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Shale gas and coal bed methane Potential sources of sustained energy in the future

2 Shale gas and coal bed methanePotential sources of sustained energy in the future

ContentIntroduction .................................................................................4Shale gas .....................................................................................6

Introduction .............................................................................................. 06

Worldwide shale gas development ............................................................. 08

Shale gas development: India .................................................................... 11

Technological development ....................................................................... 13

Costs and economics ................................................................................. 14

Risks and challenges ................................................................................. 15

Outlook .................................................................................................... 16

Coal bed methane ........................................................................18Introduction .............................................................................................. 18

CBM vs. conventional gas .......................................................................... 21

CBM development: worldwide .................................................................... 21

CBM development: India ............................................................................ 22

Technology: drilling and extraction ............................................................. 24

Cost and economics .................................................................................. 24

Key investment considerations .................................................................. 25

Outlook .................................................................................................... 26

3Shale gas and coal bed methanePotential sources of sustained energy in the future

BCM Billion Cubic Meters

BCF Billion Cubic Feet

BTU British Thermal Unit

CBM Coal Bed Methane

DGH Directorate General of Hydrocarbons

DOE US Department of Energy

EIA US Energy Information Administration

IEA International Energy Agency

GEECL Great Eastern Energy Corporation

MCF Thousand Cubic Feet

MoPNG Ministry of Petroleum and Natural Gas, Government of India

MMBTU Million Metric British thermal units

MMSCMD Million Standard Cubic Meter Per Day

NPC US National Petroleum Council

ONGC Oil and Natural Gas Corporation Ltd.

PGC Potential Gas Committee

PSC Public Service Commission

RIL Reliance Industries Ltd.

RPWR Reliance Power Ltd.

R&R Rehabilitation and Resettlement

TCM Trillion Cubic Meters

TCF Trillion Cubic Feet

TPWR Tripwire Inc

Abbreviation


Introduction�� Iran around 2000 BC as seeps from the ground were ignited by lightning, but it was not until 211 BC that the �� Chinese reaching a depth of 150 meters using bamboo poles and primitive percussion bits.

The use of natural gas has come a long way since then; global consumption in 2009 is estimated at 2,940 BCM, and has been growing at a CAGR of ~3.5% since 1965. Globally, proven natural gas reserves have grown steadily in the past decades to 187.5 TCM by the end 2009. About 4% of this is unconventional gas, of which more than half is in North America.

Although global production declined �� the US experienced the world’s largest increase in production for a third consecutive year driven by increased supply from unconventional gas sources. International Energy Agency (IEA) estimates world’s remaining gas resources to be 785 TCM, of which ~48% (380 TCM) is unconventional. Although unconventional gas production has been mainly restricted to the US, the global unconventional resources are expected to be abundant. However, it is not always feasible to correctly estimate unconventional resources.

In the last decade, the development of unconventional gas resources has ��

attributed by declining conventional gas reserves, increasing demand from developing countries such as India and China and improvements in technology for extraction.

The main differences between conventional and unconventional gas sources are the permeability of the gas and resource distribution. Conventional gas resources have high permeability and hence, are easier to extract as ��!��conventional resources are far less abundant compared to unconventional resources despite the fact that conventional resources are denser, i.e., contain more gas per km2.

Unconventional gas can be of the following types:


Shale gas: Shale gas is a natural gas produced from shale rock contained in shale formations and extracted by way of horizontal drilling and hydraulic fracturing. Currently, the largest producer of shale gas is the US. Other countries such as Australia, Canada, France, Germany, China and India are also in the process of developing their own shale resources. According to data from the US National Petroleum Council, the global shale gas resources were more than 16,000 TCF in 2007.

Coal bed methane (CBM): As the name implies, CBM is a gas contained in coal beds that are usually not commercially viable for mining. CBM is also referred to as Coal Seam Gas and is mainly produced in the US, Canada, Australia, India and China. Global CBM resources as per the US National Petroleum Council were estimated at ~9,000 TCF in 2007.

Figure 1: Conventional vs. unconventional gas

Conventional

Tight gas

Gas hydrates

Coalbed methane

Shale gas

High quality reservoirs

Low quality reservoirs

Volume

Unconventional

Higher concentrations

Easier to develop

More permeable

Larger volumes

More advancedtechnology needed

Source: EIA

6

Shale gasIntroductionWhat is Shale gas?Shale gas is a type of natural gas produced from shale. Shale is the earth’s most common sedimentary rock, and consists mainly of consolidated clay-sized particles. In most conventional oil �� seal that retains oil and gas in porous sandstone and carbonate or limestone reservoirs, preventing hydrocarbons from escaping to the surface. This “gas-cap” that accumulate over petroleum, has historically been the source of most commonly produced natural gas. But in other locations, layers of shale — sometimes hundreds of feet thick and covering millions of acres — are both the source and reservoir of natural gas. These shales are rich in organic carbon, and typically, the methane in organic shales was created in the rock itself over millions of years.

Though the shales may be as porous as other sedimentary reservoir rocks, their extremely small pore sizes make them relatively impermeable to gas ��occur. Although it has low permeability and releases gas very slowly, shale can hold an enormous amount of natural ��"��#�� the formations are so large that their wells will continue to produce gas at a steady rate for decades.


