also apart of the debate on the environmentalimpact of shale gas production.After fracturing, each well returns apercentage of the injected fracturefluid volume over its lifetime; this wateris heavily polluted, creating a risk ofgroundwater contamination upon itsreturn to the surface if not correctlycontained and treated. Concerns aroundsuch risks have led to the moratoriumon shale gas development in New

Yorks Marcellus Shale. In addition tothe nature of the produced water, the

growing volumes of wastewater areincreasing demand for efficienciesin water treatment technologies toimprove water reuse and


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recycling. Innovative water managementsolutions are required to address thelong-term sustainability of water use inshale gas production.

Water movementsThe volume of equipment, materialsand water required to support shale

gas operations presents a significantlogistics challenge. Given the remotenature of most locations and thefrequent operations movements acrosshighly dispersed and numerous well sitelocations, flexibility is required in thetransport model making road transportthe logistics model of choice for mostenvironments. While pipeline and railmovements can be effective for long-distance or point-to-point movements,the final distribution to and from thewell pad is almost exclusively managedvia road transport. Road transportvolumes and types vary significantlydepending on the operational phase ofthe project, with the majority of demandduring the fracking and completionphases, which can account for 6085percent of total transport volumes.Some large operations are required tosource, plan and manage up to 300truck movements per day within asingle basin, which is the equivalent ofa pan-regional transport operation in

many other sectors. This concentrationcreates significant challenges, withon-site congestion causing issues to theoperations teams and local residents,and leading to significant cost exposureto an already marginal cost operation.

The high volume and intensity ofroad transport associated with shalegas production present some uniquechallenges for operators. A shortageof transport operators with sufficient

knowledge, difficulties in tracking andoptimizing delivery schedules, reducingburden on strained road infrastructure,and a lack of standardized reportingand regulatory data can all lead tohigh costs, Health Safety SecurityEnvironment (HSSE) exposure, andregulatory compliance issues. Withup to 30 percent of completion costsrelated to transportation, operatorsare exploring different options toreduce transport activity, with akey focus on water hauling, which

can represent up to 80 percent oflogistics activity. Research into water-free fracking, on-site treatment anddisposal and assessment of alternativemodes of transport are all beingpursued, but are currently unable togenerate significant impact. Within theboundaries of current capabilities, theadoption and integration of logistics

leading practice provide the moststraightforward, technology-readyapproach to reducing transport costand regulatory and HSSE exposure.

Improvements in water movementsalso have an impact on other aspectsof shale operations, specifically HSSEexposure, operational performanceand compliance.

HSSE exposure

Improved transport planning processesand systems can reduce the numberof truck moves, while telematicssystems can provide real-time visibilityof truck movements and driverperformance, supporting reductionin wait times, less congestion andbetter driver HSSE compliance.

Operational performance

Better monitoring and planningcapabilities will reduce bottlenecksand smooth delivery into a site (e.g.,managed slot windows, dynamicre-routing to avoid congestion).Availability of accurate operational datacan allow operators to identify issuesand enable continuous improvement

in both drilling and transportation.Logistics costs can be reduced throughefficiency gains (e.g., reduction ofwaiting time) and automated processescan reduce administrative costs. Pastimplementations have shown thatconsistent adoption of logistics leadingpractices can deliver up to 45 percentreduction in transport costs.

Compliance

The use of a water inventory monitoring

tool can support water managementregulatory compliance through visibilityof water draw, usage and movements.Automated end-to-end processes andsystems enable accurate and rapiddata capture, storage and reporting.A cross-operator, basin-wide solutionwould also confirm consistent basin-wide reporting standards acrossmultiple 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.


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Civil/site prepForest clearing, excavation, buildingof access routes, constructing andinstalling wells pads and preparing

site for drilling activities.

DrillingNatural gas will not readily flow tovertical wells because of the lowpermeability of shales. This can beovercome by drilling horizontal wellswhere the drill bit is steered fromits downward trajectory to follow ahorizontal trajectory for one to twokilometers, thereby exposing thewellbore to as much of the reservoir

as possible.

Completion/frackingAs drilling is completed, multiplelayers of metal casing and cement areplaced around the wellbore. After the

well is completed, a fluid composed ofwater, sand and chemicals is injectedunder high pressure to crack the shale,increasing the permeability of the rockand easing the flow of natural gas.

FlowbackA portion of the fracturing fluid willreturn through the well to the surfacedue to the subsurface pressures. Thevolume of fluid will steadily reduce andbe replaced by natural gas production.

ProductionThe fissures created in the frackingprocess are held open by the sandparticles so that natural gas from withinthe shale can flow up through thewell. Once released through the well,the natural gas is captured, stored andtransported away for processing.

Overview of shale gas life cycle activities

Typical

timelines

Civil/site prepBuild access

roads, construct

and install well

pads, prepare site

for drilling

DrillingDrill vertical and

horizontal wells

Completion/frackingComplete wells

with steel and

cement casings

Release gas

through

hydro-fracking

FlowbackCapture, store

and treat

returned fracking

fluids

ProductionCapture, store

and transport gas

Decommission

60 days 15-60 days 15-30 days 20 days 540 years

Source: Accenture 2012.

Figure 3. Shale gas lifecycle.


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1.1Shale resourcesoutside the

United StatesAlthough estimates are likely to changeover time as additional informationbecomes available, the internationalshale gas resource base is currentlyconsidered to be significant. The initialestimate of technically recoverableshale gas resources in the 32 countriesexamined in the EIAs World ShaleGas Resources study is 5,760 trillioncubic feet (see Figure 4). Adding the USestimate of the shale gas technicallyrecoverable resources of 862 trillioncubic feet results in a total shaleresource base estimate of 6,622 trillion

cubic feet for the United States andthe other 32 countries assessed. Toput this shale gas resource estimatein context, the worlds technicallyrecoverable gas resources are roughly16,000 trillion cubic feet, largelyexcluding shale gas.11Thus, addingthe identified shale gas resources toother gas resources increases total

world technically recoverable gasresources by more than 40 percentto 22,600 trillion cubic feet.12

The estimates of technically recoverableshale gas resources for the 32 countriesoutside the United States representa moderately conservative riskedresource for the basins reviewed. Giventhe relatively sparse data currentlyavailable and the differences inapproaches employed to determine theresources, these estimates are quiteuncertain. At the current time, thereare efforts under way to develop more

detailed shale gas resource assessmentsby the countries themselves, with manyof these assessments being assisted bya number of US federal agencies underthe auspices of the Global Shale GasInitiative (GSGI) that was launched inApril 2010.

At a country level, there are two country

groupings that emerge where shale gasdevelopment appears most attractive.The first group consists of countriesthat are currently highly dependentupon natural gas imports, have at leastsome gas production infrastructure, andtheir estimated shale gas resources aresubstantial relative to their current gasconsumption. For these countries, shalegas development could significantlyalter their future gas balance, whichmay motivate development. Examplesof countries in this group includeChile, France, Morocco, Poland, SouthAfrica, Turkey and Ukraine. In addition,

Legend

Assessed Basins with Resource Estimate

Assessed Basins without Resource Estimate

Countries within Scope of EIA Report

Countries outside Scope of EIA Report

Figure 4. Map of 48 major shale gas basins in 32 countries.

Source: World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States,U.S. Energy Information Administration, 2011, www.cia.gov.


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South Africas shale gas resourceendowment is interesting as it maybe attractive to use this natural gasas a feedstock to its existing gas-to-liquids (GTL), coal-to-liquids (CTL)plants and combined cycle gas turbine(CCGT) currently running on diesel.

