association of oil & gas producers - ngs facts - hydraulic …€¦ · · 2013-06-14regulated...

International

Association

of Oil & Gas

P r o d u c e r s

Updated June 2013

We are Working for safe, sUstainable exploration & development in eUrope

Successful exploration of gas from shale could potentially provide Europe with an additional source of secure and competitive energy that could make an immediate and positive impact on reaching the EU’s ambitious CO2 reduction targets. OGP members are committed to work for its safe, responsible development in Europe.

What is gas from shale?

It is natural gas that can only be economically extracted from sedimentary shale rock through the combined use of horizontal drilling and hydraulic fracturing. It shares many of the advantages of natural gas that has been produced safely in Europe for many years.

gas from shale…

• Is an affordable, efficient energy source.

• Has a smaller environmental footprint with lower GHG emissions and a lower surface footprint than other conventional energy.

• Reduces CO2 emissions. Between 2007 and 2012 the US cut CO2 emissions by 450 million tons thanks to the shift from coal to gas in power generation.

• Is abundant. IEA estimates show that reserves of natural gas extracted from unconventional sources, like gas from shale, coal bed methane and tight gas almost double recoverable gas resources (using current technology and economic models).

• Has potential for economic benefits such as increased employment, tax revenues and royalties.

• Contributes to supply diversity and security for Europe by increasing domestic supplies.

responsible development

OGP acknowledges the importance of industry and authorities cooperating and establishing a dialogue to address public concerns through the open sharing of information and knowledge. Industry experience has demonstrated that early dialogue with local communities is the most important element of maintaining the trust necessary for successful development.

As part of our efforts to build trust OGP has developed a Transparency Initiative for European drilling projects. It has created a public hydraulic fracturing disclosure website where members of the public can search for nearby well sites that have been hydraulically fractured to see what chemicals were used to fracture natural gas resources on a well-by-well basis.

existing regUlation redUces risk

European legislators have ensured that the exploration and production of natural gas in Europe is one of the most highly regulated processes in the world. In fact, gas from shale development is regulated by 14 different pieces of EU legislation, as well as a strong existing regulatory regime at national and local level. OGP and its members work within the effective implementation of existing regulations and recognise that this is an important factor in reducing risk for all gas operations.

You can find answers to the most frequently asked questions on hydraulic fracturing at www.ogp.org.uk/fracturingIt is an online source of easy-to-understand answers to questions covering hydraulic fracturing and:

CHEMICALS

WATER

SEISMICITY

GREENHOUSE GASES

…SH

ALE GAS

OPERATI

ONS

– F.A.Q.s o

n wate

r

What ha

ppens t

o the h

ydraul

ic frac

turing

fluid i

njecte

d into t

he gro

und? ..

. Contin

ued

Extra

polat

ing th

e dista

nce o

f the v

ertica

l frac

tures

for a

typic

al Eu

ropea

n sha

le ga

s well

wou

ld lea

ve a

distan

ce of

1 to

3 ki

lometr

es be

twee

n the

fractu

re an

d the

wate

r sou

rce, s

epara

ted by

mult

iple l

ayers

of im

perm

eable

rock

strat

a whic

h prev

ent a

ny w

ater, g

as or

chem

icals

from re

achin

g it.

Figure

9 p

rovide

s a sc

ale ill

ustrat

ion of

this.

In a

dditio

n, as

the w

ell b

ore p

enetr

ates t

he w

ater s

ource

near

the su

rface

, any

prod

uced

wate

r or h

ydroc

arbon

s are

sepa

rated

from

the

water s

ource

by

multipl

e lay

ers o

f impe

rmea

ble ce

ment a

nd st

eel c

asing

, whic

h is t

ested

to en

sure w

ell in

tegrity

prio

r

to co

mmencin

g an

y hyd

raulic

fractu

ring.

This

is als

o sho

wn at th

e top

of Fi

gure

9.

This

type

of well

des

ign a

nd c

onstru

ction

proh

ibits

hydro

carbo

ns fro

m ente

ring

the w

ater s

ource

and

local

well w

ater.

Hyd

raulic

frac

turing

has b

een u

sed

in ov

er 2

million w

ells w

orld-w

ide si

nce

the 1

940’s

7 and

compre

hensi

ve re

ports

have

foun

d no

histo

rical

case

s in w

hich h

ydrau

lic fra

cturin

g

has

conta

minated

dri

nking

wate

r.8

The

UK D

epart

ment o

f Ene

rgy a

nd

Climate

Cha

nge

(DEC

C) has

rece

ntly

(early

201

2) co

nclud

ed th

at ‘In

the

light

of the

robu

st co

ntrols

in p

lace..

.

to pro

tect th

e en

viron

ment a

nd e

nsure

safe

opera

tion,

DECC s

ee n

o ne

ed

for an

y mora

torium

on sha

le ga

s’

deve

lopmen

t. ‘Th

is is

also

the vi

ew o

f

the (U

K) En

ergy a

nd C

limate

Cha

nge

Selec

t [pa

rliamen

tary]

Committe

e

which

held

an in

quiry

into

shale

gas

earlie

r thi

s ye

ar an

d too

k ev

idenc

e

from

Govern

ment,

regula

tors,

the

British

Geo

logica

l Su

rvey,

the

oil

and

gas

indust

ry an

d en

viron

mental

group

s. Th

e com

mittee a

lso co

nclud

ed

that h

ydrau

lic fra

cturin

g doe

s not

pose

a dir

ect r

isk to

wate

r wate

r sou

rces,

provid

ed th

at the

well

-casin

g is

intac

t.

Any r

isks t

hat d

o ari

se a

re more

likely

to be

relat

ed to

the

integ

rity o

f the

well, a

nd a

re no

diffe

rent t

o iss

ues

enco

unter

ed

when

explo

ring

for

and

produ

cing

hydro

carbo

ns fro

m

conv

entio

nal g

eolog

ical fo

rmati

ons.’

9

FIGURE

9: WELL

CONSTR

UCTION AN

D DISTAN

CES EX

AMPLE

…SHALE GAS OPERATIONS

– F.A.Q.s on greenhouse gases

• Combustion. Over

three quarters

of the life

-cycle e

missions o

f natura

l gas are gene

rated during the

combustion phase

2 . There

are no additional em

issions in

the combustio

n of shale g

as compared

to those o

f natura

l gas from other

types o

f reservo

irs.

A study ca

rried out by Pr

of William Griffit

h et al. of Carneg

ie Mello

n Unive

rsity conclu

des that the

life-

cycle fo

otprint of sha

le gas fro

m the Marcel

lus formation is

only 3% hig

her than th

e average domestic

gas in the

United States

3 . In Decem

ber 2011,

the U.S. N

ational Energy Te

chnology La

bs estimated

that “shale g

as life cyc

le emissio

ns are 6

% lower than co

nventio

nal natura

l gas.”

When gas is used to generate electrici

ty

The life-cycle ghg footprint of shale gas is:

Mean life-cycle GHG footprint of U.S. Natural gas (g CO2e/MJ)*

Less than 1/3 of

lignite-fired coal power

Less than 1/2 of

hard coal

*OGP elaborationof data from Venkash et al., Uncertainty in life cycle greenhouse gas emissions from

United States natural gas end-users and its effects o

n policy, 2011

3/4 of natural

gas life-cycle emissions

are generated here

Extraction

GHG emissions for shale gas

are marginally higher due to

more energy- intensive

equipment & higher water use

Processing

Processing shale gas is no more

emission intensive than gas

from other formations

Transportation

There is no difference between

the emissions of transportation

of gas from different reservoirs

Combustion

There are no additional

emissions during combustion of

shale gas compared to other

types of natural gas

3Is the GHG footprint of shale gas less th

an other energy sources, and can

it be further reduced?

A: Yes. T

he life-cyc

le GHG footprint

of shale g

as is less

than ha

lf that of ha

rd coal and less th

an a

third of lig

nite-fire

d coal power, and em

issions fr

om the life

-cycle o

f shale g

as can be fu

rther reduce

d.

Industry takes

a pro-active approach t

o limit em

issions a

nd employs i

ts expertis

e and ca

pability to

do so. It h

as already reduce

d the em

issions o

f methane (

CH4) and carbon dioxide (C

O 2) fro

m shale

gas production, a

nd will continu

e improvem

ents durin

g the drillin

g and production phases

by utilisin

g

additional equipment and practice

s to preve

nt or ca

pture CH 4

emissio

ns for sa

le on th

e market,

for use o

n site fo

r enhance

d recovery, or as a fue

l source

. Implem

entation o

f rigorous p

reventative

maintenance

programs also help reduce

emissio

ns.

FIGURE 2: SHALE GAS GHG FOOTPRINT IS COMPARABLE TO GAS FROM OTHER RESERVOIRS

…SHALE GAS OPERATIONS

– F.A.Q.s on chemicals

Are you prepared to disclose chemicals in fracturing fluids per well?