Figure 2: schematic geology of natural gas resources

Source:EIA

Figure 3: shale rocks

Source:EIA, energy techstocks

Brief history and background1

Shale formations across the U.S. have been developed to produce natural gas in small but continuous volumes since the earliest years of gas development. "�� $�'��was completed in 1821 in shallow *��+�� Fredonia, New York. These early supplies of natural gas were derived from shallow gas wells that were not complicated to drill and from natural gas seeps.

/�� <�� of shale gas from the Ohio Shale in the Big Sandy Field of Kentucky during the 1920s. However, it was not until the 1980s that development began to expand rapidly, with development of the natural gas resources in the area around Fort Worth, Texas.

Although shale gas has been produced for more than 100 years, shale gas production was not generally considered economically viable because of the low permeability and slow release of gas. Development of the Barnett Shale play grabbed the industry’s attention in 1990’s. More particularly in the recent years, steadily increasing natural gas prices, advances in hydraulic fracturing and new horizontal drilling technology have made shale gas a more viable source of energy.

Worldwide shale gas developmentWhile the initial wave of shale gas development has largely been a U.S. story, the wave is gathering international force and momentum. As per Schlumberger, shale deposits are located in 688 different shale resources in 142 separate basins around the world. Outside the U.S., the most developed shale resources are in Canada. While Europe and Australia has no shale gas production yet, exploratory projects are underway on a large scale. Further, it is estimated that China’s shale resources could rival those of the U.S. As per the U.S. National Petroleum Council (NPC) the global shale gas resources were more than 16,000 TCF in 2007, with more than 75% of that outside North America.

Table 1: World unconventional resource estimates, TCF

CBM Shale gas Tight gas Total

North America 3,017 3,842 1,371 8,228

Latin America 39 2,117 1,293 3,448

Western Europe 157 510 353 1,019

Central and Eastern Europe 118 39 78 235

Former Soviet Union 3,957 627 901 5,485

Middle East and North Africa 0 2,548 823 3,370

Sub-Saharan Africa 39 274 784 1,097

Centralled planned Asia and China 1,251 3,528 353 5,094

=��>/?@*J 470 2,313 705 3,487

/��Q��+=�� 0 314 549 862

South Asia 39 0 196 235

World total 9,051 16,112 7,406 32,560

Source: National Petroleum Council, 2007

1 “Modern Shale Gas Development in the U.S. A Primer, April 2009,” U.S. Department of Energy; “Shale Gas White Paper,” Schlumberger Inc.


The US'�� across much lower-48 states of the US.Each of these gas shale basins is different and each has its unique set of exploration criteria and operational challenges. The following graphic depicts the major US shale basins.

Figure 4: shale gas basins in the U.S.

Source: : U.S. Department of Energy, Modern Shale Gas Development in the U.S.: A Primer, April 2009

Proven US shale gas reserves at the end of 2008 were estimated by the US Department of Energy (DOE) at 32.8 TCF, a little more than 13% of the total US natural gas reserves of almost 245 TCF.2 Proved shale reserves should increase sharply when the 2009 data are reported,

given the changes in SEC reserves estimation and reporting that allow for more unconventional resources to be included as proven.

However, proven reserves of shale gas are thought to be relatively small in comparison to technically recoverable reserves. In the recent Potential Gas Committee (PGC3) report on US natural gas resources (June 2009), the total US gas resource base as of end 2008, was estimated at 1,836 TCF, with more than 616 TCF or 33% of the US total, accounted for by shale gas.4 The 2009 PGC estimates are more than 40% higher than their estimates two years ago. Further, different agencies estimate different shale gas recoverable reserves for the U.S., with EIA being the most conservative. Analysts have estimated that by 2011 most new reserves growth (50% to 60%) will come from unconventional shale gas reservoirs.

2 “U.S. Proved Reserves of Crude Oil, Natural Gas, and Natural Gas Liquids Annual Report 2008, November 2009,” U.S. Department of Energy.

3�"��=��X��@�� +��Z��[��

4 “Potential Gas Committee Report 2009,” Colorado School of Mines press release, 18 June 2009.


Figure 5: Shale gas resource estimate from different sources (2008)

84250.0%1,000

756

616

385274 20.0%

30.0%

40.0%

400

600

800

(tcf)

125

0.0%

10.0%

0

200

Navigant consulting

(max)

All consulting

(2008)

PGC 2008IC ICF Navigant consulting

(mean)

EIA-AEO 2008

Source: Analyst Research Reports

Total shale reserves (tcf) Percentage of total NG reserves (RHS)

US shale gas production in 2008 was estimated by DOE to be about 6 BCF per day (~2.2 TCF). In its latest long-term energy forecast, the DOE expects shale gas production to reach more than 12 BCF per day (~4.4 TCF) by 2020, and almost 17 BCF per day (~6.2 TCF) by 2035.5 The DOE production forecast is considered conservative, given the potential size of the shale resource base. For example, analysts at JP Morgan estimate US shale gas production to reach close to 25 BCF per day (~9.13 TCF) by 2015.6 Currently, it is estimated that ��+��of the total natural gas production in the US, which, by some estimates can go up to 26%–42% of the total domestic US production by 2015.