The second group consists of those

countries where the shale gas resourceestimate is large (e.g., above 200 trillioncubic feet) and there already existsa significant natural gas productioninfrastructure for internal use or forexport. In addition to the United States,notable examples of this group includeAlgeria, Argentina, Australia, Brazil,Canada, China, Libya and Mexico.Existing infrastructure would aid inthe timely conversion of the resourceinto production, but could also leadto competition with other natural gassupply sources. For an individual countrythe situation could be more complex.

Outside the United States thereare certain shale plays that couldchange the energy security of thecountries in which they are located.These include the following:

Argentina The NeuqunBasinAccording to the EIA, Argentina has774 trillion cubic feet of technicallyrecoverable shale gas, making it theworlds third-largest player in the shalegame behind the United States andChina. Located on Argentinas borderwith Chile, the 137,000 km NeuqunBasin is the South American nationslargest source of hydrocarbons, holding35 percent of the countrys oil reservesand 47 percent of its gas reserves.Within the basin, the Vaca Muerta Shale

formation may hold as much as 240trillion cubic feet of exploitable gas.ExxonMobil has recently entered intoan agreement with Americas Petrogasfor the Exploration and Production(E&P) farm-out of 163,500 gross acresof its Neuqun-based Los Toldos blocks.This area is also being explored anddeveloped by Shell, Apache, EOG, Totaland Wintershall, among others.

Argentinas biggest energy company,YPF, has found unconventional shale oiland natural gas in Mendoza province,confirming the extension of the massive

Vaca Muerta area. YPF said explorationat the Payun Oeste and Valle del RioGrande blocks pointed to an estimatedone billion barrels of oil equivalent(boe) in unconventional oil and gas in

Mendoza. Energy resources and reservesin the province, which border the Andesmountain range in western Argentina,currently stand at 685 million boe.

Canada Horn RiverShale BasinBritish Columbias Horn River ShaleFormation is the largest shale gasfield in Canada and part of Canadiandeposits that amount to as much

as 250 trillion cubic feet of naturalgas. Since 2008, a total of ninecompanies has ventured into the HornRiver market, including ExxonMobil,Apache, Devon Energy and Encana.

While large-scale commercialproduction of shale gas has not yet beenachieved in Canada, many companiesare now exploring for and developingshale gas resources in Alberta, BritishColumbia, Quebec and New Brunswick.Development of shale gas, and otherunconventional resources, will helpconfirm supplies of natural gasare available to the growing NorthAmerican natural gas market for manydecades. Encana, Canadas largestnatural gas producer and one of thebiggest in North America, is lookingfor a single partner for a package ofassets that could include positions inthe Collingwood Shale, the TuscaloosaMarine Shale, the Mississippi Limeand the Eaglebine Shale in the United

States. All have natural gas liquids or oilpotential and are in the early stages ofexploration and development.

China Sichuan andTarim BasinIn 2011, the EIA estimated thatChina had 1,275 trillion cubic feetof technically recoverable shalegas. Since then a geological surveyled by China Ministry of Land andResources (MLR) confirmed a total of882 trillion cubic feet of technicallyrecoverable shale gas, excluding Tibet.The Sichuan Basin, located in south-central China, covers a large 211,000km2and accounts for 40 percent ofthe countrys shale resources.13

China hopes to produce between 60billion and 100 billion cubic meters ayear by 2020an objective that someanalysts are skeptical can be achieved.Royal Dutch Shell has recently signed

the first production-sharing contract toexplore, develop and produce shale gasin China, a move that fits in with Chinasoverall strategy to bring technicaland operational know-how to thedevelopment of its untapped reservesof the unconventional fuel. CNOOCLtd., Chinas biggest offshore energyproducer, plans to develop new fields,acquire overseas assets and developunconventional resources such as shalegas to meet output targets. The countryis determined to learn shale-gastechnology from its partners and deployit in China, holder of the worlds largestdeposits of the fuel, Chairman Wang

Yilin has stated.14

Poland Baltic-Podlasie-Lublin BasinsThe EIA has assessed that EasternEurope may hold as much as 250 trillioncubic feet of shale gas, with Polands

Silurian Shale plays boasting 187 trillioncubic feet of that total. The RussiaFederation currently supplies 25 percentof Europes natural gas, and Polandspotential shale resources could reduceEuropes dependence on natural gasimports. Whether these reserves willbe developed is still to be seen, but the38-million-strong Slavic nation will havea strong claim to energy independenceas its projected reserves equate to 300years of domestic consumption.


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Several companies including ExxonMobiland Chevron have begun to drill testwells and more than 100 companiesrushed to grab a share of Polands gasconcessions. Some of those early testsproduced decent flows, but othersshowed quite different results fromwells drilled into US shale deposits.ExxonMobil said its two test wells did

not justify commercial production.ExxonMobil said in January 2012 thattwo exploratory wells failed to flowenough gas to make developmentprofitable. In June 2012, ExxonMobilannounced it would end its search forshale gas in Poland.15Flow rates atsites drilled by 3Legs Resources Plc. andBNK Petroleum Inc. were not as high assimilar wells in the United States.

South Africa The Karoo

SupergroupKnown by paleontologists as one of theworlds most fertile hunting grounds forfossil remains, the Karoo Supergroup(KSG) might also be one of the mostplentiful sources of shale gas in theworld. The KSG is constituted mainly ofshales and sandstones and spans across88,000 km, underlying more thantwo-thirds of the entire area of SouthAfrica and containing an estimated

485 trillion cubic feet of technicallyrecoverable gas. Shale gas could reducethe countrys dependence on coal tofuel 85 percent of its energy needs.

Other regionsIndias Oil and Natural Gas Corp (ONGC)and US oil company ConocoPhillips havesigned an agreement to explore anddevelop shale gas assets and look foropportunities in deepwater exploration.The agreement is for sharing technicalknowledge on shale gas explorations,

but ONGC and ConocoPhillips couldalso jointly bid for shale gas assetsoverseas. India may still launch the firstshale gas licensing round by the endof 2013 even though the governmentpushed back plans to unveil a policyon exploration of unconventionalgas resources trapped in rocks.


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A key objective of this report is tohighlight the trends and lessons learnedfrom shale development in the UnitedStates that can be applied to shaledevelopments in other geographies. Toemphasize this point, we will presentfour case studies in this report of fourvery different shale developments:Argentina, China, Poland and South

Africa. The following is a detaileddescription of these shale developments.

ArgentinaArgentina is the largest natural gasproducer in South America with 1,416billion cubic feet (bcf) annual output in2010.16Natural gas prices in Argentinawere kept low by the governmentsince the economic crisis in 2002.As a result natural gas productiondropped almost 15 percent from itspeak of 1,628 bcf and natural gastested reserves dropped 50 percentto only 13.4 trillion cubic feet

in 2011 due to decreasing explorationactivities in the past decade.17Meanwhile, the demand for natural gasin Argentina has increased in recentyears in line with economic growth,and the country has had to rely on gasimports from neighboring Bolivia andLiquefied Natural Gas (LNG) shipments.Shale gas has brought new hope for

addressing energy demands. Basedon an EIA estimation, Argentina has774 trillion cubic feet of technicallyrecoverable shale gas, which is almost60 times that of its current testednatural gas reserves.18To encouragedomestic natural gas explorationand production, the Argentiniangovernment introduced its GasPlus program in 2008 to allow newdiscovered unconventional gas to besold at a higher price based on costand reasonable profit.19This incentive

program allows approved companies tocharge up to $5/thousand cubic feet(mcf) for their natural gas production.