A: OGP supports the public disclosure of the additives used in hydraulic fracturing on-line and many of

our members active in shale gas exploration in Europe already disclose information on their company

websites. In addition, our suppliers are aware of the importance of public disclosure of additives and are

in dialogue with our members about the best way to do this for European audiences.

Oil and gas producers are working to further reduce the environmental impact of fracturing fluids and our

suppliers see commercial advantage in providing fracturing fluids with better environmental profiles. OGP

members are carrying out scientific benchmarking studies aimed at further improving the fracturing process

and reducing the environmental footprint.

8

9

Our members and their suppliers comply

with laws and regulations such as the

Registration, Evaluation, Authorisation

and Restriction of Chemicals (REACH)

Regulation. REACH is a comprehensive

system that ensures additives meeting

the one metric tonne threshold and other

requirements must be registered and

authorised for use by ECHA (European

Chemicals Agency). Authorisation is

based on whether or not usage can be

adequately controlled in a safe manner.

OGP Members:

At present: Additive suppliers:

support disclosure & many already

provide details on their websites

are currently carrying out

benchmarking studies

see commercial benefit from improving

environmental profiles

comply with REACH

Companies

need to protect their

intellectual property to

remain competitive & benefit

from their investment, which

drives further innovation &

investmentOGP supports

disclosure as per eu

regulations & REACH.

Suppliers understand the

importance of such

disclosure

What is your position with regard to “intellectual property”?

A: OGP supports the public disclosure of additives used in fracturing operations consistent with the

European regulatory structure and REACH processes. Our suppliers are already aware of the importance

of public disclosure of additives and are in dialogue with our members about the best way to do this for

European audiences. However, OGP recognises that Intellectual property rights

are critical for businesses – these rights enable business

to benefit from their investments and remain competitive in

the global marketplace. Any disclosure process needs to

include protection for the intellectual property represented

in some chemical makeups and concentrations in the

hydraulic fracturing fluid. We believe FracFocus.org in the

United States has managed to provide unprecedented

amounts of information on hydraulic fracturing fluids,

including even non-hazardous constituents, while

protecting vital intellectual property that allows for

continued innovation and, hence, improvement.

Further, the Harmonised Mandatory Control System for the

Use and Reduction of the Discharge of Offshore Chemicals

used in the North Sea and North East Atlantic Areas (OSPAR)

requires proprietary chemical compositions to be directly

disclosed to the Competent Authority by the supplier.

FIGURE 3: OGP MEMBERS & SUPPLIERS ARE TALKING ABOUT THE

BEST WAY TO DISCLOSE ADDITIVE USE IN EUROPE

FIGURE 4: STRIKING A BALANCE ON DISCLOSURE

…SHALE GAS OPERATIONS– F.A.Q.s on seismicity

5

6

What happened in the Blackpool area of the UK in 2011?A: In the UK, hydraulic fracturing was suspended at Cuadrilla Resources’ Preese Hall exploratory site

after a magnitude 1.5 event on 27 May 2011 in the Blackpool area and in light of a preceding

magnitude 2.3 event on 1 April 20118.At that time the British Geological Survey (2011) commented: “We understand that fluid injection,

between depths of two to three kilometres, was ongoing at the Preese Hall site shortly before both

earthquakes occurred. The timing of the two events in conjunction with the fluid injection suggests they

may be related. It is well-established that fluid injection can induce small earthquakes. Typically, these

are too small to be felt.”In a recent report of the UK Department of Energy and Climate Change (DECC) recognises the risk

of induced seismicity, but below 3 on the Richter scale, and that such events are “unlikely to cause

structural damage” and “see no reason why Cuadrilla Resources Ltd. should not be allowed to

proceed with their shale gas exploration activities and recommend cautious continuation of hydraulic

fracture operations, at the Preese Hall site9.”

What happened in the US (Texas, 2008/9; Ohio, 2011...)? A: A number of the small-to-moderate earthquakes that occurred in the US in 2011 have been

associated with the disposal of wastewater, and not directly related to natural gas production. It

should be emphasised that: • They are not triggered by hydraulic fracturing itself but possibly by waste water injection;

• No earthquake triggered by fluid injection has ever caused injuries or significant damage;

• More than 144,000 wastewater disposal wells have been operating safely in the US for many

decades; and• When properly planned, operated, and monitored, fluid disposal wells are safe, as demonstrated

by decades of disposal operations involving many industries10. How can hydraulic fracturing be undertaken in areas prone to seismicity?A: Clearly tectonic areas, with active faults, are more prone to seismic events. These areas, however,

are well known, and sound pre-planning and surveying prior to operating in these areas can mitigate

the risk.

Geological risk assessments should be conducted prior to drilling fluid disposal wells Faults with large, pre-existing stress in brittle rock formations should be avoided

Proper limits on flow rate should be set

Very small to moderate sized seismic events can be induced in the earth when large volumes of water or other fluids are disposed of in the vicinity of faults that have pre-existing stress, such that they are on the verge of moving (“failure”). The injected fluids can affect the stress state or reduce friction on the plane of the fault, causing it to fail. When properly planned, operated, and monitored, with contingency plans in place, these operations are safe. It is important for

7

all disposal operations to avoid faults with large, pre-existing stress in brittle rock formations and to set

proper limits on the flow rate of water into the formation. These conditions can generally be met by

conducting geologic risk assessments prior to drilling wells for fluid disposal.

FIGURE 3: SIUND PRE-PLANNING & SURVEYING CAN MITIGATE RISK IN AREAS PRONE TO SEISMICITY

http://ogp.org.uk/fracturing

…Shale gaS operationS Frequently asked questions about water

This document provides factual information about shale gas operations and water

How much water do you use to drill a well and to hydraulically fracture it? A: To drill a typical, relatively deep horizontal shale gas well in Europe and complete a multi-stage hydraulic fracturing operation will use an estimated 10,000 to 20,000 cubic metres (m3) of water over the two/three month set-up, drilling and completion process. This equates to the annual water use of between four and seven people (average freshwater annual resources per inhabitant in France, Italy, the United Kingdom, Spain, Germany and Poland is below 3 000 m³)2.

The total usage includes 2,500 – 5,000 m3 to drill the well and 7,500 – 15,000 m3 to perform a multi-stage (5-15 stages) hydraulic fracturing process. The variance depends primarily on subsurface geology and the number of hydraulic fracturing stages.

Do you sample groundwater when drilling and hydraulic fracturing a well?A: It is best practice to sample groundwater in a pre-determined vicinity of a new well site both before and after drilling or hydraulically fracturing of well and periodically during the production phase.

Depending on applicable regulations, local conditions and operator’s policies, the testing may include water wells and surface water such as rivers, ponds or lakes in the immediate vicinity of the planned well. Understanding the quality of water is an important component of water source management. For example, The Polish Geological Institute tested 17 water wells and one creek in the vicinity of the Lebien LE-2H well before and after drilling and completion and found no evidence of any change in surface or ground water quality.1

WELL DRILLING 2,500-5,000m3

FRACTURING (5-15 STAGES)

7,500-15,000m3

ANNUAL WATER USE oF 4-7 pEopLE

10,000-20,000m3

1

2

FIGURE 1: GROUNDWATER IS TESTED BEFORE & AFTER DRILLING AND COMPLETION

Testing also occurs:After drilling & fracturing

Baseline tests measure:Levels of iron & solidsOrganic matterMethaneNORM

FIGURE 2: TYPICAL WATER USE FOR HYDRAULIC FRACTURING OPERATIONS IN EUROPE

FIGURE 1: GROUNDWATER IS TESTED BEFORE AND AFTER DRILLING AND COMPLETION



How much water is used to develop a typical shale gas deposit?A: According to the Massachusetts Institute of Technology, in the United States, where the development of gas from shale is prevalent, water used for drilling and hydraulic fracturing shale gas wells represents less than one percent of total water usage in the areas where major shale gas deposits are being developed.3

In Poland, the water used for the Lebien LE-2H well totalled approximately 18,000 m3 (to drill the well to a depth of 4,000 metres and perform 13 hydraulic fracture stages over a horizontal distance of 1,000 metres).1

Operations for a typical European shale gas basin in early production phase could require drilling about 100 hydraulically fractured wells per year (from multi-well drill pads with 10-20 wells per pad) which at 18,000 m3 per well (and assuming no recycling of produced water) would result in annual water use of less than 0.02% of annual industrial water use in Poland.4 Recycling of produced water reduces the amount of water needed. In the Marcellus Basin in Pennsylvania recycling of produced water is approaching 100% to reflect local conditions, while in other basins the use of recycling is less prevalent than the Marcellus, but is generally increasing.