The following table summarizes some of the key characteristics of the major US shale basins. Notably, much of the key information on many of the basins is incomplete and/or under development. While the recent history of the shale gas industry has centered around the Barnett Shale play in Texas, the resource potentials of the Haynesville and Marcellus formations are considered many times larger.

Table 2: Key characteristics of major US Shale Basins

Major US shale gas formations

Formation Approx square miles

Approx vertical

depth (ft)

Approx thickness

(ft)

Approx gas in

place (tcf)

Approx recoverable

reserves (tcf)

Approx production

2008 (MMcf/d)

Barnett 5000 6500-8500 100-200 327 44 5000

Woodford 11000 6000-11000 120-220 23 11 200

Fayetteville 9000 1000-7000 20-200 52 42 650

Antrim 12000 600-2200 20-200 76 20 350

Haynesville 9000 >11000 200-300 717 35-251 60

Marcellus 95000 4000-8500 50-2000 1500 35-392 na

New Albany 43000 500-2000 50-100 160 19 na

Bakken na >10000 8-20 na na 75

Huron na 1000-7000 200-2000 na na 25

Baxter na >11000 na na na 10

Pierre na 2500-5000 na na na 2

Mancos na >13000 na na na 30

Eagleford na >11500 600-1000 na na na

Lewis/Mancos

10000 3000-6000 200-300 na 20 7

Source: Leon D. Brathwaite, Shale-Deposited Natural Gas: A Review of Potential, California Energy Commission Staff Paper, May 2009; and U.S. Department of Energy, Modern Shale Gas Development in the U.S.: A Primer, April 2009.

“Annual Energy Outlook to 2035, December 2009,” U.S. Department of Energy.

“Shale Gas – a Game Changer for Global Gas Markets,” J.P. Morgan, 9 February 2010, via Thomson Research.


Other countriesPotential opportunities and/or attractive geologies for shale gas include:

^� �Canada: Development is underway in western Alberta and British Columbia — particularly the Montney and Horn River plays; the eastern Utica shale play in Quebec is still in exploratory stages.

^� �Europe: Shale and other unconventional gas resources �� Q�� France, Germany, Hungary, Italy, Netherlands, Poland, Romania, Spain, Sweden, Switzerland, and the UK. Land acquisition and early-stage exploration is underway in a number of the countries.

^� �China: China’s shale resources could rival those of the US; ongoing discussions are being held with Shell and BP with regard to joint development.

^� �Others: Shale/unconventional gas �� in South Africa, Morocco, Russia and the Ukraine.

Shale gas development: IndiaIndia7 India has high natural gas prices, rapidly growing gas markets, increasing dependency on LNG imports, and a nascent coal bed methane industry. Thus, India appears to be a likely acolyte of the shale gas revolution.

India has extensive organic shale deposits across the gangetic plains, Rajasthan, Gujarat and other coastal areas. However, since systematic exploration is yet to commence, its prospectivity and questions about their �� mineralogical composition, or structural complexity is yet to be ascertained.

Since, shale gas presents a credible source of energy, which can contribute substantially to meet the energy requirements of India, the Government of India (GoI) is seriously looking at exploring shale gas potential.

Recently, in May 2010, the Ministry of Petroleum and Natural Gas signed

an in-principle agreement with the US Government to jointly cooperate for Shale gas exploration and production in India. Some aspects to be covered under the agreement include:

^� Assessment of economics, technologies and investment potential

^� `��{��|programs

^� }��'��X��

^� ` �� Z��potential shale gas areas

^� <�� be based on a case by case basis

The government, through the Directorate General of Hydrocarbons (DGH), is establishing policy guidelines for shale gas exploitation and auction of shale gas blocks within the next two years (expected in latter part of 2011), even as various E&P players are moving ahead with their pilot projects. ONGC has been implementing a pilot project in Damodar valley in partnership with Schlumberger at a capital cost of approximately USD28 million. Similarly, Oil India has initiated a project in Assam. While some players are trying to source

7 Research reports; Media articles via Infraline


shale gas technologies from foreign players, Reliance Industries has chosen to learn by working on live projects. RIL has signed joint venture (JV) agreements to invest over USD3.5 billion in three separate deals over the coming years to explore approximately 370,000 acres of shale in the US.

However, the project timelines, are not short. ONGC, which has been researching shale gas in India since 2006, is expected to spend the next two years gathering geological data ��*�� by drilling and resource estimation by 2013. In 2014, the company will be able to assess the feasibility and consider production from this pilot project.

Characteristics of some potential shale gas plays in India are as follows8 :

Cambay basin (Gujarat): Western India’s main onshore oil and gas producing region, the Cambay basin, is located in the country’s highly industrialized state of Gujarat. The lower Eocene Cambay Shale (Chhatral Member) has thick carbonaceous and sideritic shale inter-bedded with thin conventional sandstones pay zones. The Chhatral is dark grey and ��"/@��`��high porosity (11%–20%) and permeability (0.1–15.3 mD). However, the shale is thermally immature (Ro of 0.44%–0.55%), has high water saturation (35%–84%), and consists mostly of clay minerals (kaolinite, chlorite). The dry gas window for this basin is estimated at 4,000 m, but only a few wells have been drilled to this depth.