The Neuqun Basin covers the Neuqunprovince and parts of Mendoza, RioNegro and La Pampa provinces incentral-west of Argentina, holding 407trillion cubic feet of the countrys 774trillion cubic feet estimated resources.This basin largely overlaps with existingnatural gas production regions. The

Neuqun province alone currentlyproduces almost half of the nationsconventional gas.20The geologicalformation of the Neuqun Basin is verysimilar to major US shales with theaverage depth of the 204 trillion cubicfeet of recoverable shale gas in the VacaMuerta formation within the NeuqunBasin at 2,400 meters. Geologicalfeatures and existing local natural gasinfrastructure make future developmentin the Neuqun Basin very promising.Other basins including the San Jorge

Basin and the Austral Magallanes Basinhave 95 trillion cubic feet and 172trillion cubic feet reserves, respectively.

In Focus

Shale developments in Argentina, China, Poland andSouth Africa

Legend Neuqun Basin

Thrust Fault

City

Water

Productive Area

Extensional Structures

An

des

Mo

un

tain

s

Cuyo

Basin

Co

lora

do

B

as

in

Agri

dFo

ld&

Th

rus

tB

elt

HuinculArch/

DorsaldeNeuquen

North

Patagonian

Massif

Neuqun

Figure 5. Neuqun Basin Shale Gas Prospective Area and Basemap.

Source: World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States,U.S. Energy Information Administration, 2011, www.eia.gov.


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Many shale operators have startedexploration activities in Argentina.Apache partnered with YPF, previouslycontrolled by Repsol, but wasrenationalized in April 2012 by theArgentinian government, to exploreunconventional resources includingshale gas in the Neuqun and AustralBasins. Apache has been awarded

1.6 million gross acres (3,642 km2)in the Neuqun Basin for shale gasdevelopment and the company drilledthe first horizontal multi-fracture shalegas well in South America in 2011.21InMay 2011, one of Apaches horizontalwells in the Neuqun Basin tested ata rate of 7 million cubic feet (mmcf)/day. Canadian firm America Petrogas

joined with ExxonMobil to explore 660km2of blocks in the Neuqun Basin.The company drilled a test well together

with ExxonMobil and the result isunder evaluation.22With undergoingexploration activities, EIAs originalestimation on Argentinas shale gaspotential is waiting to be confirmedwith new data from the operators.

ChinaThe recent success of shale gasdevelopment in the United States, aswell as a domestic push to reshape theenergy structure to reduce dependenceon coal, has put shale gas under thespotlight in China. In December 2011,the China State Council approved shale

gas as a new type of natural resourcethat will be managed separately fromconventional gas.23In March 2012,the National Development and ReformCommission (NDRC) issued its Shale GasDevelopment Plan (20112015)24thatsets clear targets for the industry by2015 and 2020. However, the shale gasindustry in China remains at an earlystage with most activity in explorationand drilling of test wells.

Data from a recent Ministry of Land andResources (MLR)-led geological surveyshows China has 882 trillion cubicfeet of technically recoverable shalegas resources, a lower figure than theEIAs estimate. Figure 6 illustrates shalegas distribution in China. The SichuanBasin in the Upper Yangzi region andsouthwest China (a region covering

Sichuan, Chongqing, Yunnan, Guizhouand Guangxi provinces) has 10 trillioncubic meters (350 trillion cubic feet) ofshale gas, which equates to 40 percentof total national reserves. Unlike USformations, where most shale seamsare at depths of less than 3,000 meters(with the exception of the HaynesvilleShale), the shale-bearing layers in manyChinese formations are between 3,000to 5,000 meters deep. Therefore, USshale gas development models cannot

be simply replicated in China and thecomplex geological conditions willincrease the cost of drilling wells.

Northwest zone

15%

North and

Northeast zone

26%

Lower Yangzi &

Southeast zone

19%

Upper Yangzi &

Southwest zone40%

Sichuan

Chongqing

Guizhou

Guangxi

Yunnan

Source: China Ministry of Land and Resources, Peoples Republic of China, www.mlr.gov.cn.

Figure 6. Shale gas distribution in China.


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The shale gas industry has, for thefirst time, been put in a strategicallyimportant position in the governments12thfive-year energy plan (20112015).In addition, the Shale Gas DevelopmentPlan (20112015) states that by 2015,the government aims to complete aninvestigation on shale gas reserves andtheir national distribution. The plan also

estimates annual production reaching6.5 billion cubic meters (230 billioncubic feet) and confirmed technicallyrecoverable reserves reaching 600billion cubic meters (21 trillioncubic feet) by 2015. With almost nocommercial production today, reachingsuch targets will require significantinvestment at each stage of the valuechain in the next couple of years, aswell as technology development andcollaboration between national oil

companies (NOCs) and experienced shalegas operators from other countries.

NOCs and state-owned entities havebeen the first to be allowed to exploreand develop shale gas resources inChina. So far most activities are inexploration, with only very limitedcommercial production. The three majorNOCs (CNPC, Sinopec and CNOOC),

Yangchang Petroleum Group, and ChinaUnited Coalbed Methane Co (ChinaCBM) are actively involved in shale gas

exploration. By the end of 2011, CNPChad drilled 11 test wells in southernSichuan and northern Yunnan, four ofwhich had exhibited industrial-levelgas flow. Sinopec has its explorationactivities mainly in Guizhou, AnhuiSichuan and Chongqing. In Chongqing,Sinopec has shale gas production inLiangping County with an estimatedannual output 300500 million cubicmeters (1018 billion cubic feet).25

Yanchang Group is very active in its

traditional territory of Shannxi provinceand has successfully fracked the firsthorizontal well in China.

China CBM has proposed to startexploring three regions in Shanxiprovince.26In the first round of nationalshale gas exploration rights auctions,organized by the MLR, Sinopec andHenan Coal Bed Methane Co won thebid. A second round of auctions is dueto start in late 2012.

International oil majors are activelypartnering with NOCs to enter Chinasshale gas market. CNPC and Statoilbegan test drilling in China in early2011. Sinopec has teamed with BP toexplore shale gas in Guizhou in 2010,

joined forces with ExxonMobil toconduct geological research in Sichuan,and is also working with Chevron inGuizhou to carry out risk assessments.Shell is the most active international oilcompany (IOC) in China, and has alreadysigned the first production-sharingcontract with CNPC to explore, developand produce shale gas.

PolandPoland has the most significant shalegas potential in Europe. Polandsshale gas resources are located inthe Baltic-Podlasie-Lublin Basins (seeFigure 7), creating a strip across thecountry from northwest to southeast.The EIA estimates 187 trillion cubic

feet of technically recoverable shalegas resources in the Baltic-Lublin-Podlasie Basins of Poland; of those,120 trillion cubic feet are in theBaltic Basin.27A report released inMarch 2012 by the Polish GeologicalInstitute was able to confirm 67 trillioncubic feet of technical recoverableshale gas resources in these threebasins after a 16-month researchproject with external support fromthe U.S. Geological Survey.28

The average depth of shale formationsin Poland is from 2,500 to 3,800 meters,which is up to twice as deep as theaverage depth of 2,000 meters observedin the Marcellus Shale.29 30Variationshave been observed among differentbasins, with 1,0004,500 meters depthfor the Baltic Basin, 1,0003,500 metersdepth for the Lublin Basin, and 4,000

5,000 meters depth for the PodlasieBasin (near Warsaw). These geologicalcharacteristics could likely result inhigher drilling costs, linked to higherdemands on water in the drilling stages.