3

100 X 18000 m3 = less than 0.02% of annual freshwater industrial water use in Poland

FIGURE 3: EXAMPLES OF WATER USAGE IN SHALE GAS OPERATIONS

In the Marcellus Basin, in Pennsylvania, recycling of produced water is approaching 100%

In the US, water used for drilling & hydraulic

fracturing shale gas wells represents less than 1% of total water usage in the areas where the deposits

are being developed.



3000m

1.5km

MULPTIPLE HORIZONTAL WELLS FROM SINGLE PAD

Energy water intensity:

While several different metrics are typically used to try and quantify the comparative level of water used in shale production, the most widely used is energy water intensity. Energy water intensity is a comparison of the volume of water used in the production of a fuel per a standard amount of energy produced by that fuel (e.g. cubic meters of water per megawatt hour). There is consensus among shale gas researchers that the energy water intensity of shale gas production is relatively small compared to that of other types of fuels. This has been documented by the Groundwater Protection Council for the US Department of Energy and a comparison of energy water intensity for the production of various sources of energy is shown in Figure 5.5

LOW

MEDIUM

HIGH

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

0.450

Reducing the surface footprint:

Figure 4 shows an example of a multi-well, ‘pad’ type development, in this case utilising an eight well horizontal completion from a single well pad. This type of development minimises the surface footprint while efficiently producing the resource.

The hydraulic fracturing process normally lasts 3-5 days and takes place after a well is drilled, cased and cemented, and the drilling rig is removed.

FIGURE 4: MULTIPLE HORIZONTAL WELLS FROM SINGLE PAD

FIGURE 5: ENERGY WATER INTENSITY



Deep non-fresh water sources

The range of water sources might include:

Recycled fracturing water

Surface waterTreated waste water

Municipal water supplies

Wells connected to known water sources

Water is drawn over time & stored for use when larger amounts are required minimising impact on water availability for other uses.

Approved permits consider: Availability Competing uses Proximity Geologic formation characteristics

Where do you get the water required to drill a well and hydraulically fracture it?A: Before drilling a well, operators evaluate supply water. This process includes consideration of volume and water quality requirements, regulatory and physical availability, competing uses, proximity, means of transport and characteristics of the geologic formation to be fractured (including water quality required to fracture it). The source of water is based on these factors.

The range of water sources available can include: • water wells drilled to known freshwater water sources• surface water, such as rivers and lakes• municipal water supplies• treated waste water• deep non-fresh water water sources• recycled water from earlier fracturing operationsIn Poland most operators have utilised water that is drawn from shallow water wells near the drilling site and current regulations limit water extraction rates and reporting requirements are set out by the Government.

Water is drawn from the wells over time as set out in the permit and stored for use when larger amounts are required. This minimises any impact on the availability of water for other uses.

4

FIGURE 6: A WATER SUPPLY EVALUATION IS COMPLETED PRIOR TO DRILLING



What happens to the hydraulic fracturing fluid injected into the ground?A: The water injected deep underground for hydraulic fracturing either stays in the formation or is returned to the surface mixed with the natural gas resource during production. Depending on the nature of the geological formation, between 10 and 70% of the water used for hydraulic fracturing, known as flowback water, is recovered during the first two to five weeks of hydrocarbon production. Flowback water is collected in tanks and then disposed of according to government approved methods.

5Can hydraulic fracturing fluid affect our drinking water?

There has been no case of hydraulic fracturing operations contaminating drinking water resources.

European natural gas-bearing formations generally tend to be separated from underground water sources by 1-3 kilometres of rock. During the hydraulic fracturing process, water is injected into these deposits, along with proppant (sand) particles and additives. The composition of the hydraulic fracturing fluid varies depending on the preference of the operator and the properties of the shale target formation. The volume of the fluid is about 90% water, 9.5% proppant (sand) particles, and on average 0.5% additives.

The additives can serve a number of purposes, including:• friction reduction (as the fluid is

injected)• prevention of bacterial growth)• scale inhibition (to prevent mineral

precipitation)• corrosion inhibition• clay stabilisation (to prevent swelling

of expandable clay minerals)• supporting proppants• fracturing promotion

WHAT DO THE ADDITIVES DO?

reduces friction (as fluid is injected)prevent bacterial growth (biocides)inhibit scale (to prevent mineral precipitation)inhibit corrosionstabilise clay (to prevent swelling of expandable clay materials)support proppants (gelling agent)promote fracturing (surfactant)clean (well bore & formation)

0.5%additives

90%water

9.5%proppant (sand)

particles

• cleansing (for the well bore and formation). In the interests of transparency OGP supports the on-line disclosure of the chemical additives used in hydraulic fracturing (such as fracfocus.org in the United States or as currently listed on several of our members web sites).

The water, sand and additives mixture injected into the geologic formation at high pressure forms micro fractures in the shale that allow the trapped gas to flow to the wellbore. During this hydraulic fracturing process, an on-site treatment pressure comparison ensures stimulation is only injected in geologic formations of interest. The extent of the micro fractures from the well bore can be estimated by taking highly sensitive seismic measurements during the hydraulic fracturing process. The micro fractures extend typically less than 180 metres upward from the well bore. The probability that any micro fractures extend vertically upward beyond 350 metres is ~1% and beyond 500 metres is a small fraction of 1%. This is because layered sedimentary rocks provide natural barriers to the progression of the micro fractures.6

Figure 8 (above) shows micro seismic measurements of the actual maximum extent of micro fractures from a series of wells in the Barnett Shale in the United States.7

FIGURE 7: WHAT IS IN A TYPICAL FRACTURING FLUID?

FIGURE 8: MICROSEISMIC MEASUREMENTS OF DISTANCE FROM FRACTURES TO WATER SOURCE

http://fracfocus.org



What happens to the hydraulic fracturing fluid injected into the ground? ... ContinuedExtrapolating the distance of the vertical fractures for a typical European shale gas well would leave a distance of 1 to 3 kilometres between the fracture and the water source separated. Multiple layers of impermeable rock strata prevent any water, gas or chemicals from reaching a water source.

Figure 9 provides a scale illustration of this. In addition, as the well bore penetrates the water source near the surface, any produced water or hydrocarbons are separated from the water source by multiple layers of impermeable cement and steel casing, which is tested to ensure well integrity prior to commencing any hydraulic fracturing. This is also shown at the top of Figure 9.

This type of well design and construction stops hydrocarbons from entering the water source and local well water. Hydraulic fracturing has been used in over 2 million wells world-wide since the 1940’s8 and comprehensive studies have found no historical cases in which hydraulic fracturing has contaminated

drinking water.9 The UK Department of Energy and Climate Change (DECC) has recently (early 2012) concluded that ‘In the light of the robust controls in place...to protect the environment and ensure safe operation, DECC see no need for any moratorium on shale gas’ development. ‘This is also the view of the (UK) Energy and Climate Change Select [parliamentary] Committee, which held an inquiry into shale gas in 2012 and took evidence from government, regulators, the British Geological Survey, the oil and gas industry and environmental groups. The committee also concluded that hydraulic fracturing does not pose a direct risk to water sources, provided that the well-casing is intact. Any risks that do arise are more likely to be related to the integrity of the well, and are no different to issues encountered when exploring for and producing hydrocarbons from conventional geological formations.’10

FIGURE 9: WELL CONSTRUCTION AND DISTANCES EXAMPLE



Can you recover the water used in hydraulic fracturing?A: Depending on the geology of the shale formation, during hydraulic fracturing typically 10% to 70% of the water used is recoverable in the first 2-5 weeks of production. The water flows to the surface and is separated from the natural gas. The water may contain suspended clay particles, dissolved inorganic components from the shale (total dissolved solids), organic compounds from the hydraulic fracturing fluids and the hydrocarbons in place, and sand and silt particles from the shale or proppant (sand). Appropriate government authorities issue permits for handling and disposal of produced water. This procedure is consistent with the EU Mining Waste Directive.

6

Water flows to the surface & separates from the gas

Water is shipped to processing facility or recycled at surface & re-used

iron & solidsorganic mattermethaneNORM

Recycle/ disposal

Source Transport

Store

Store Utilise

Treat

The water can then be shipped to licensed water processing facilities or recycled at the surface and re-used for subsequent hydraulic fracturing operations. As a reference, the British Columbia Oil and Gas Commission has estimated that 20% of the water used in hydraulic fracturing for Horn River Basin, Canada comes from reuse of flowback water11 and recycling of flowback water in the Marcellus Basin in Pennsylvania is now approaching 100% to reflect local conditions. In other basins the use of recycling is less prevalent than the Marcellus, but is

FIGURE 10: CAN USED WATER BE RECOVERED?

FIGURE 11: VARIOUS WATER MANAGEMENT STEPS

generally increasing. Various treatment technologies allow the produced water to be reused for other hydraulic fracturing operations, or enhanced recovery projects, or other industrial uses.