Assam basin in northeastern India is structurally broken up into several sub-basins with numerous faults. The Kajrahat Limestone is up to 600 m thick and comprises inter-bedded shale and limestone with 1%–3.9% TOC,

Types II and III kerogen, that is thermally mature (Roof more than 1.3%). Structural ��[�� !��

The Krishna Godavari basin is located in onshore and offshore eastern India. The Proterozoic Draksharama Shale has 1.2%–5% TOC and is thermally mature (Ro of 1.4%–2.0%). In addition, the much younger Cretaceous to Paleocene Raghavapurum and Chintalipalli Shales are rich organically (TOC 5%–9%) but thermally immature (Ro of 0.5%–1.0%).

Rajasthan basin in northwestern India is characterized by small faulted grabens. The Permian Karampur Shale averages 1.5% TOC, consisting of Type III kerogen, and is considered mature (Ro unavailable). The Cretaceous Parh Goru Pariwar Shale has 1%–10% TOC, Type II and III kerogen, and is mature in places (Ro of 0.5%–1.5%).

Figure 6: shale gas basins in India

Source: Advanced Resources International, Inc

8 “Shale gas revolution: Potential for a new energy paradigm,” CLSA report, 28 May 2010


Technological developmentsIn his book Basic Economics, Thomas Sowell, an economist at the Hoover Institution, pointed out that, “[how] much of any given natural resource is known to exist depends how much it costs to know.” 9 Notably, in the case of shale gas, technological breakthroughs in the natural gas industry have driven down the “costs to know” and have thus enabled development.

The key elements in the emergence of shale gas development and production ��horizontal drilling and hydraulic fracturing technologies. These two processes have allowed shale gas development to move into areas, which previously would have been inaccessible and uneconomic.

Horizontal drilling10

The most recent and most important advances in drilling technology is the ability to direct the drill bit beyond the region immediately beneath the drill rig. Horizontal drilling provides more exposure to a formation than does a vertical well. In the case of thin or inclined shale formations, a long horizontal well increases the length of the well bore in the gas-bearing formation and therefore, ��into the well. This increase in reservoir exposure creates a number of advantages over vertical well drilling. Six to eight horizontal wells drilled from only one well pad can access the same reservoir volume ��[��$��

�� pipeline routes, and production facilities required.

Advances in horizontal drilling can be evidenced from the fact that as recently as the late 1990s, only 40 drilling rigs (6% of total active rigs in the US) in the US were capable of onshore horizontal drilling; the number has now grown to approximately 519 rigs (28% of total active rigs in the US) by May 2008.11

Figure 7: conventional vs. un-conventional drilling

Source: Advanced Resources International, Inc

Un-conventional Conventional

Hydraulic fracturing12 Another technology used for the economic recovery of shale gas, and indeed, the more controversial one, is hydraulic fracturing, which involves the pumping of a fracturing �� #�� #��"��economic quantities.

Despite their abundant natural gas content, shales do not produce gas freely. Economic �� the gas. Typical “frac” treatments or “frac jobs,” as they are commonly referred to, are relatively large operations compared to most drilling operations.

Fracturing involves isolating sections of the well in the producing zone, and then �� >�� #�open) down the wellbore through perforations in the casing and out into the shale. The �� #��as much as 3,000 ft in each direction from the wellbore.

9 Thomas Sowell, Basic Economics: A Common Sense Guide to the Economy, Basic Books, 2007.

10 “Unconventional Gas Shales: Development, Technology, and Policy Issues, October 2009,” Congressional Research Service; “Modern Shale Gas Development in the U.S.: A Primer, April 2009,” U.S. Department of Energy; “Shale Gas White Paper,” Schlumberger Inc.

11“EIA. 2008. Is U.S. Natural Gas Production Increasing?” 11 June 2008, U.S.Department of energy, the US government website, http://tonto.eia.doe.gov/energy_in_brief/natural_gas_production.cfm.

12 “Unconventional Gas Shales: Development, Technology, and Policy Issues, October 2009,” Congressional Research Service; “Modern Shale Gas Development in the U.S. A Primer, April 2009,” U.S. Department of Energy; “Shale Gas White Paper,” Schlumberger Inc.


Cost and economics@�� shale gas will vary widely across regions and companies. Back in 2007, major companies in the US exploring shale gas used a price of USD6–8 per million BTUs for gas wells to break-even. But �� advent of new technology. A review of estimates by analysts from investment houses shows that average break-even costs today, including a 10% return, are typically USD4–6 per million BTUs. Shale costs in the Marcellus were generally seen as the lowest, averaging USD3.50–4.00 per million BTUs, with core Barnett shale and Fayetteville shale costs averaging USD4.00–4.50 per million BTUs, and Woodford shale costs a bit higher at USD5.00–5.50 per million BTUs. In contrast, new Rocky Mountain unconventional gas costs were estimated in the USD4.50–5.00 per million BTU range, with new conventional mid-continent gas at USD6.00–6.50 per million BTUs, and new conventional Gulf of Mexico shelf gas at USD7.00–7.50 per million BTU.13

Horizontal wells are generally two to three times more expensive than typical vertical wells, but for most shale plays, the expected ultimate recovery of gas is two to six times higher.14 Being closer to the major East Coast natural gas markets, Marcellus gas also enjoys a big basis differential/premium to the spot Henry Hub price (~15%–20%), in contrast to core Barnett shale gas, which typically trades at a 10%–15% discount to the spot price.