Shale gas activities in Poland startedin 2007; by September 2011, a total of101 shale gas exploration authorizationshad been granted and another 26applications were being processed.31International oil majors have enteredthe Polish market in the form of jointventures. 3Legs Resources formeda joint venture with ConocoPhillipsto evaluate shale gas potential inthe Baltic Basin and drilled the firstexploration well in Poland. PKN andPGNiG are the most active Polishoperators. As of August 2011, basedon square kilometers covered, the top10 concession holders in Poland were:(1) San Leon Energy with 14 licensescovering 11,520 km2, (2) ExxonMobil, (3)PKN Orlen, (4) Chevron, (5) Marathon

Oil & Gas, (6) BNK Petroleum, (7)3Legs Resources, (8) Nexen, (9)ConocoPhillips and (10) Petrolivest.32


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With authorizations received, currentindustry activities have moved ontodrilling of testing wells. 22 explorationwells were started in 2011 and 13 wellswere completed by February 2012. 14new exploration wells were plannedfor late 2012 and as many as 123 wellsare planned by 2017.33So far, state-owned PGNiG, 3Legs Resources, BNK,

Talisman Energy, Marathon Oil andExxonMobil have all completed theirfirst batch test wells. ExxonMobil, BNKand 3Legs released rather disappointingresults, stating that the gas flows intheir testing wells are lower than similarprospects in US shale and commercialproduction cannot be justified.34Despite this negative news, the Polishgovernment strongly believes shalegas would help to reduce the nationsenergy dependency on Russia and cut

greenhouse gas (GHG) emissions through

transforming the coal-based electricitygeneration sector. A consortium formedwith state-owned power utilitiescompanies and PGNiG will co-financeand co-develop shale exploration alongthe Baltic coast. Utilities will financeexploration activities in exchangefor future gas supplies in off-takeagreements.35Polands Treasury Minister

said the country may be producing onebillion cubic meters (35 billion cubicfeet) of shale gas per year by 2014.36

Figure 7. Map of Polands shale gas basin.

Legend

Trans-European Fault Zone

Faults

National Capitals

Major Cities

Poland Shale Basins

Prospectivity

Non-Prospective

Prospective

Baltic Basin

Lublin Basin

Podlasie BasinPoznan

Lodz

Katowice

Krakow

Berlin

Gdansk

Kaliningrad

Mazury - Belarus High

Bialystok

Brest

Lublin

Czestochowa

Ostrava

Szczecin

Bydgoszcz

Warsaw

Source: World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, U.S.Energy Information Administration, 2011, www.eia.gov.


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South AfricaSouth African electricity generationis currently heavily coal-based. TheDepartment of Energy intends tohave 9 percent of energy from opencycle gas turbines by 2030 and shalegas could help to reach this target.37According to the EIA, South Africa has

an estimated 485 trillion cubic feetof technically recoverable shale gaslocated in the Karoo Basin (see map,Figure 8). Of this, 298 trillion cubicfeet is believed to be in the WhitehillShale.38The real volume of shale gasreserves is still waiting to be confirmedthrough physical exploration activities.

Unlike Poland and China, where shalegas formation are buried deeperthan the United States, the averagedepth of shale gas in South Africa

is 2,500 meters (8,000 feet),39which is quite similar to the Barnett

Shale.40However, the Karoo Basincontains significant areas of volcanicintrusions that impact the qualityof the shale gas resources, limit theuse of seismic imaging and increasethe risk of shale gas exploration.

A number of companies have startedpursuing shale gas development in the

Karoo Basin by obtaining TechnicalCooperation Permits (TCPs) from theSouth Africa Petroleum Agency (seemap, Figure 8). Shell is the biggestTCP holder with 185,000 squarekilometers of land in the Karoo Basin.Falcon Oil and Gas has 30,000 squarekilometers of TCPs. Sasol, Chesapeakeand Statoil have formed a joint ventureand together hold 88,000 squarekilometers of TCPs, but in December2011, Sasol decided to put its Karooshale gas plan on hold.41 Anglo Coaland Australian Sunset Energy alsohave their own TCPs. According to

South African regulations, TCPs allowno more than desktop research; withfurther applications required to obtainauthorization for physical explorationactivities. However, the applicationto convert these TCPs into physicalexploration licenses was suspendedover a year to allow the government toconduct policy and technical reviews

before final decisions.42On September7, 2012, the South Africa governmentaccepted the recommendations fromthe Department of Mineral Resources(DMR) and finally lifted the moratoriumon shale gas exploration.43

Ecca Group

Karoo Basin

Operator

Anglo Coal

Falcon Oil and Gas

Sasol/Statoil/Chesapeake

Shell

Sunset Energy

City

Maseru

Durban

East LondonPort Elizabeth

Cape Town

Johannesburg

Pretoria

Mbabane

South Africa

Botswana

Namibia

Lesotho

Swaziland

Shell

Falcon Oil and Gas

SunsetEnergy

Sasol/Statoil/Chesapeake

AngloCoal

Figure 8. Map of operators TCP coverage in the Karoo Basin.

Source: World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, U.S. Energy Information Administration, 2011,www.eia.gov.


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The topic of shale gas regulation is dominated by hydraulicfracturing, the key feature of shale gas that separates itfrom well-regulated conventional gas production. However,existing regulations to protect water resources during oil andgas development are also affected by the greater intensity ofwater, energy and infrastructure used in shale gas operations.This consequence is driving significant uncertainty in the USregulatory landscape, which is still adapting to the new industry.

The speed of industry growth has outpaced the availability ofrigorous data on its potential impact, which has hindered theability of government to adequately assess and regulate operations.This situation has led to a patchwork regulatory landscape andto a moratorium on shale gas development in New York State,France and Bulgaria. To resolve this issue, there has been renewedfocus by the US federal government on establishing betterunderstanding of the potential impacts of shale gas development,to most effectively regulate this critical new energy resource.

Water regulation

2


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2.1Regulatory historyand the current

landscapeHydraulic fracturing of gas wellsbegan in 1949; however, it remainedlargely unregulated until significantunconventional gas production beganaround the millennium with thecommercial development of coal-bed methane. As production grew,media reports and public complaintsof drinking water contaminationraised concerns, leading the EPA tocommission a study into the risks ofhydraulic fracturing to drinking water.In 2004, this study found that hydraulicfracturing of coal-bed methaneposed minimal threat to undergroundsources of drinking water, which wasa significant finding in support of theindustry. In 2005, following the EPAreport, the federal Energy Policy Actgranted hydraulic fracturing a specificexemption from the Safe DrinkingWater Act (SDWA), which regulates allunderground injection.

Since the Energy Policy Act passed in2005, shale gas production in the UnitedStates has grown significantly, from lessthan one trillion cubic feet in 2005 toover three trillion cubic feet in 2009.Such rapid growth, along with continuedreports of environmental effects, hasled to renewed calls for change in theregulatory landscape, particularly forthe federal government to provideincreased regulation or guidance. Thispressure led to the introduction to

congress of the FRAC Act in 2009,which sought to repeal the 2005 SDWAexemption and require disclosure ofcomponents used in all fracturing fluids.The bill was sent to committee butwas not passed to congress for vote. Inthe absence of new federal regulation,states have continued to use existing oiland gas and environmental regulationsto manage shale gas development, aswell as introducing individual stateregulations for hydraulic fracturing.

The current regulatory landscapeis comprised of an overlappingcollection of federal, state and localregulations and permitting systems,implemented by oil and gas, naturalresources and environmental agencies.A mapping of current federal and stateregulation is shown in Figure 9. Theseregulations cover different aspects of

the development and production of ashale gas well, with the intention thatthey combine to manage any potentialimpact on the surrounding environmentand water supplies. These combinationsof regulations have long served toregulate oil and gas development innumerous states; however, the newprocess of hydraulic fracturing issomething that has not previouslybeen managed by these regulations.Therefore, the related intensity in

terms of water, emissions and siteactivity mean existing regulations arebeing reassessed for their suitabilityfor this new production method.