Water may absorb low levels of radioactivity through contact with NORM

air soil

food water

Naturally Occurring Radioactive Material is found in:

Any radioactive material absorbed during operations that flows back up the well bore is contained & disposed of

The resulting NORM in recovered water is

very low

7 Does the water used in drilling or hydraulic fracturing have radioactive material in it?A: Some rocks naturally contain trace levels of minerals that are radioactive. Depending on the regional and sedimentary environment, water used in the exploration and production process (whether in typical sandstone reservoirs or shale) may absorb low levels of radioactivity through contact with this naturally occurring radioactive material (or ‘NORM’). NORM is also found in the air, soil, water, and in many of our foods in normal background levels.

Lower than background levels

Any radioactive material that is absorbed from the subsurface during drilling, hydraulic fracturing or production operations and flows back up the well bore is contained and disposed of at certified waste facilities. NORM in this water typically presents very low risks. In a recent study of outflow from treatment plants for water used in the Marcellus Basin in Pennsylvania, the test results showed that treated water contained levels of radioactivity lower than normal background levels.12

1 Polish Geological Institute – Environmental impact of hydraulic fracturing treatment performed on the Lebien LE-2H well, 2012 2 http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Water_statistics3 Polish Geological Institute – 2010 figures4 Massachusetts Institute of Technology – The Future of Natural Gas, 20115 Ground Water Protection Council, for U.S. Department of Energy 6 Richard J. Davies et al – Hydraulic Fractures, How far can they go? Durham Institute, Marine and Petroleum Geology, 20127 Kevin Fisher – “Data Confirm Safety of Well Fracturing,” The American Oil & Gas Reporter, July 2010 8 SPE – Hydraulic Fracturing, History of an Enduring Technology, 20109 USDOE and GWPC Study – State Oil and Natural Gas Regulations Designed to Protect Water Resources, 200910 UK Department of Energy and Climate Change – http://www.decc.gov.uk/en/content/cms/meeting_energy/oil_gas/shale_gas/shale_gas.aspx 11 Campbell Matt Horne and Karen Campbell – Shale gas in British Columbia: Risks to B.C.’s water resources, Pembina Institute, September 2011 12 Pennsylvania Department of Environmental Conservation – http://www.portal.state.pa.us/portal/server.pt/community/newsroom/14287?id=16532&typeid=1

References

FIGURE 11: WHAT IS NORM?

…Shale gaS operationS Frequently asked questions about chemicals

This document provides factual information about shale gas operations and chemicals

1 Are you prepared to carry out baseline testing of drinking water sources? What is typically included in baseline testing?A: Yes. OGP members believe that baseline testing of water sources in new areas of operation is in everyone’s best interest. Baseline testing of water sources is normally part of an Environmental Impact Assessment and/or part of the drilling permit. Baseline testing is also one of the IEA’s “Golden Rules for a Golden Age of Gas” (Measure, Disclose, Engage).

Providing authorities with a clear understanding of the chemical status of water sources before and after drilling and completion is an important part of water source management. Authorities may then choose to make this information publicly available to local communities.

Best practice is to sample groundwater in a pre-determined vicinity of a new well site both prior to and after drilling and fracturing. Depending on applicable regulations, local conditions and operator policies, the testing may include water wells and surface water such as rivers, ponds or lakes in the immediate vicinity of the planned well.

Baseline tests typically include measuring levels of iron, solids, organic matter, naturally occurring radioactive material (or ‘NORM’) and methane.

What is NORM?Naturally Occurring Radioactive Material is found in:

Water may absorb low levels of radioactivity through contact with NORM

AIR SOIL

FOOD WATER

The resulting NORM in recovered water is

very low

Real-world exampleThe Polish Geological Institute tested 17 water wells and one creek in the vicinity of the Lebien LE-2H well before and after drilling and found no evidence of any change in surface or ground water quality as a result of the drilling or hydraulic fracturing processes for the well.

Source: Polish Geological Institute – Environmental impact of hydraulic fracturing treatment performed on the Lebien LE-2H well, 2012

Any radioactive material absorbed during operations that flows back up the well bore is contained & disposed of

Testing also occurs:After drilling & fracturing

Baseline tests measure:Levels of iron & solidsOrganic matterMethaneNORM

NORM is also found in the air, soil, water, and in many of our foods at normal background levels. Some rocks naturally contain trace levels of minerals that are radioactive. NORM in water used in the exploration and production process typically presents very low risks. A recent Pennsylvania Department of Environmental Conservation study of the outflow from treatment plants for water used in the Marcellus Basin in Pennsylvania showed that treated water contained levels of radioactivity lower than normal background levels.

Depending on the regional geological and sedimentary environment, water used in the exploration and production process (whether in typical sandstone reservoirs or shale) may absorb low levels of radioactivity through contact with this naturally occurring radioactive material. Any radioactive material that is absorbed from the subsurface during drilling, hydraulic fracturing or production operations and flows back up the well bore is contained and disposed of at certified waste facilities.

Measuring baseline methane is an important way to differentiate between naturally occurring methane that can be found in many biogenic environments such as lakes, ponds and shallow water sources/water wells before development activities even commence.

FIGURE 1: GROUNDWATER IS TESTED BEFORE & AFTER DRILLING AND COMPLETION



2

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Are you prepared to disclose chemicals in fracturing fluids publicly?

Why are there chemicals in fracturing fluids?A: All hydraulic fracturing fluids contain a small proportion of additives. These fulfil very specific purposes, such as controlling rust or reducing bacteria levels, to improve the overall productivity of the well. On average, chemical additives make up only 0.5% of a fracturing fluid and many are typically found in food additives, makeup and household cleaning products.

Are you prepared to register your fracturing fluid additives under REACH?A: Yes. All additives in fracturing fluids that exceed the one metric tonne threshold and other requirements set by REACH must be registered at ECHA by the manufacturer or importer.

A: Yes, we are committed to keeping people well informed about additives used in their local area. Many OGP members who are active in shale gas exploration in Europe already disclose information via various industry initiatives or on their company websites, even though the number of shale gas fracturing operations in Europe is currently very small.

In order to address the need for greater transparency, OGP supports the public disclosure of the additives used in hydraulic fracturing (such as fracfocus.org in the United States or as currently listed on several of our members web sites). The full disclosure of fracturing fluid additives and volumes is one of the IEA’s “Golden Rules for a Golden Age of Gas” (Measure, Disclose, Engage).

MEASURE

DISCLOSE

ENGAGE

IEA’s GOLDEN RULES

REGULATORS

COMMUNITIES

DISCLOSURE ON...

Chemicals

Additives

Fracking operations

Water use

Are you prepared to list components by proportion/by %?

FIGURE 2: OGP SUPPORTS PUBLIC DISCLOSUREA: Yes, OGP supports the public online disclosure of the additives used in hydraulic fracturing (such as fracfocus.org in the United States or as currently listed on several of our members’ websites), which includes maximum component concentrations.

6 Are you prepared to disclose when fracturing operations are carried out per well?A: Yes, OGP supports the public on-line disclosure of the additives used in hydraulic fracturing on-line (such as fracfocus.org in the United States or as currently listed on several of our members’ websites), which includes well–by–well statistics.



Are you prepared to disclose water use per well? A: Yes, OGP recognises the importance of appropriately managing and conserving water. It is accepted industry practice in the United States to disclose how much water has been put into a well and OGP supports this practice.

It is also important for operators to record water usage and in some countries, such as Poland, operators must measure all water used in order to comply with the terms of permits.

7

Companies need to

protect their intellectual property to remain

competitive & benefit from their investment, which drives further

innovation & investment

OGP supports disclosure as per EU

regulations & REACH. Suppliers understand the

importance of such disclosure

What is your position with regard to “intellectual property”? A: OGP supports the public disclosure of additives used in fracturing operations consistent with the European regulatory structure and REACH processes. Our suppliers are already aware of the importance of public disclosure of additives and are in dialogue with our members about the best way to do this for European audiences.

Geologic and reservoir characteristics such as mineralogy, rock strength, permeability, reservoir fluid composition, pressure, and temperature are just a few of the factors considered in selecting an appropriate fracturing fluid. Service companies have developed a number of different hydraulic fracturing fluid recipes to more efficiently induce and maintain productive fractures. These solutions have unique characteristics and therefore the exact concentrations of some additives are protected as proprietary information. OGP recognises that intellectual property rights are critical for businesses – these rights enable business to benefit from their investments and remain competitive in the global marketplace. Any disclosure process needs to include protection for the intellectual property represented in some chemical makeups and concentrations in the hydraulic fracturing fluid. We believe fracfocus.org in the United States has managed to provide unprecedented amounts of information on hydraulic fracturing fluids, including even non-hazardous constituents, while protecting vital intellectual property that allows for continued innovation and, hence, improvement.