Figure 8: Breakeven analysis of major US shale gas plays

4 0 4.3

6.2 6.4

5.6

7.0

3.3 3.4 3.6 3.7 . 4.3

0.0

1.4

2.8

4.2

(USD

)

Mar

cellu

s

Low

er H

uron

Hay

nesv

ille

Barn

ett

Faye

ttev

ille

Barn

ett T

ier 2

Eagl

e Fo

rd

Woo

dfor

d

Pear

sall

Breakeven Gas Prices (USD/mmbtu)

Source: Scotia Waterous

12 “Unconventional Gas Shales: Development, Technology, and Policy Issues, October 2009,” Congressional Research Service; “Modern Shale Gas Development in the U.S.: A Primer, April 2009,” U.S. Department of Energy; “Shale Gas White Paper,” Schlumberger Inc.

13 “In Shale We Trust,” Scotia Capital, January 2010, via Thomson Research.


Risks and challengesDespite the relatively strong economics of shale gas development, it is not without some clear risks and challenges. There is less geological risk for shale compared to conventional gas, and technological advances have substantially reduced the economic risks. Larger residual risks are environmental in nature.

Environmental risks �� Surface disturbances: Surface

preparation issues related to noise, lighting, dust, and construction �� to wildlife habitat and wilderness preservation makes shale gas development challenging, particularly near existing communities

�� Groundwater protection/contamination and life cycle water/waste management:�"��hydraulic fracture operations used in horizontal wells may require 3 to 4 million gallons of water per well. Ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers. Once the fracture treatment is completed, most of the fracture water, along with the chemicals that facilitate both the suspension of the proppant and the lubrication of the conveying medium, comes back to the surface and must be managed in a way that conserves and protects water resources.

�� Greenhouse gas emissions: Although natural gas offers a number of ��sources of energy, particularly other fossil fuels, some air emissions commonly occur during exploration and production activities. Emissions may include NOx, volatile organic compounds, particulate matter, SO2, and methane. On a per million BTU basis, total emissions from natural gas produced from shale formations differ little from that of natural gas from conventional sources.

�� NORM: An additional consideration in shale gas development is the potential for low levels of naturally occurring radioactive material (NORM) that is brought to the surface in the rock pieces of the drill cuttings, remains in solution with produced water, or, under certain conditions, precipitates out in scales or sludges.


OutlookConsolidation"��{�� $'�� been the large and medium-sized independent E&P companies. While “late-for-the-party,” the majors are now taking an increasing interest in shale gas, both in the US and particularly in Europe. ExxonMobil has moved aggressively by acquiring one of the US “shale majors,” XTO; StatoilHydro has moved aggressively into the Marcellus with its JV with Chesapeake, and French Total SA has substantially increased its North American presence with its Barnett Shale JV with Chesapeake. BP, Eni, and BG are also building North American shale positions through asset acquisitions.

A European “land-grab” could swallow-up many of the smaller companies with local and regional shale positions. The Chinese national oil companies are keen to develop their huge shale resources, and are turning to the international majors for assistance.

Table 3: recent shale gas deals in the US

Buyer Seller Year Shale play Stake acquired

Gross potential (in tcf)

Gross acreage (‘000 acres)

Deal value (USD mn)

USD/acre

USD mn/bcf

BP Chesapeake 2008 Fayetteville 25% NA 540 1900 14074 NA

Exxon XTO 2009 Barnett 100% 14 1360 6970 5125 0.5

Total SA Chesapeake 2010 Barnett 25% 9 270 2250 33333 0.97

BP Lewis Energy 2010 Eagleford 50% NA 80 160 4000 NA

RIL Pioneer Resources 2010 Eagleford 45% 10 263 1315 11111 0.29

Chesapeake Statoil 2008 Marcellus 33% 16 1800 3375 5769 0.65

XTO Linn Energy 2008 Marcellus 100% NA 152 600 3947 NA

Ultra Petroleum Corp.

Private Company 2009 Marcellus 100% NA 80 400 5000 NA

Consol Energy Dominion res. 2010 Marcellus 100% 20 1460 3475 2380 0.17

Mitsui Anadarko (JV) 2010 Marcellus 33% NA 307.7 1400 14000 NA

EQT Corp. Private Operators 2010 Marcellus 100% NA 58 280 4828 NA

Chesapeake Epsilon Energy 2010 Marcellus 100% 3.5 11.5 200 17391 0.06

RIL Atlas Energy 2010 Marcellus 40% 13.4 300 1700 14167 0.32

BG Group Exco Resources 2010 Marcellus 50% 2.4 654 950 2905 0.79

Shell East Resources 2010 Marcellus 100% 16 1050 4700 4476 0.29

Source: Research Reports


Natural gas balancesThe medium-to-long-term view of the US supply/demand dynamic for natural gas has shifted dramatically in the last ��?[�� has been reduced, while domestic production expectations have been raised, particularly from shale and other unconventional sources, with a net result of a substantially lower implied need for LNG imports, affecting Atlantic Basin LNG trade. Additionally, with the continued de-coupling of oil and gas prices, there will also be increasing pressure on any oil-indexed gas prices.