Federal regulationsWith its exemption from the SDWA,hydraulic fracturing is not directlyregulated by federal standards. However,a number of federal laws still directoil and gas development, includingshale gas.44These regulations affect

water management and disposal, aswell as air quality and activities onfederal land. The Clean Water Actis focused on surface waters andregulates disposal of wastewater andalso includes authorizing the NationalPollutant Discharge EliminationSystem (NPDES) permit program, aswell as requiring tracking of any toxicchemicals used in fracturing fluids.

Outside water use, the Hazardous

Materials Transport Act and Oil PollutionAct both regulate ground pollutionrisks relating to spills of materials orhydrocarbons into the water table.

State regulationsRegulation of oil and gas productionhas traditionally occurred primarily atthe state level. This level of regulationis also the case for shale gas, withmost shale gas-producing statesissuing more rigorous standards thattake primacy over federal regulations,

as well as additional regulationsthat control areas not covered atthe federal level, such as hydraulicfracturing. Within states, regulationis carried out by a range of agencies.Energy or natural resource-focuseddepartments generally set requirementsfor site permits, drilling, completionand extraction, while environmentalor water departments regulate water,emissions and waste management.

The specific regulations vary

considerably among states, such asdifferent depths for well casing, levelsof disclosure on drilling and fracturingfluids, or requirements for waterstorage. The majority of states in shalegas-producing regions now have varyinghydraulic fracturing regulations ontheir books, specifically for disclosureof fracking fluids, proper casing ofwells to prevent aquifer contaminationand management of wastewater fromflowback and produced water. Disposal

of wastewater by underground injectionhas emerged as a point of concern forstate regulators due to large inter-stateflows of wastewater to states withsuitable geology for Class II disposalwells and reports of earthquakes nearsome well sites. States such as Arkansasand Ohio have placed local moratoriumson disposal wells in locations whereincreased seismic activity has beenrecorded and Ohio is developing rigorousnew standards for disposal wells.45


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Typicaltimelines

Civil/site prepBuild access roads,construct and installwell pads, prepare sitefor drilling

DrillingDrill vertical andhorizontal wells

Completion/frackingComplete wells withsteel and cementcasings

Release gas throughhydro-fracking

FlowbackCapture, store andtreat returnedfracking fluids

ProductionCapture, store andtransport gas

60 days 15-60 days 15-30 days 20 days

Federalregulatoryimpa

ct

The National Environmental Policy Act (NEPA)requires that exploration and production onfederal lands be thoroughly analyzed forenvironmental impacts.

Under the Clean Air Act, Nationalemission standards for hazardous air pollutants(NESHAP) are used to limit toxic pollutants.

Under the Clean Air Act, Engine NESHAP rulesregulate newly refurbished engines includingmonitoring and reporting requirements.

The US Environmental Protection Agency (EPA)has proposed new performance standards fortoxic air emissions for oil and natural gasproduction.

The US EPAadministers most of the federal laws.

States are able to implement federal regulations.

All states require a permit to drill and operatea well.

All states have regulations regarding drilling,abandonment and plugging of wells.

States regulate the effective casing andcementing of wells.

The Clean Water Act (CWA) regulates surfacedischarge of produced water and storm waterthrough the National Pollutant DischargeElimination System (NPDES) permittingprocess.

The CWA sets wastewater standards forindustry, and water quality standards for

contaminates in the surface water. The Oil Pollution Act (OPA) enforces spill

prevention requirements and reportingoperations.

The EPA has proposed that drillers use greencompletion techniques to reduce emissions ofvolatile organic compounds from wells.Green completions are required in Coloradoand Wyoming.

Comprehensive Environmental Response,Compensation and Liability Act (CERLA)enables the federal government to respond to

releases of hazardous substances that threatenhuman health or the environment.

The Safe Drinking Water Act(SDWA) excludesfracking from its Underground Injection Control(UIC)program.Instead, the EPA and statesimplement the UIC program to protectgroundwater resources. Forty states have primacyfor this with the EPA implementing theprogram directly in New York and Pennsylvania.

Groundwater is often protected under StatePollutant Discharge Elimination System(SPDES) permits rather than just discharges

to surface water, as with the NPDES permits.

In addition to state regulations, the DelawareRiver Basin Commission and SusquehannaRiver Basin Commissionimpose water quantitylaws.

States regulate hazardous wastes andimplement waste management procedures thatare exempt from the federal ResourceConservation and Recovery Act.

The U.S. Departmentof Interior Bureauof Land Management(BLM) is responsiblefor issuing frackingpermits on federallands.

Hazardous chemicalsmust be recorded onmaterial safety datasheets and reportedin the event of acrisis as part of theEmergency Planningand CommunityRight to Know Act.

Hazardous MaterialsTransportation Act

regulates thetransport of

hazardous materials.

Transportation ofwater, sand andadditives areregulated understate regulations.

Disclosure ofchemicals used infracking is regulatedat a state level, butregulations differ in

strength. Wyoming,Texas and Arkansasrequire disclosure ofall chemicals,Pennsylvania andMichigan onlyrequire disclosuredeemed hazardous,Louisiana andColorado areexpected toimplement disclosureregulations soon.

Stateregulatory

impact

Figure 9. Federal and state regulation mapped to the shale gas lifecycle.


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Other regulationsIn addition to federal and stateregulations, local governments andwater basin management commissionsalso control aspects of shale gasdevelopment in some regions. Inthe northeast, groups such as theSusquehanna River Basin Commission

and Delaware River Basin Commissionmanage water supply and disposalpermits across state and county lines.Local counties and municipalitiesalso play a role in local site andinfrastructure permitting.

The overlapping of authorities andimmaturity of the industry have led to avaried regulatory landscape for hydraulicfracturing and shale gas development.This situation creates considerablecomplexity for operators and other

stakeholders who should maintaincompliance across jurisdictions,creating a desire for standardization.The simplicity of standardizationshould, however, be balanced with theoptimization of regulations for localconditions. There is strong consensusthat maintaining regulatory primacyat the state level is preferred due tothe variations in geology, water, gascomposition and infrastructure indifferent shale gas basins, meaning

a one-size-fits-all national policy islikely to be sub-optimal for all parties.Federal focus is therefore on supportingstates in developing detailed shalegas regulations for their conditions,confirming they are transparent,data-backed and consistent.

2.2Federal efforts to

support regulatory

consistencyBased on the preference for stateprimacy, the EPA has assumed the roleof coordinating and supporting researchinto the impacts of hydraulic fracturingto provide rigorous data and guidancefor state regulation development. Inparticular, the EPA has undertaken amajor national study to understandthe impacts of hydraulic fracturing ondrinking water resources. The study willinclude a review of published literature,

analysis of existing data, scenarioevaluation, laboratory research andcase studies. The EPA will release initialstudy results in a report expected atthe end of 2012 and a final report atthe end of 2014.46The objective of thisstudy is to provide a definitive federalposition on the issue of fracking inshale gas, which will provide states withgreater clarity on what regulations arerequired to protect water resources.While there is broad agreement among

operators and industry specialiststhat the risk of migration of frackingfluids from the fracking site tounderground drinking supplies isextremely remote, it is expected thatthe EPA report will provide greaterclarity on this and will also assess therisks to drinking water from currentdrilling and well casing procedures.