Further, the Harmonised Mandatory Control System for the Use and Reduction of the Discharge of Offshore Chemicals used in the North Sea and North East Atlantic Areas (OSPAR) requires proprietary chemical compositions to be directly disclosed to the competent authority by the supplier.

FIGURE 3: STRIKING A BALANCE ON DISCLOSURE

8

…Shale gaS operationS Frequently asked questions about seismicity

This document provides factual information about shale gas operations and seismicity

1

2

Is hydraulic fracturing increasing the risk of earthquakes?A: No. As stated in a recent study from the Department of Environmental Conservation of New York State:

There is a reasonable base of knowledge and experience related to seismicity induced by hydraulic fracturing. Information reviewed in preparing this discussion indicates that there is negligible increased risk to the public, infrastructure, or natural resources from induced seismicity related to hydraulic fracturing. The microseisms created by hydraulic fracturing are too small to be felt, or to cause damage at the ground surface or to nearby wells.1

Why does the Industry use the term “induced seismicity” instead of earthquake?A: Induced seismicity is the phenomenon where human activity alters the frequency of occurrence and the magnitude of seismic events from natural levels.

The mechanisms for natural earthquakes and induced seismicity by hydraulic fracturing are very different. By design, hydraulic fracturing treatments release energy deep underground, creating very low levels of seismic activity that generally cannot be felt at the surface. In contrast, most natural earthquakes occur when ruptures and fractures in the earth slip due to the build-up of stresses along a plane such as a fault or joint. When movement on the fault occurs, energy is released and is transmitted through the earth as seismic waves that can cause shaking and movement of the ground at the surface.

In many oil and gas operations, hydraulic fracturing is used to enhance production flow rate. Shale gas is produced by drilling horizontally and hydraulically fracturing shale rock typically one to three

A mixture of water, sand and additives are pumped into the well under controlled pressure to fracture the shale

Hydraulic fracturing is a 3-5 day process

The sand keeps the fissures open, allowing natural gas to flow from the fissures into the well & to the surface

Many industrial activities can induce seismic events:

impounding water

tunnelling

pile driving vibrating rollers

industrial pressesheavy vehicle movements

geothermal energyproduction

quarrying

mining activity

shale & tight gas activity

Hydraulic fracturing releases energy deep underground, creating low levels of siesmic activity that generally cannot be felt at the surface

Earthquakes occur when ruptures or fractures in the earth slip along a plane, such as a fault or joint, releasing energy as seismic waves that can cause shaking & movement of the ground at the surface

kilometres beneath the surface. Hydraulic fracturing is a 3–5 day well completion process that injects water, proppant (sand) and chemical additives into the shale under controlled pressures to fracture it and allow the natural gas to flow to the surface.

Shale and tight gas exploration and production are one of many industries that can induce seismic events and/or above-ground movements and vibrations.

Other activities that can induce seismicity include:• Impounding water

(e.g. behind a dam)• Quarrying• Tunnelling• Mining activity• Geothermal energy production• Pile driving• Vibrating rollers• Industrial presses • Heavy vehicle movements

FIGURE 1: INDUCED SEISMICITY vs NATURAL EARTHQUAKES



3

4

What is seismicity magnitude and intensity?A: Magnitude is the amount of energy released at the source of an earthquake, while earthquake intensity is the strength of shaking produced by the earthquake at a certain location.

Intensity is determined from effects on people, human structures and the natural environment (and measured as surface displacement or reported damage against the Modified Mercalli scale2) while magnitude is measured by a seismograph (and reported against the Richter Magnitude Scale). Earthquake intensity is sometimes compared to other activities that are felt by humans at the surface, such as vibrations from passing traffic.

The Richter Magnitude Scale is a base-10 logarithmic scale obtained by calculating the logarithm of the amplitude of waves measured by a seismograph.

1. 2. 3. 4. 5. 6. 7. 8. 9.

Only felt by instruments

INSIGNIFICANT LOW MINOR MODERATE INTERMEDIATE NOTEWORTHY HIGH FAR-REACHING OUTSTANDING

Equivalent to vibrations of

trucks

May break a few windows

Move furniture, fissure walls

Severe damage to weak structures

Buildings displaced, cracks in earth

Bridges destroyed, few structures intact

Total destruction

An earthquake that measures 5.0 on the Richter scale has a shaking amplitude ten times larger and corresponds to an energy release of √1000 ≈ 31.6 times greater than one that measures 4.0.

Events below 3 on the Richter scale are generally not felt by people at the surface.

Note: Quarrying, mining and other industries measure the surface disturbance, often measured as peak particle velocity, which is a better method for determining the impact, because the surface effects of an earthquake depend on its depth, the rocks where it occurs and the rocks above it. An alternative scale used is the Modified Mercalli scale (see footnotes), which is related to the reported damage which occurs at the surface.

What are the risks induced by hydraulic fracturing?A: Hydraulic fracturing treatments create extremely low levels of seismic activity typically below minus 0.8 (-0.8) on the Richter scale3. Moreover, it is a temporary process, generally lasting only a few hours.

Over two million wells have been hydraulically frctured worldwide. Of these, there are only a few rare cases when a number of factors coincide, including the activation of existing faults (see the Blackpool event below), where hydraulic fracturing could be linked to induced seismicity up to a magnitude 3 (truck vibration equivalent).

In addition, recent governmental or academic studies lead to similar conclusions4,5,6,7.

FIGURE 2: THE RICHTER MAGNITUDE SCALE



5

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What happened in the Blackpool area of the UK in 2011?A: In the UK, hydraulic fracturing was suspended at Cuadrilla Resources’ Preese Hall exploratory site after a magnitude 1.5 event on 27 May 2011 in the Blackpool area and in light of a preceding magnitude 2.3 event on 1 April 20118.

At that time the British Geological Survey (2011) commented: “We understand that fluid injection, between depths of two to three kilometres, was ongoing at the Preese Hall site shortly before both earthquakes occurred. The timing of the two events in conjunction with the fluid injection suggests they may be related. It is well-established that fluid injection can induce small earthquakes. Typically, these are too small to be felt.”

In a recent report, the UK Department of Energy and Climate Change (DECC) recognises the risk of induced seismicity below 3 on the Richter scale. Such events are “unlikely to cause structural damage” and therefore the DECC could “see no reason why Cuadrilla Resources Ltd. should not be allowed to proceed with their shale gas exploration activities. DECC went on to recommend cautious continuation of hydraulic fracture operations, at the Preese Hall site9.” In December 2012, the UK govern ment announced its decision to allow hydraulic fracturing to resume.

What happened in the US (Texas, 2008/9; Ohio, 2011)? A: A number of the small-to-moderate earthquakes that occurred in the US in 2011 have been associated with the disposal of wastewater, and not directly related to natural gas production. It should be emphasised that: • They are not triggered by hydraulic fracturing itself but possibly by waste water injection;• No earthquake triggered by fluid injection has ever caused injuries or significant damage;• More than 144,000 wastewater disposal wells have been operating safely in the US for many

decades; and• When properly planned, operated, and monitored, fluid disposal wells are safe, as demonstrated

by decades of disposal operations involving many industries10.

How can hydraulic fracturing be undertaken in areas prone to seismicity?A: Clearly tectonic areas, with active faults, are more prone to seismic events. These areas, however, are well known, and sound pre-planning and surveying prior to operating in these areas can mitigate the risk.

Geological risk assessments should be conducted prior to drilling fluid disposal wells

Faults with large, pre-existing stress in brittle rock formations should be avoided

Proper limits on flow rate should be set

Very small to moderate sized seismic events can be induced in the earth when large volumes of water or other fluids are disposed of in the vicinity of faults that have pre-existing stress, such that they are on the verge of moving (“failure”). The injected fluids can affect the stress state or reduce friction on the plane of the fault, causing it to fail. When properly planned, operated, and monitored, with contingency plans in place, these operations are safe. It is important for all disposal operations

7

to avoid faults with large, pre-existing stress in brittle rock formations and to set proper limits on the flow rate of water into the formation. These conditions can generally be met by conducting geologic risk assessments prior to drilling wells for fluid disposal.

FIGURE 3: SOUND PRE-PLANNING & SURVEYING CAN MITIGATE RISK IN AREAS PRONE TO SEISMICITY



What measures are taken to mitigate induced seismicity?A: Recommendations have been proposed in order to mitigate induced seismicity, in particular by the US Department of Energy11, the UK Department for Energy and Climate Change12, and in academic papers13.

Sound pre-planning and surveying are likely to be the most important factors that should be taken into account by operators and reviewed by the regulator.

We believe the correct approach is for government to review the risks and seek advice regarding mitigation measures. We support the inclusion of best practice in developing new guidelines, which would enable exploration and production while tackling public concerns and mitigating impacts. OGP is happy to offer assistance to develop these guidelines.