Adding to the pressures, there has been strong growth in global LNG liquefaction capacity. Almost 6 BCF per day ( approximately 2.2 TCF) of new liquefaction capacity was added in 2009, and another 5.7 BCF per day (approximately 2 TCF) is due on-line by 2012.15 Further, LNG liquefaction capacity of major exporters to the US remained under utilized in 2009.

Russia stands to be particularly challenged by the shale boom. The strong mid-to-long term market for LNG imports into North America is greatly diminished, and Russia’s strategic gas focus is now likely to shift from “west” to “east.”

Global gas demand forecasts are the greatest unknowns. The baseline forecast from the International Energy Agency (IEA) at 1.5% per year growth through 203016 is seen as quite “conservative” and alternative growth projections range as much as several times higher. As would be expected, gas demand growth in China, India and other Asia is the principal wildcard, but so too is the uncertainty that surrounds the degree of global commitment to natural gas as �� carbon reduction strategy/agreement.

The global gas battleground is still likely to be Asia, with increasing LNG supply capabilities into the region, both from the Middle East as well Southeast Asia and Australia, along with increasing pipeline capacity into Asia, from both the Caspian region and Russia. But long-term growth in shale gas should play an important role not just in North America, but in Europe and Asia as well.

“Oil & Gas Exploration & Production,” Credit Suisse, 12 February 2010

“World Energy Outlook 2009, November 2009, ” International Energy Agency,


Coal bed methane

IntroductionTrapped in the middle of coal is an unconventional natural gas whose vast untapped resource is still at a very nascent stage. After a couple of outbursts and explosions of methane gas �� quick to acknowledge that this gas could be used as fuel and so coal bed methane (CBM) was born. With abundant coal reserves around the globe, coupled with depletion of the conventional source of energy such as fossil fuels, CBM offers a ��+growing energy demand.

CBM is naturally occurring methane (CH4) gas with traces of other hydrocarbons and non-hydrocarbons, generated by chemical or bacterial reactions in the coal matrix. This process ��#�� methane is effectively ”adsorbed” in a coal reservoir. Though the permeability of a coal seam is low compared to that of a conventional gas reservoir, it can �� conventional sandstone reservoir.

Coal seams have dual porosity system comprising micro and macro-pores (as indicated in Figure 1). While the micro-pores exist in the matrix, the macro-pores are made up of a system of natural fractures called cleats. There are two kinds of cleats: Face cleats, which are parallel to the coal seam and are continuous, and butt cleats, which are discontinuous and perpendicular to the coal seam. These fractures are the target points during drilling. Methane gas, which has been adsorbed onto the internal coal surface, requires a pressure drop to be evacuated. The pressure drop is provided by dewatering. When the pressure is brought down below threshold value the gas starts to undergo desorption and hence the methane gas can be collected.

Figure 1: Coal has a dual porosity system

Source: Reservoir Engineering for Geologists

Matrix

Fracture

MatrixButt cleats

Face cleats


CBM vs. conventional gasCBM offers a lot of upsides as well as downsides just like any other natural resource. One such downside is that the estimation of recoverable volumes in the evaluation of CBM project is hard to determine. The production of the CBM wells is about 100–500 Mcf/day, which is lesser than a conventional gas well. This means CBM drilling is likely to require multiple low producing wells. In certain CBM projects, after hydraulic fracturing, the quality and quantity of groundwater ��excess groundwater released during the dewatering process in a way that is environmentally acceptable, increases the operational expenditure substantially. Producing CBM is as much a water management program as it is an energy program. Considering that CBM projects are onshore they have a tendency to require locals to vacate the area and settlements for them have to be provided.

Figure 2: CBM vs conventional gas projects

Source: Gaffney, Cline & Associates

CBM development: worldwideThe global estimate for potential CBM production is expected to be more than 7,000 TCF. The countries that are �� @��are Australia, Canada, the US and a few western European countries. Close to 10% of the natural gas produced in the US is contributed by CBM. India, Japan and China have a great potential for new CBM explorations. China and Indonesia boast of a high CBM reserve estimate but their production is still very low as most projects are still in exploration and estimation stages due to absence of a formal licensing round process. Indonesia offered the 1st round of CBM bidding in 2009 and awarded 10 blocks to different companies. Russia has a vast amount of unchartered CBM resource and reserve (as seen in Table 1) and is currently entering CBM ��@��production facility in the Taldinskoye �� '��

Table 1: CBM and coal resources across the Globe

Country Coal resources (billion tons)

CBM resource (TCF)

Canada 7,000 229–2,697

Russia 6,500 469–2,598

China 4,000 579–1,200

US 3,970 449 –900

Australia 1,700 310–510

India 495 49.4–91.8

Germany 320 60.1–88.3

Indonesia 17 3.5–7.1

Source: DGH India presentation


CBM development: IndiaThe growing Indian economy requires �� and sustain growth, thereby leading to increased demand for gas. Due to the high pricing of LNG and fossil fuels, India has resorted to developing resources that are unconventional such as CBM. The total gas demand (including latent demand) has risen from 179 MMSCMD in FY08 to 197 MMSCMD in FY09 and ~ 225 MMSCMD in FY10 while the supply is currently expected to be ~170 ��'@�*��Q�� [�� widen with the ever increasing demand, it is critical for the country to ensure alternate sources of gas such as CBM are developed to their full potential.