In addition to technical research intohydraulic fracturing, the Secretaryof Energy sought to provide broader

industry guidance by convening asubcommittee of his Advisory Board todevelop a report on the immediate stepsthat can be taken to improve the safetyand environmental performance of shalegas development. The SEAB shale gasreport was requested and completed in2011, and identified four major areas ofconcern that should be addressed:

Possible pollution of drinking water

from methane and chemicals used infracturing fluids.

Air pollution.

Community disruption during shale

gas production.

Cumulative adverse impacts that

intensive shale production can haveon communities and ecosystems.

To address these concerns, the SEABoffered twenty recommendationsto support safety, environment anddevelopment objectives. These broadrecommendations, such as increasingcommunication between stateregulators, included specific actions,such as providing funding to theState Review of Oil and Natural GasEnvironmental Regulations (STRONGER)organization to review and comparestate shale gas regulations. Therecommendations can be summarized asfocusing on the following key areas:

Maintaining water quality through

focus on groundwater protection andwastewater disposal.

Managing water supply through

reducing water intensity, developingbetter baseline data and focusing on alife-cycle, systems approach to watermanagement.

Standardizing fracturing fluid

disclosure as the benefit oftransparency outweighs IntellectualProperty (IP) protection.

Reducing use of diesel, both as a

fracking fluid and as an energy sourcefor power and transport.

Developing a cumulative, holistic

approach to managing impact oncommunities and ecologies.

Supporting these recommendationsby promoting regulatory comparison,and sharing and incentivizing leadingpractice.

Improving air quality through data

collection, life-cycle analysis andfocus on fugitive emissions.


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2.3Key trendsIn its final report, the SEAB assessedthe level to which its recommendationshave currently been implemented

and concluded there was limitedimplementation at this time. Giventhe dissatisfaction of operators withthe current regulatory complexity,47the desire of the federal governmentto implement its recommendationsfor responsible development, andthe desire of other stakeholdersfor increased transparency, thereis likely to be significant evolutionof shale gas regulation. Based onthese pressures, we expect a number

of key trends in regulation.

DisclosureMany states (including Wyoming,Arkansas and Texas) have alreadyimplemented regulations requiringdisclosure of the materials used infracking fluids and the US Departmentof Interior has indicated an interest inrequiring similar disclosure for sites onfederal lands. As operators are requiredto disclose the materials and volumes

used in certain states, the argumentof IP protection in other states quicklyerodes. The FracFocus website, jointlyoperated by the Department of Energyand the Ground Water ProtectionCouncil, is a voluntary registry forcompanies to report chemicals. In thefuture, FracFocus may become the basisfor a more rigorous reporting system.

Cumulative approachAs the development of each shale gasbasin continues, there is increasedawareness that the cumulativeimpact of individually low-impactoperations risks creating negativeenvironmental consequences. Theadjustment of regulations to be

more focused on cumulative inputsand outputs at the basin level willrequire enhancements to regulatoryprocedures and data availability.

Water trackingUnderstanding the impact of operationson the water table involves both acumulative and also an end-to-endapproach to water management.Tracking of water use, from the initialsourcing to disposal, is expected

to become an increasingly rigorousrequirement to allow regulators toassess the holistic impact of operations.

Focus on intensityCumulative regulatory impactassessments will encourage operatorsto reduce the intensity of shale gasproduction across their new andexisting operations, including water,energy and emissions intensity. As

the industry matures and operationsbecome increasingly optimized,operators and regulators will focuson intensity as a way of reducingcosts, allowing greater output forthe same input costs , environmentalfootprint and disruption to localcommunities. Particular areas of focuswill include recycling of wastewaterfor fracking and supporting use ofefficient technologies. Innovation inoperations and analytics will be criticalto assessing efficiency performance.

Pressure on watertreatmentEven if the current EPA study confirmsthat fracking itself does not pose a riskto drinking water, increased regulatorypressure will be placed both on wellcompletions and treatment or disposalof wastewater. This will encouragemore rigorous regulations on operatorsmanagement of wastewater.

Growing standardizationAs the industry matures and disclosureincreases, there will be increasingstandardization in terms of operationalexcellence and leading practice.This standardization combined withincreased pressure for coordinationand comparison in regulations will

lead to more consistency in regulationbetween regions, which will reducecomplexity of compliance, in contrastto the other trends in regulations, whichare likely to increase complexity.


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In Focus

Water regulation in Argentina, China, Polandand South Africa

Water regulation related to shale

gas in Argentina, China, Poland andSouth Africa is in its early stagesas governments start to pursue thedevelopment of their shale resources.

Argentina regulationOnshore oil and gas resources inArgentina are governed by provincialgovernments in their own territory,based on the Federal HydrocarbonLaw.48Therefore, exploration permitsare granted by provincial states.Operators are also regulated byenvironmental regulations issued bythe Federal Secretary of Energy andmore stringent rules at the provinciallevel. For oil and gas operations,Environmental Impact Studies arerequired by Resolution 105/92 andResolution 340/93 requires AnnualEnvironmental Audit Studies to beprepared by consulting firms registeredwith the Secretary of Energy.49

Water is primarily regulated bythe provincial government. In theNeuqun province, the General WaterResource Office (DGRH) is responsiblefor applying the water code in theprovince. Considering the amountof water consumed by the shale gasindustry, conflicts in water demandwith other users could occur. Withinthe province, a user community hasbeen created to resolve water demandconflicts, which has been regarded

as good practice. Due to a lack of anational water law, inter-provincialwater conflicts are more difficultto resolve and a River Basin WaterManagement model has been used byNeuqun and neighboring provinces.50The AIC River Basin Authority wasintroduced in 1985 to act as the watermanagement authority for Rio Negro,Neuqun and Limay River Basin.

Managing water quality is also within

the scope of provincial water laws.There is growing demand in Argentinafor more stringent wastewater dischargeregulations to improve widespreadsurface water pollution. However,with the complexity of varyingenvironmental/water regulations indifferent provinces, progress is relativelyslow. Researchers in Argentina alsoraised concerns over chemicals used inthe fracking process;51 and disclosureof details in fracking fluid is not

mandatory in the country.

China regulationDue to the early stage of shale gasdevelopment, current environmentalregulations in China remain focusedon the conventional oil and gasindustry. In March 2012, the Ministryof Environmental Protection (MEP)issued the report, Technical Guidelinesfor Oil and Gas Industry PollutionPrevention.52 This document stressed

the importance of wastewater recyclingand gave guidance on fracking fluidsused in the oil and gas industry. Thisdocument also requires the creation ofunderground water monitoring schemesto confirm current industrial practices inunderground injection do not cause anywater pollution. However, this documentdoes not specifically cover shale gasand related unique water challenges.Revision of this document will not occuruntil late 2013.

In addition, the Technical Guidelinesfor Environmental Impact AssessmentConstructional Project of Petroleum andNatural Gas Development on Land,53issued by the MEP in 2007, sets clearstandards for wastewater dischargeand stated leading practices to preventpollution caused by wastewater in theoil and gas industry.

Although there are no specific

environmental regulations on shale gas,the NDRC shale gas development plan(20112015) does cover environmentalissues.54The plan states a series ofleading practices, which includesfracking water recycling, strict ruleson drilling activities and an enhancedmonitoring scheme for wastewaterdischarge, for shale gas operators toreduce negative impacts on the localenvironment. These areas could be thefocus for future shale gas industry-

specific regulations.

Poland regulationIn Poland, government bodies regulatingshale gas development include theMinistry of Environment, StateMining Authority and National WaterManagement Authority. In general,Poland lacks specific legal regulationsthat would apply directly to operationsin the field of shale gas. Therefore, anybusiness activity in this area is currently

regulated by the same legislation forconventional natural gas, the Act of 4February 1994 Geological and MiningLaw.55 56 57The Ministry of Environmentgrants authorizations for shale gasexploration activities with the supportfrom the Department of Geologyand Geological Concessions (DGGC);further approval from the State MiningAuthority is required for commencementof any mining activity.