Would an operator be liable in the case of damage as a result of seismic activity?A: Operators are subject to the laws of the jurisdiction and the terms of the administrative authorisation they have been granted, for damages caused by their activities.

Is it likely that seismic activity would damage well integrity and lead to leakage?A: A study by the Department of Environmental Conservation of the New York State considers it very unlikely, based on the existing track record of earthquakes in oil and gas producing areas of the United States14. In addition, the National Resource Council released a 225-page report on induced seismicity in June 2012 that reinforces this position15.

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9

10



1 Department of Environmental Conservation, New York State — Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program (September 2011) 2 California Geological Survey, Note 32, How earthquakes and their effects are measured (2002) See also: US Geological Survey Website

3 Magnitude / Intensity Comparison

The following table gives intensities that are typically observed at locations near the epicenter of earthquakes of different magnitudes.

Magnitude Typical Maximum Modified Mercalli Intensity

Abbreviated Modified Mercalli Intensity ScaleI. Not felt except by a very few under especially favorable conditions. II. Felt only by a few persons at rest, especially on upper floors of buildings. III. Felt quite noticeably by persons indoors, especially on upper floors of buildings. Many people do not recognise it as an earthquake. Standing motor cars

may rock slightly. Vibrations similar to the passing of a truck. Duration cab be estimated. IV. Felt indoors by many, outdoors by few during the day. At night, some awakened. Dishes, windows, doors disturbed; walls make cracking sound.

Sensation like heavy truck striking building. Standing motor cars rocked noticeably. V. Felt by nearly everyone; many awakened. Some dishes, windows broken. Unstable objects overturned. Pendulum clocks may stop. VI. Felt by all, many frightened. Some heavy furniture moved; a few instances of fallen plaster. Damage slight. VII. Damage negligible in buildings of good design and construction; slight to moderate in well-built ordinary structures; considerable damage in poorly

built or badly designed structures; some chimneys broken. VIII. Damage slight in specially designed structures; considerable damage in ordinary substantial buildings with partial collapse. Damage great in poorly

built structures. Fall of chimneys, factory stacks, columns, monuments, walls. Heavy furniture overturned. IX. Damage considerable in specially designed structures; well-designed frame structures thrown out of plumb. Damage great in substantial buildings, with

partial collapse. Buildings shifted off foundations. X. Some well-built wooden structures destroyed; most masonry and frame structures destroyed with foundations. Rails bent. XI. Few, if any (masonry) structures remain standing. Bridges destroyed. Rails bent greatly. XII. Damage total. Lines of sight and level are distorted. Objects thrown into the air.

1.0 - 3.0 I

3.0 - 3.9 II - III

4.0 - 4.9 IV - V

5.0 - 5.9 VI - VII

6.0 - 6.9 VII - IX

7.0 and higher VIII or higher

Frequency of Occurrence of Earthquakes

Magnitude Average annually a Based on observations since 1900. These numbers have been recently updated, based on data from the Centennial catalogue (from 1900 to 1999) and the PDE (since 2000). b Based on observations since 1990. 8 and higher 1a

7 - 7.9 15a

6 - 6.9 134b

5 - 5.9 1319b

4 - 4.9 13,000 (estimated)

3 - 3.9 130,000 (estimated)

2 - 2.9 1,300,000 (estimated)

4 Worldwatch Institute, Natural Gas and Sustainable Development Initiative — Addressing the Environmental Risks from Shale Gas Development — Mark Zoback, Saya Kitasei and Bradford Copithorne, (July 2010)5 A report by researchers at the Tyndall Centre University of Manchester — Shale gas: an updated assessment of environmental and climate change impacts, (January 2012)6 New York State Department of Environmental Conservation Division of Mineral Resources — Supplemental generic environmental impact statement on the oil, gas and solution mining regulatory program (2011) 7 Both carbon sequestration and liquid waste injection can induce seismic activity. Induced seismic events caused by deep well fluid injection are typically less than a magnitude 3.0 and are too small to be felt or to cause

damage. Rarely, fluid injection induces seismic events with moderate magnitudes, between 3.5 and 5.5, that can be felt and may cause damage. Most of these events have been investigated in detail and have been shown to be connected to circumstances that can be avoided through proper site selection (avoiding fault zones) and injection design (Foxall and Friedmann, 2008). Department of Environmental Conservation, New York State - Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program (September 2011)

8 WorldWatch Institute — Addressing the Environmental Risks from Shale Gas Development, Mark Zoback, Saya Kitasei, Brad Copithorne (July 2010) 9 Report by researchers at the Tyndall Centre University of Manchester — Shale gas: an updated assessment of environmental and climate change impacts (January 2012)10 We agree with the conclusion that the observed seismicity was induced by the hydraulic fracture treatments at Preese Hall. However, we are not convinced by the projected low probability of other earthquakes during future treatments.

However, we consider that the historical record of maximum observed magnitudes from coal-mining induced earthquakes in the UK can be used to provide a realistic upper limit. This leads to a maximum magnitude of ~ 3.0 ML. An event of this size at an expected depth of 2-3 km is unlikely to cause structural damage. Based on the induced seismicity analysis done by Cuadrilla and ourselves, together with the agreement to use more sensitive fracture monitoring equipment and a DECC agreed induced seismic protocol for future operations, the authors of this report see no reason why Cuadrilla Resources Ltd. should not be allowed to proceed with their shale gas exploration activities and recommend cautious continuation of hydraulic fracture operations, at the Preese Hall site. Preese Hall shale gas fracturing — Review & recommendations for induced seismic mitigation (April 2012)

11 Earth Magazine — Managing the Seismic Risk Posed by Wastewater Disposal, Mark Zoback, (April 2012)12 US department of Energy — Protocol for Addressing Induced seismicity Associated with Enhanced Geothermal Systems, DOE/EE-0662, (January 2012)13 Preese Hall shale gas fracturing — Review & recommendations for induced seismic mitigation (April 2012)14 Wells are designed to withstand deformation from seismic activity. The steel casings used in modern wells are flexible and are designed to deform to prevent rupture. The casings can withstand distortions much larger

than those caused by earthquakes, except for those very close to an earthquake epicenter. The magnitude 6.8 earthquake event in 1983 that occurred in Coalinga, California, damaged only 14 of the 1,725 nearby active oilfield wells, and the energy released by this event was thousands of times greater than the microseismic events resulting from hydraulic fracturing. Earthquake-damaged wells can often be re-completed. Wells that cannot be repaired are plugged and abandoned (Foxall and Friedmann, 2008). Induced seismicity from hydraulic fracturing is of such small magnitude that it is not expected to have any effect on wellbore integrity. Department of Environmental Conservation, New York State — Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program 6-326, (September 2011)

15 National Research Council - Induced Seismicity Potential in Energy Technologies (2012)

References

…Shale gaS operationS– F.A.Q.s on greenhouse gases

…Shale gaS operationS Frequently asked questions about Green House Gases

This document provides factual information about shale gas operations and GHG

1 What is the difference between natural gas from shale and natural gas from other reservoirs?

Once extracted, there is no difference between natural gas from shale rock and from other reservoirs

Hydraulic fracturing is required to extract shale gas from otherwise impermeable shale

A: Shale gas is natural gas produced from sedimentary shale rock composed of organically rich mud and clay. Shale rock formations are found miles below the earth’s surface. Generally, porosity and permeability decrease as depth increases due to the pressures exerted by the earth’s weight. At great depths, there may not be sufficient permeability to allow hydrocarbons to flow from the targeted formation into the wellbore. Hydraulic fracturing operations are essential to increase the interconnectivity (permeability) between pore spaces in the formation.

Extraction of these resources on a commercially viable basis has been made possible by the combination of two conventional techniques called ‘horizontal drilling’ and ‘hydraulic fracturing’. Without hydraulic fracturing, the shale rock is simply too impermeable and valuable gas would remain locked underground.

Natural gas that is produced from shale reservoirs is the same as gas produced from sandstone, tighter siltstones, limestone or dolomite reservoirs and has significantly lower GHG emission than coal.