Figure 3: CBM production in India


0

1

2

3

4

5

6

7

8

2007-08 2008-09 2009-10 2010 -11 2011-12 2012-13

0.21.1

2.2

3.7

5.4

7.4

India being the third-largest producer of coal has reserve estimation of 248 billion tons. The CBM reserve estimation, from these coal reserves is in excess of 60 TCF covered over 36 blocks.17 As can be seen in Figure 3, in 2007, DGH had estimated that CBM production in 2010 is likely to be approximately 2.29 MMSCMD. However, the current production is only 0.14 ��'@�*��than the DGH estimates. This indicates that a production forecast of 7.4 MMSCMD in 2013, as predicted by DGH, is actually optimistic in nature. But even so, the production forecast of 7.4 MMSCMD is still well below the expected production potential of the country at 38 MMSCMD.

The main areas where CBM can be found in India are Jharkhand (six blocks), West Bengal (four blocks), Madhya Pradesh >��#J��}�{��>��#J��

Chhattisgarh (three blocks), Andhra Pradesh (two blocks), Maharashtra (1 block) and Gujarat (1 block).18

In 1997, the GoI formulated the CBM policy*. The key terms were as follows:

^� ��#�� open international competitive bidding system.

^� �"��X�`� ��participating interest.

^� �� bonus.

^� Exemption from customs duty and imports for CBM operations.

^� Walkout option at the end of Phase I (exploration program) and II (development and production program).

^� Freedom to sell gas in the domestic market.

^� �=��

^� Seven-year tax holiday.

17 “Oil and gas,” Nomura Financial Advisory, 11 May 2010, via Thomson Research.

18 “Developments in India-CMM/CBM,” Essar Exploration and Production Ltd, March 2010 via Thomson Research.

* Subsequent changes in tax law may impact the provisions of the CBM policy.


1997

1993

1995

1997

1997

1998

2000-09

Evaluation of CBM basins, pilot studies

by ONGC

Well in Jharia tested successfull

R&D well drilled in Raniganj and

Mehsana

CBM policy formulated

MoU signed between MoP&G

and MoC

Model contract drafted

CBM bidding initiated, 4

rounds conducted

The Ministry of Petroleum & Natural Gas offered the blocks for exploration in four rounds as shown in Table 2. The blocks were offered on the basis of open, �� '�[�`� ��in a total of 16 bids for the seven blocks �� @��+`��were awarded. CBM-II, in 2003, attracted �� >��`� �� foreign company) for the 9 blocks offered out of which8 blocks were awarded. The 10 blocks in CBM-III, in 2006, attracted

54 bids from 26 companies and all the blocks were awarded. Under the CBM IV Licensing Round, 26 bids were received for 8 out of the 10 blocks on offer. Out of these 8 blocks, 7 blocks received multiple bids and a single bid was received for 1 block. A total of 19 companies, comprising three foreign companies and 16 domestic companies, participated in this round.

Table 2: rounds for CBM bidding in India

Round Blocks Resource (TCF)

Nomination 3 5.8

Round I 5 8.3

Round II 8 15.1

Round III 10 22.4

Round IV 10 13.5


According to the terms of the exploration license and PSC, all companies involved will have to pay a royalty of 10% ad-valorem sale value at the well-head on the production of CBM to the particular state government. In addition a monthly production level payment (PLP) on CBM produced and saved in accordance with the provisions outlined in the PSC, will be payable. Table 2 provides the resource potential of the blocks awarded during each of the above four rounds.

"�� @��was started at Raniganj by GEECL, with a production of 0.11 MMSCMD in June 2007. As observed in Figure 4, ONGC has the largest CBM production potential according to resource base, followed by Arrow Energy and Reliance Industries. Large opportunities do exist in the CBM space, because it is an onshore resource, which can provide quick access to customers in the “no gas” regions and has a lower Capex/Boe requirement as compared to other unconventional gas source such as shale gas. Also, the production was initially spurred by tax incentives. However, it is currently at its infancy due to lack of connectivity through pipelines to evacuate the gas and under developed gas markets.19

19 “The Global Utilities Specialist,” Macquarie Equities Research, July 2010 via Thomson Research


Technology: drilling and extractionThe drilling for CBM is an atypical procedure than that followed for conventional gas drilling. A well is drilled at 1,000–1,500 ft (not as deep as a conventional reserve, which is at 3,000ft). A casing is placed inside (as seen in Figure 5) the newly drilled hole of the bore well. Highly pressurized water, #�� coal seam causing the coal to fracture. "�� pumped to the surface using a pumpjack by a process known as dewatering. The pressure on the trapped methane gas is then released (desorption). Methane �� is collected and put into a system of underground piping. The pumped out water is either treated or evaporated (not recommended) or re-injected.20 Treated water can be obtained by reverse osmosis or pH adjustment and can be distributed to various industries.