Based on the current Water Act(July 2001), a separate water permitis required for utilizing surface andgroundwater with a capacity over5m3per day and for projects suchas drainage facilities and mines.Applications have to be made to theNational Water Management Authority.Water permits granted also coverthe discharge of wastewater.58TheEuropean Union regulation 2006/1907/EC concerning the Registration,Evaluation, Authorization and

Restriction of Chemicals (REACH),


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establishing a European ChemicalsAgency, is applicable to the use ofchemicals in the hydraulic fracturingprocess.59In contrast to a voluntarydisclosure system in the UnitedStates, additives used in hydraulicfracturing are public informationin Poland and have to be approvedby the State Mining Authority.60

A recent environmental impactassessment report on horizontal drillingand fracking for the first Polish wellshowed minimum environmental impact.The report coordinated by the PolishGeological Institute concluded thathydraulic fracturing did not generateair pollution, only caused temporaryelevated noise within permissible levels,had no effect on the quality of surfaceand groundwater, and did not causeearthquakes. Such positive resultscould influence future environmentallegislations in Poland.

South Africa regulationShale gas exploration and productionis regulated by the Mineral andPetroleum Resources DevelopmentAct (MPRDA) in South Africa. ThePetroleum Agency is responsible forissuing exploration permits.61 62Basedon the current system, a Technical

Cooperation Permit (TCP) is issuedto allow initial paper-based researchand acquisition of seismic datafrom other sources, including thePetroleum Agency. A ReconnaissancePermit is issued to allow operationsto search for mineral or petroleumby geological survey with remotesensing technologies, but not physicalexploration. An Exploration Right hasto be obtained for physical explorationactivities and a separate ProductionRight is required for subsequentproduction activities. However,MPRDA is currently under reviewwith the intention of streamlining thelicensing process to avoid delays.

The National Water Act requiresindustry water users to register with theDepartment of Water Affairs (DWA) and

obtain a permit. Wastewater dischargeis also regulated by the DWA. Therefore,shale gas developers will need to obtainpermits from the DWA for sourcingand discharging water. In practice, noshale gas operators have successfullyreached the stage of applying for waterpermits, although Shell attemptedto obtain Exploration Rights. Public

concerns about the environmentalimpact of fracking led the DMR to issuea moratorium between April 2011 andSeptember 2012, which temporarilysuspended all applications for shalegas exploration. So far, there are nophysical exploration activities in SouthAfrica and more specific regulations onshale gas water sourcing and dischargemay be introduced in the future beforeoperations begin.

The following table highlights the mostrelevant water regulation trends in thevarious markets given the nature ofthe shale development and the localregulatory context.

Figure 10. Relevance of water regulation trends to focus markets.

Argentina China Poland South Africa Comments

Disclosure

Disclosure of chemicals used in Poland already

mandatory.

Although currently not obligated, operators in South

Africa are committed to voluntarily disclose the

chemicals used in fracking. In the future, we also

expect China and Argentina to also require some

level of disclosure.

Cumulative

approach

All four countries are developing plans to look at the

environmental impact of overall shale development.

Water tracking

Some form of water monitoring and tracking is

expected in all the focus markets.

Focus on intensity

Public concerns around the environment in all of

these geographies are high. There is a wider trend to

reduce water, energy and emissions.

Pressure on water

treatment

This is an area of emphasis in all shale plans.

Growing

standardization

Regulations are at early stages and each country

is assessing the local environmental impact and

developing its own view. Regulations are likely

to be consistent at each national level, but with

significant potential variation by nation.


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3.1Water use andproductionWater plays a key role in each stage of

the shale gas well life cycle, from welldevelopment to production (seeFigure 11).63The key challenges foroperators are:

Sourcing sufficient volumes of water

required for drilling and fracking eachwell.

Effectively managing the volumes of

wastewater generated.

Sourcing sufficient

volumes of waterWater used in hydraulic fracturing issourced from surface waters (lakes andrivers), groundwater (wells, aquifers),municipal supplies, and from wastewaterfrom previous fracking processes. Oncecollected, the water is hauled or pipedto the site where it is stored in linedimpoundments or tanks until it is usedin the drilling and fracking stages.

The volumes of water required in shalegas production vary considerably fromwell to well. The FracFocus website,which details the water use of wellsacross the United States, shows thevariety of volumes required acrossdifferent wells. Factors influencingthis total volume will include:

The depth, length and number ofhorizontal segments fracked: Thelonger the segment, the more wateris required for the fracking process.64There is a trend for longer horizontalsegments: two years ago, these wouldbe approximately 3,000 feet longwith advances in technology, thesecan now cover up to 6,000 feet.65

The geological characteristics of the

shale play: shale plays differ widely intheir geological characteristics (depth,

thickness, total porosity) resultingin different water requirements. TheHaynesville Shale (3,200 to 4,110min depth), for example, requires onaverage one million gallons of waterduring the drilling phase comparedto 60,000 gallons for the FayettevilleShale (300 to 2,100m in depth).66

As an average, approximately fivemillion gallons of water are requiredto drill and frack a well, the equivalentof 1,000 water truck movements.The fracking stage is the most waterintensive, using up to 90 percent of thetotal water use, as illustrated in Figure12. In contrast, only a small amountis necessary for the maintenance of

the equipment (flushing and cleaning)following the fracking.

Despite public perceptions to thecontrary, these water requirementsare low when compared to othersectors (agricultural, industrial), andwhen set against the water intensityof other forms of energy. The 2009Modern Shale Gas Development inthe United States: A Primer reportsthat total volumes required for shalegas production in a shale basin rangefrom 0.1 percent to 0.8 percent of totalwater use.67Pennsylvanias annual totalwater consumption is approximately 3.6trillion gallons, of which the shale gasindustry withdraws about 0.19 percentfor hydraulic fracturing.68

Nevertheless, access to water sourcesis likely to become more of a constraintfor operators in arid regions facinggrowing depletion of water resources,and in areas where water flows and

Typicaltimelines

Civil/site prepBuild accessroads, constructand install wellpads, prepare sitefor drilling

DrillingDrill vertical andhorizontal wells

Completion/frackingComplete wells withsteel and cementcasings

Release gas throughhydro-fracking

FlowbackCapture, storeand treatreturned frackingfluids

ProductionCapture, storeand transport gas

Decommission

60 days 15-60 days 15-30 days 20 days 540 years

watermanagement

challenges

Access to water fromsurface, groundwateror municipal watersources

Volumes and qualityof water required forthe drilling fluid(up to 99% of thefluid depending onthe operator/shale)

Volumes and qualityof water required forthe fracking fluid

Managing thevolumes of flowbackwater returned to thesurface in the firstfew days followingthe fracking

Managing thevolumes of producedwater returned to thesurface followingproduction

Figure 11. Water management challenges across the shale gas lifecycle.


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availability follow seasonal variations.In Pennsylvania, for instance, accessto permits for water can be more of achallenge in the summer when minimumflow rates need to be maintained.69In July 2012, the Susquehanna RiverBasin Commission (SRBC) suspendedwater withdrawals due to lower streamflow levels in the Susquehanna Basin,

including a majority of shale gasoperators including Chesapeake andTalisman.70In dry regions of Texas,water demands for shale gas productionare viewed as competing with water usefor irrigation and domestic use.