FIGURE 1: SHALE GAS IS NATURAL GAS

Study from EU Directorate-General for Climate Action1:

• For the base case considered for shale gas, the GHG’s per unit of electricity generated are around 4% to 8% higher than for electricity generated by conventional pipeline gas from within Europe

• Emissions from shale gas generation (base case) are: 2% to 10% lower than emissions from electricity generated from sources of conventional pipeline gas located outside of Europe (in Russia and Algeria)

• 7% to 10% lower than electricity generated from LNG imported into Europe”

2 What is the Greenhouse Gas (GHG) emission footprint of shale gas?A: It is comparable to that of gas produced from other types of reservoirs, and when gas is used to generate electricity, the GHG footprint of natural gas is less than half that of hard coal and less than a third of lignite-fired coal power.2

The life-cycle of natural gas encompasses a variety of processes, with varying amounts of GHG emissions, as outlined below:

• Extraction. The only area where shale gas may differ from gas produced from sandstone reservoirs is in the extraction process. The difference in GHG emissions is only marginal due to the use of more energy-intensive equipment at the well-site and increased water consumption. Emissions of methane may occur following hydraulic fracturing and well completion during the “flowback”




When gas is used to generate electricityThe life-cycle ghg footprint of shale gas is:

Less than 1/3 of lignite-fired coal power

Less than 1/2 of hard coal

3/4 of natural gas life-cycle emissions

are generated here

ExtractionGHG emissions for shale gas are marginally higher due to more energy- intensive equipment & higher water use

ProcessingProcessing shale gas is no more emission intensive than gas from other formations

TransportationThere is no difference between the emissions of transportation of gas from different reservoirs

CombustionThere are no additional emissions during combustion of shale gas compared to other types of natural gas

FIGURE 2: SHALE GAS GHG FOOTPRINT IS COMPARABLE TO GAS FROM OTHER RESERVOIRS

of the well when some methane, hydraulic fracturing fluids (primarily water), and formation fluid return to the surface immediately prior to the well being put into production and when using open storage ponds; closed storage tanks can almost completely eliminate this methane discharge (see also later references on Reduced Emission Completion (REC) technology. Industry takes safeguards to minimise these emissions and operate safely.

• Processing. Processing of shale gas presents no significant difference from other types of gas. The variance in emission quantities during this phase depends on the gas/oil ratio, flow pressure of the wells, CO2, N2 or H2S content of the gas, and the viscosity and sulphur content of the oil or condensate that is separated from the shale gas at a production facility. None of these characteristics makes the processing of shale gas more emission intensive than natural gas from other types of formations.

• Transportation. There is no difference between the transportation of natural gas from different reservoirs. Emissions in this phase are dependent upon the mode of transportation (pipeline or LNG) and the distance to the consuming market. Transport emissions would be lower within Europe than in Russia and most parts of the US, due to the proximity of these resources to consumers.

• Combustion. Over three quarters of the life-cycle emissions of natural gas are generated during the combustion phase3. There are no additional emissions in the combustion of shale gas compared to those of natural gas from other types of reservoirs.

A study carried out by Prof William Griffith et al. of Carnegie Mellon University concludes that the life-cycle footprint of shale gas from the Marcellus formation is only 3% higher than the average domestic gas in the United States4. In December 2011, the U.S. National Energy Technology Labs estimated that “shale gas life cycle emissions are 6% lower than conventional natural gas.”




3 Is the GHG footprint of shale gas less than other energy sources, and can it be further reduced?A: Yes. The life-cycle GHG footprint of shale gas is less than half that of hard coal and less than a third of lignite-fired coal power emissions from the life-cycle of shale gas can be further reduced5.

Industry takes a pro-active approach to limit emissions and employs its expertise and capability to do so. It has already reduced the emissions of methane (CH4) and carbon dioxide (CO2) from shale gas production. Further improvements will cut emissions from the drilling and production phases by utilising additional equipment and practices to prevent or capture CH4 emissions. Captured gas can be sold or used on site for enhanced recovery, or as a fuel source. Implementation of rigorous preventative maintenance programs will also help reduce emissions.

Natural gas or electricity instead of diesel

Water pipelines instead of trucks

*Experience shows that once operations begin & big businesses dedicate significant resources to continuous improvement, emissions will be even further improved

REC well technologies (green completions)for example:

wellhead sandtrap

separator

condensatetank

gasdehydrater

wastewatertank

separator

CSS technologies (potentially viable post-2030)for example:

CO2 capture & sepration

CO2

compression

CO2 source

CO2 injection

CO2 storage

Responsible monitoring of all phases

FIGURE 3: FURTHER REDUCING THE SHALE GAS GHG FOOTPRINT*




• Use of efficient equipment. The use of natural gas or electricity instead of diesel to power engines and equipment at the well-site is a potential source of emission reductions. Similarly, the use of pipelines instead of trucks for the transport of the water to and from the well-site can, under certain conditions, further reduce the life-cycle carbon footprint of shale gas.

• Separation and capture of gas from water. The water returned from the hydraulic fracturing treatment may contain high concentrations of methane, some of which may be flared or occasionally vented at the well-site.

Reduced Emission Completion (REC) technologies — also known as green completions — are techniques that separate and capture methane emitted during well completions and flowback.

This technique uses a system of piping, separators and sometimes dehydration equipment to capture the gas during a completion, clean it and send it to the sales line instead of flaring or venting it. This technology requires that a pipeline be laid up to the well-pad and is now applied to the majority of new wells in the United States.

Use of REC depends on the characteristics of the basin and the area it is located, but with proper planning of field development, including gas pipeline construction, the industry will strive to utilise such solutions.

Moreover, advanced planning, favoured by the existing European licencing framework, allows for a timely coordination of drilling and pipeline installation. Industry is working with suppliers to ensure that the availability of REC equipment keeps up with demand.

In April 2012, the EPA finalised their New Source Performance Standards (NSPS OOOO) for oil and natural gas source category. NSPS OOOO requires operators to recover gas and liquids during flowback operations, route sale-quality natural gas to a flowline, flare combustible gas not capable of being sent to a flowline or vent gas if safety, environmental or other conditions prevent flaring.

• Monitoring. Responsible monitoring of all phases of operations allows a timely identification of leaks and fast response mechanisms to minimise emissions.

• Carbon capture and storage. Carbon capture and storage technologies have the potential to bring life-cycle emissions from natural gas, including the combustion phase, to very low levels. These technologies are not cost-effective at present, but a number of pilot projects are on-going and the technology is expected to be commercially viable after 2030 if a favourable regulatory, commercial and political framework is in place.

Industry’s track record shows that emissions are reduced once operations begin, especially as larger businesses have entered this business segment and dedicate significant resources to continuous improvement.

4 Is the current European regulatory framework relating to high emission standards adequate?A: Yes. Natural gas developments in Europe are a tightly regulated activity. The current European regulatory framework already covers emissions resulting from the extraction, processing, transportation and combustion of shale gas with the EU Emission Trading Scheme (ETS), the Industrial Emissions Directive and various emission performance standards.




5 How can burning shale gas help the EU’s efforts to reduce emissions?

On a well-to-wire basis, natural gas power plants emit less than 1/2 the CO2 of coal

Flexible back-up for renewables

Could be retro-fitted with CCS technologies

In the long-term:

Fully amortised by 2030

CCS

Shale gas can offer a long-term low emission solution

Emissions could be reduced by if all EU oil- & coal-fired power plants were converted to best performance CCGT

Coal-to-gas switching has been the largest contributer to Europe’s emission reduction from 1990 levels

low capital

rapid cost recovery

Base-load power

Peak consumption

A: On a well-to-wires basis, natural gas power plants emit around half the CO2 of coal power plants. The exact reduction in CO2 depends on the type of gas plant and the type of coal plant being compared. Natural gas, including shale gas, is a critical fuel for Europe’s energy transition as the Commission recognised in the Energy Roadmap 20506. Coal-to-gas switching has been the largest contributor to Europe’s 11% emission reduction from 1990 levels. IHS-CERA calculated that emissions reduction of up to 58% could be achieved if all EU oil- and coal-fired power plants were converted simultaneously to best performance combined cycle gas turbines (CCGT).

In the long-term, investment in natural gas, including shale gas, will not lock in emissions and drive investment away from renewable sources. Gas-fired power plants can serve both for base-load power generation and peak consumption and are characterised by relatively low capital requirements and rapid cost recovery. After 2030, they will be fully amortised and could serve as a flexible back-up for variable renewables such as wind and solar or be retrofitted with Carbon Capture and Storage (CCS) technologies, offering a long-term low-emission solution.

FIGURE 4: GAS FORM SHALE CAN HELP THE EU REDUCE ITS EMISSIONS




6 How can people claim that shale gas is less efficient than coal in terms of GHG emissions?A: Their analysis is based on questionable data and assumptions and has been repeatedly refuted.

Whilst we agree emissions from all energy sources need to be better understood, the quickest and cheapest way to reduce emissions is to switch power generation from coal to natural gas.

The claim made in a study by Prof Robert W. Howarth et al. from Cornell University that the GHG footprint of shale gas would be “higher than coal”7 has been directly or indirectly refuted by many studies8. OGP does not agree with many of the underlying assumptions in this paper or the overall conclusions. There are at least four fundamental mistakes in the analysis.