Figure 5: pumping methane gas from a coalbed

Source: U.S geological survey

Cost and economicsCBM Drilling and well development is an ongoing process in order to maintain a steady state of production to deliver constant supply contracts. For example, the Power River Basin in the US had 848 wells at the end of 1999, which increased to 16,000 wells by the end of 2005 (~2,500 well increase per annum) with shallow depths to a maximum of around 500 m. An estimated 3,000 wells were drilled in 2006. These wells take less than a week to drill and complete and cost around USD100,000 per well. Thus, CBM projects are quite capital intensive in nature.

The operating expenditure of a CBM project is USD0.5/MMBTU. Along with �� total cost for extraction of CBM from its reservoir up to USD1.5-2/MMBTU.21

Table 3: prices of alternative fuel sources

Fuel USD/MMBTU

Fuel Oil 15.3

Light Diesel Oil 18.8

LPG 18.8

Gasoline 31.2

Diesel 22.4

Source: GEEC, IOC, BPCL

Table 4: prices of unconventional fuel sources

Unconventional fuel

Average min price (in USD/MMBTU)

CBM 5

Shale gas 6

Tight gas 11.5

Bio-fuels 6.29

Source: Morgan Stanley report, Institute of Defense studies

It is critical to assess the prices of alternate fuels, to assess the viability of substitution by CBM. Table 3 provides the current prices of liquid fuels in equivalent energy terms. While natural gas from conventional sources is priced at approximately USD4 per MMBTU, the long-term price estimate for CBM is USD5 per MMBTU. Comparing the same with the Table 3, the price for the ��than that of CBM. In addition, when CBM is compared to other unconventional gases such as tight gas, shale gas and gas hydrates, it offers a very competitive pricing point as indicated in Table 4. Although, CBM is more expensive than conventional natural gas, it is still very competitive when compared to other liquid fuels. This offers an economic advantage to both the suppliers and the consumers for a switch over to CBM from alternate fuels.

The pricing of CBM at a global level also differs due to various geographical factors. In Australia CBM is for USD4–6/MMBTU and in China USD5–7/MMBTU. The difference is attributable to the methodology for production, its distribution aspects and the stage of development of the project.

20 “CBM sector Overview,” FD Capital, 2007 via Thomson Research

21 “CBM sector Overview,” FD Capital, 2007 via Thomson Research


Key investment considerationsCBM projects are characterized by an initial low capital expenditure to establish production but relatively higher and continuous expenditure as development drilling is undertaken to progressively add production. Just like coal production �� and technical factors, there are a few important characteristics, which determine suitability of CBM production.

Reserve quality: Large amounts of recoverable gas trapped in the coal seam are the basic criteria for a CBM project to be economically viable. This typically requires coal seams that are a minimum of 20 feet thick. Viability of a project also depends on the rank of coal, which should be 77%–87% of carbon typically found in sub-bituminous coal. CBM exists only in areas where the dominant chemistry of the water in the coal seam is sodium bicarbonate and where the coal seam is buried deeply ��pressure to hold the gas in place.

Land acquisitions: CBM projects are located on shore and require local inhabitants to vacate the location or drilling site. Huge compensations have to be paid to acquire the land from the land owners. In addition, rehabilitation and resettlement (R&R) issues may also lead to several delays before a CBM project can take off.

Resource estimation: A coal seam is said to be a favorable reserve if it produced 50–70 cubic feet/ton of coal. The resource estimation is generally �� @��{��Many wells are needed to describe a CBM resource as it is relatively more heterogeneous and extensive than a conventional gas reserve.

Permeability: Coal beds are generally characterized as water-saturated gas reservoirs with low permeability through natural fractures and dual porosity. They also vary widely from basin to basin and can be highly heterogeneous within the same basin. Drilling, cementing, perforation, and �� for each situation to maintain reservoir performance. All this invariably increases the operational cost.

Environmental impacts: Water treatment is an important issue for many stakeholder groups in the CBM industry. Due to dewatering, the groundwater becomes polluted, cloudy and decreases in content drastically. As the quality of water is low, it cannot be disposed of or used in irrigation or for human consumption. Water is part of the fabric of a geologic formation. It holds the rock open. When water is removed from the rock, the pore spaces are left open, and the rock can collapse. This is known as compaction or subsidence. There is also a high possibility of spontaneous combustion of dewatered coal beds due to the reaction of the coal with atmospheric oxygen.

26

OutlookCBM development in India is moving slowly yet progressively. In many ways CBM in India is similar to the coal industry. The impediment to CBM development in India is acquisition of land, a lengthy modus operandi for environmental approvals due to CBM production displacing large volumes of ��`�� investments in gas pipeline infrastructure is critical for the evacuation of CBM Gas.

The increasing number of successful and viable CBM projects established globally gives investors a positive outlook on CBM. The CBM industry is still evolving in some countries such as China and Indonesia where structured policies in CBM are yet

to materialize. In Australia, gas projects are typically underpinned by a long-term gas sales agreement, which does not provide an immediate, untapped, market for CBM. This is not the case in the US as ready gas markets are available due to an established history of CBM production.

CBM looks ready to play a vital role in the energy sector. The challenge it poses is the need to convert this huge resource into reserves through developing innovative technology and feasible techniques for commercial development.

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EYIN1011-125 Shale gas and coal bed methane.indd (India).

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