The volumes of water required at sourcedepend on a number of factors. Thesevolumes can be reduced, for instance,by optimizing the well configurationand the number of wells per padandby modifying the constitution of thefracturing fluid. The composition offracturing fluids has changed over theyears, and continues to see changes.Gel-based fluids were largely useduntil the emergence of slickwaterfracturingusing a low-viscosity mixof water and friction reducersin the1990s.71Slickwater fracturing, whichrequires higher volumes of water, withfewer requirements on the water quality,is now widely used.72

Figure 13 shows one example of thecomposition that may be encountered inshale gas fracturing, with 99.51 percentof water and sand (proppants),73and theremainder consisting of chemicals. Thesechemicals fulfill varying purposes, fromincreasing the fluid viscosity to help theproppant transport (gelling agents), tolimiting bacteria growth (biocides), the

build-up of scale (scale inhibitors), theviscosity of the fluid (surfactant), or thefriction between the fluid and the well(friction reducers).74

The water quality requirements for thewater used in the drilling fluid are higherthan for the fracturing fluid due to therisk of damage to the drilling equipment(this higher quality requirement hasimplications for water reuse, seeSection 3.2).

An emerging trend in the compositionof the fracturing fluid is to use less andcleaner additives. These green fracksinclude the use of guars and starch-based chemicals that are biodegradableand non-bio-accumulating. Throughits Green Frac program, Chesapeakeclaims to have eliminated 25 percentof the additives used in hydraulicfracturing fluids in most of [their]shale plays.75

Still in initial stages of development,waterless fracturing fluids (includingliquid propane, liquid CO2, nitrogen gasfoams and gels), are being explored.These fluids, however, present their ownchallenges. The use of liquid propane,for instance, presents safety risks linkedto using an explosive gas underground.

Drilling

Fracking

TotalWateruseperwell(000g

al)

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

0

Barnett Fayetteville Haynesville Marcellus

Figure 12. Water use in drilling and fracking across four US shales.


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Managing the volumes ofwastewater generatedFollowing the fracking, varying volumesof the injected fracture fluid willflow back to the surface (flowbackwater), mixed with formation watercontaining dissolved minerals fromthe formation. Although there is noformally agreed definition, flowback andproduced water are jointly referred toas wastewater.76 The water recoveryrate, that is, the amount of wastewaterrecovered from the volume injected aspart of the fracking process, both inthe short term (flowback water) and inthe long term (total produced),77 78 79varies by well and by shale. There aredry shales with lower water recoveryrates (15 25 percent of the injectedwater returning to the surface), such

as the Marcellus, and wet shaleswith high water recovery rates (up to75 percent), such as the Barnett.80The flowback water constitutesthe highest volumes of wastewaterover the life cycle of a wellit canrepresent a million gallons of wateror more over the course of weeks,81with the majority captured in the firstseveral hours to several weeks.82

The challenges of managing these highinitial volumes of water differ fromconventional oil and gas productionwhere the produced water graduallyincreases over the life cycle of thewelland therefore the solutionsinvolved will be different (see sidebaron Managing produced water:unconventional vs. conventional).

The flowback water contains a numberof constituents, depending on thefracturing fluid and the shale formation.These include the additives from thedrilling fluids (e.g, biocides, scalinginhibitors, friction reducers), in additionto salts, metals, organic compoundspresent in the formation, such aschemicals causing scaling and hardness(e.g., calcium, magnesium, sulphatesand barium), and Naturally OccurringRadioactive Materials (NORM). NORMis brought to the surface in the drillcuttings, in solution in the producedwater, or in scales or sludges.83Thelevels found in wastewaters aresignificantly lower than the safelimits of exposure; however, theseshould be monitored carefully in caseconcentrations increase during wastetreatment.84At concentrations higherthan regulatory limits, the material mustbe disposed of at licensed facilities.

A further characteristic of this producedwater is its salinity, measured in levelsof Total Dissolved Solids (TDS).85These levels vary between the shales,depending on the rock strata and thegeologic basin, from brackish to salineto brine.86Managing these levels of TDShas wider implications for water reuseand recycling.87

Following this high initial flow, thelevels of wastewater generatedgradually decrease as productionbegins. Following field development,the returned water is produced insmall quantities by a multitude ofdifferent wells over longer periods oftime. The logistics challenges involvedin managing these small volumes ofwater produced by multiple sourcesover longer periods of time will bedifferent to those presented during fielddevelopmentand the opportunities toreuse the wastewater are also different.

Water and Sand99.51% Other 0.49%

Surfactant

0.085%

KCI

0.06%

Gelling

Agent

0.056%Scale

Inhibitor

0.043%pH Adjusting

Agent

0.011%

Breaker0.01%

Crosslinker

0.007%

Iron Control

0.004%

Corrosion

Inhibitor

0.002%

Biocide

0.001%Acid

0.123%

Friction

Reducer

0.088%

Figure 13. One example of composition of a fracturing fluid.

Source: Primer, 2009.


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Figure 14: Comparison of characteristics of produced water in conventional and unconventional.

The key difference between shale andconventional gas production is thatshale plays have limited permeability,which limits hydrocarbon flow tothe wellbore. To release the gascontained within the shale, effectivepermeability is created artificiallythrough hydraulic fracturing, a processby which a fracturing f luid is pumped

into the reservoir to cause fractures.This process has implications for themanagement of produced water in shalegas productionwhich differs fromconventional oil and gas, as shown inthe table below.

This comparison explains some of thekey differences in water managementoptions available to shale gas operatorswhen compared to conventional oiland gas:

In shale gas production, the

large volumes of flowback waterproduced in the initial stages needto be managed from the start of theproduction.

The water quality of produced water

from shale gas is often characterizedby high TDS levels. This poseschallenges in terms of water reuse infurther operations and treatment tocreate freshwater.

Comparison

Managing produced water: unconventional vs.conventional

Conventional oil and gas Shale gas

Volumes of produced water Very low volume initially

The water-to-oil/gas ratio increases overthe life of a conventional oil or gas well,until a stage where water forms up amajority of the volumes brought to thesurface88

Very high initial volume of flowbackwater (up to one million gallons over thecourse of a few weeks)89

This high volume rapidly drops of f to asmall residue amount of produced water(~50 barrels/day)90

Characteristics of produced water Mainly natural water naturally present inthe formation

Additional water may be from enhancedwater recovery or water flooding

The returned water is mainly waterinjected during the fracking process(flowback water)

The returned water is characterized by itssalinity (levels of Total Dissolved Solids)


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3.2Water managementoptionsThere are a number of options available

to operators to manage these waterrequirements and the producedwastewater. Factors consideredwhen evaluating different watermanagement options will include costs,the shales particular characteristics,the life cycle stage of the well (e.g.,pre- or post-development), the localinfrastructure, the local regulatoryframework, the availability of localwater sources, and public perceptionof water risks in the area (e.g.,aquifer pollution, earthquakes).

Underground injectionThis method of disposal of producedwater is normal practice in conventionaloil and gas production. Operators caninject their wastewater in undergroundinjection wells, or Class II Wells,91or pay a third-party commercialdisposal company to take their waterand inject it into a disposal well. Inthe United States, either type of well

must be permitted by a state agencyor the EPA through the UndergroundInjection Control (UIC) program. Theseunderground formations are situated inporous rock formations, thousands offeet underground.92

As the cheapest disposal option forflowback and produced water, and withapproximately 200,000 undergroundwells in the United States, disposal inunderground injection wells is one ofthe most widely used, and most cost-effective, wastewater managementoptions. Produced water is either hauledto these underground disposal sites, or

piped (thus reducing traffic and haulingcosts).93The availability of injectionwells in the Barnett, Haynesville andFayetteville Shale

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116805823 Water and Shale Gas Development

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