• Abnormally high fugitive emissions. The assumption that 1.9% of the methane produced over the life-cycle of a well is released in the atmosphere during well completion9 is an outlier in academic literature. The value used as benchmark is based on the arithmetic mean of small samples of data10 whose quality, by the authors own admission, was too low to draw ultimate conclusions11. Moreover, these data measured the amount of methane captured by REC wells and the study assumes that all of this methane is simply vented when REC equipment is not in place12. On the contrary, field operators strive to minimise methane emissions when not using REC wells, as leakages compromise safety conditions at the well-site and waste gas that could otherwise be commercialised13. When gas cannot be recovered in a green completion, most commonly, this methane is flared at the well-site, producing CO2 which has a much lower GHG warming potential.

• Abnormally high losses in transportation. The estimate of a leakage rate of 1.4% to 3.6% of total production during “transport, storage and distribution” is calculated using figures for “lost and unaccounted gas” (that is, the difference between the gas produced and the gas sold to consumers). This accounting unit, however, does not measure gas dispersed in the atmosphere, as that gas is largely used to power equipment and processing facilities. Direct measurements in the United States and Russia found average leakage rates ranging from 0.35% to 1.4%14.

• Unjustified time horizon of the analysis. The use of a 20-year time horizon to quantify the effect of emissions on climate is not supported by the scientific community15. As methane has a higher warming potential than CO2 but remains in the atmosphere for a shorter time than CO2, a 20-year horizon tilts the comparison of emissions in favour of coal, which emits less methane but considerably more CO2. However, the effects of climate change are a long-term concern and policies are based on a longer time horizon16. A 100-year time horizon is the accepted standard for Global Warming Potential calculations by the 2007 IPCC Forth Assessment Report and the UN Framework Convention on Climate Change (UNFCCC).

• Efficiency of gas in power generation not modelled. After using these (flawed) assumptions for emissions from shale gas, the authors compared them with those of coal on heat produced rather than on power produced basis. This ignores the fact that the efficiency of gas-fired power plants is 50–60% versus 30–40% for coal-fired plants17 resulting in a third to a half more electricity produced from a gigajoule of gas than from the same amount of coal. The authors themselves recognise this and admit in the paper’s supplemental materials that there is “an additional penalty for using coal over natural gas for the generation of electricity not included in our analysis”18. A correct comparison should be done on an MWh basis because this is the market where gas and coal compete.




1 Report for European Commission DG CLIMA ‘Climate impact of potential shale gas production in the EU’ 20122 Mott MacDonald — Update on UK Electricity Generation Costs, 2011 — (total emissions well to wire)3 Griffith et al., — Life cycle greenhouse gas emissions of Marcellus shale gas, 2011 4 Griffith et al., — Life cycle greenhouse gas emissions of Marcellus shale gas, 20115 Mott MacDonald — Update on UK Electricity Generation Costs, 2011 — (total emissions well to wire)6 European Commission, 2011 — Energy Roadmap 2050 COM(2011) 885/2 7 Howarth et al., — Methane and the greenhouse-gas footprint of natural gas from shale formations , 20118 Cathles III et al., — A commentary on “The greenhouse-gas footprint of natural gas in shale formations”, 2011; Griffith et al., — Life cycle greenhouse gas emissions of Marcellus shale gas, 2011; HIS —

Mismeasuring Methane, 2011; Venkatesh et al., — Uncertainty in Life Cycle Greenhouse Gas Emissions from United States Natural Gas End-Uses and its Effects on Policy, 2011; US DoE National Energy Technology Laboratory (NETL), Life Cycle Greenhouse Gas Analysis of Natural Gas Extraction & Delivery in the United States, 2011; Deutsche Bank & WorldWatch Institute, Comparing Life-Cycle Greenhouse Gas Emissions from Natural Gas and Coal, 2011

9 Howarth et al., — Methane and the greenhouse-gas footprint of natural gas from shale formations, 2011 10 Cathles III et al., — A commentary on “The greenhouse-gas footprint of natural gas in shale formations”, 2011 11 Authors’ recorded presentation to colleagues http://www.youtube.com/watch?v=EHg6Ueb2t-E&feature=player_embedded12 HIS — Mismeasuring Methane, 2011; Cathles III et al., A commentary on “The greenhouse-gas footprint of natural gas in shale formations”, 201113 HIS — Mismeasuring Methane, 201114 EPA — Methane emissions from the natural gas industry, 1996; Kirchgessner — Estimate of methane emissions from the US natural gas industry, 1997, Chemosphere 35: 1365–1390; Lelieveld et al. — Low

methane leakage from gas pipelines, Nature 434:841–842, 200515 Cathles III et al., — A commentary on “The greenhouse-gas footprint of natural gas in shale formations”, 201116 Schrag — Is Shale Gas Good for Climate Change?, 201217 Cathles III et al., — A commentary on “The greenhouse-gas footprint of natural gas in shale formations,” 2011; Griffith et al. - Life cycle greenhouse gas emissions of Marcellus shale gas, 201118 Howarth et al., — Electronic Supplemental Material to Methane and the greenhouse-gas footprint of natural gas from shale formations , 2011

References

London office:

209-215 Blackfriars Road, London SE1 8NL, UK Tel: +44 (0)20 7633 0272 Fax: +44 (0)20 7633 2350

Brussels office:

165 Bd du Souverain, B-1160 Brussels, Belgium Tel: +32 (0)2 566 9150 Fax: +32 (0)2 566 9159

ABoUT oGP

OGP represents the upstream oil & gas industry before international organisations including the International Maritime Organisation, the United Nations Environment Programme (UNEP), Regional Seas Conventions and other groups under the UN umbrella. At the regional level, OGP is the industry representative to the European Commission and Parliament and the OSPAR Commission for the North East Atlantic. Equally important is OGP’s role in promulgating best practices, particularly in the areas of health, safety, the environment and social responsibility.

Web: www.ogp.org.uk E-mail: [email protected]

member organisations

Abu Dhabi National Oil Company (ADNOC) Addax Petroleum Afren Plc Anadarko Petroleum Corporation BG Group BHP Billiton BP plc Cairn Energy Canadian Natural Resources International Chesapeake Energy Chevron Corporation CNOOC Limited ConocoPhillips Devon Energy Corporation Dolphin Energy Ltd DONG Energy Dragon Oil Eni SpA E.ON Ruhrgas ExxonMobil Fairfield Energy plc Galp Energia GDF SUEZ Hess Limited Husky Energy INPEX Corporation Kosmos Energy, LLC KUWAIT OIL COMPANY Maersk Olie og Gas AS Marathon Oil Company MOL Plc – Hungarian Oil & Gas Company Nexen Inc. Noble Energy, Inc.

North Caspian Operating Company NUNAOIL OMV Pan American Energy Papuan Oil Search Ltd Perenco Holdings Ltd Petróleo Brasileiro SA Petróleos Mexicanos (PEMEX) Petronas Carigali Sendirian Berhad Premier Oil PTT Exploration and Production Public Company Ltd (PTT EP) Qatar Petroleum Ras Laffan Liquified Natural Gas Company Limited (RasGas) Repsol YPF RWE Dea AG Safer Exploration & Production Operations Company Sasol International (PTY) Ltd Saudi Aramco Shell International Exploration & Production BV Statoil Suncor Talisman Energy TAQA TNK-BP Management Total Tullow Oil Wintershall Holding GmbH Woodside Energy Ltd Yemen LNG Company Ltd Zadco

national associations

American Petroleum Institute (API) Regional Association of Oil, Gas and Biofuels Sector Companies in Latin America and the Caribbean (ARPEL) Association of German Oil & Gas Producers (WEG) ASSOMINERARIA Australian Petroleum Production & Exploration Association Brazilian Petroleum, Gas and Biofuels Institute (IBP) Canadian Association of Petroleum Producers (CAPP) Consejo Colombiano de Seguridad Energy Institute International Association of Drilling Contractors (IADC) International Association of Geophysical Contractors (IAGC)IPIECA Irish Offshore Operators’ Association (IOOA) Netherlands Oil and Gas Exploration and Production Association (NOGEPA) Norwegian Oil and Gas Oil & Gas UK

associate members

Baker Hughes Incorporated Schlumberger

london office:

209-215 Blackfriars Road, London SE1 8NL, UK Tel: +44 (0)20 7633 0272 Fax: +44 (0)20 7633 2350

brussels office:

165 Bd du Souverain, B-1160 Brussels, Belgium Tel: +32 (0)2 566 9150 Fax: +32 (0)2 566 9159

aboUt ogpOGP represents the upstream oil & gas industry before international organisations including the International Maritime Organisation, the United Nations Environment Programme (UNEP), Regional Seas Conventions and other groups under the UN umbrella. At the regional level, OGP is the industry representative to the European Commission and Parliament and the OSPAR Commission for the North East Atlantic. Equally important is OGP’s role in promulgating best practices, particularly in the areas of health, safety, the environment and social responsibility.

Web: www.ogp.org.uk e-mail: [email protected]

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