Unconventional Oil & Gas - 2011 Annual Review

For analysis and commentary on these and other stories, plus the latest unconventional developments, see inside…

Copyright © 2012 NewsBase Ltd.

www.newsbase.com Edited by Ryan Stevenson All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All

reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents

January 2012

� News � Analysis

� Intelligence Published by

� NewsBase

JANUARY 2

� Spotlight shines on UK’s unconventional

gas 2

FEBRUARY 3

� Reflections on a decade of shale 3

MARCH 5

� Haynesville claims pole position 5

APRIL 7

� New acreage awards boost Indonesia’s

CBM sector 7

MAY 9

� Fractious fracking debate explodes in

wake of Pennsylvania blowout 9

JUNE 10

� Shale investments continue in North

American gas island 10

JULY 12

� The Franco fracking furore 12

AUGUST 14

� Shale offers North Africa alternatives 14

SEPTEMBER 15

� Chesapeake upbeat about Utica 15

OCTOBER 17

� UCG potential could match shale gas 17

NOVEMBER 19

� Moving GTL into the oil business 19

DECEMBER 21

� Argentina ready to reap rewards of its

unconventional potential 21

THE YEAR IN REVIEW

Fracking furore The controversy surrounding hydraulic fracturing (fracking) showed little sign of abating in 2011, which had a significant effect on potential shale gas production in Europe.

� France’s decision to ban fracking has had a major impact on companies that are exploring shale deposits in the country and the wider unconventional oil and gas industry. (Page 12)

� Developments in France were watched closely by the UK government as it assessed the best way forward for its own shale gas industry. (Page 2)

� Meanwhile, the debate about fracking in the US intensified after a blowout at one of Chesapeake Energy’s shale gas wells in Pennsylvania. (Page 9)

� Chesapeake remained a major player in the US unconventional energy sector last year, with the company claiming it had so far spent US$2 billion on its acreage in the Utica shale. (Page 15)

� Chesapeake’s CEO believes oil and gas reserves in the Utica shale could be worth US$500bn and has urged speedy development of the formation. (Page 15)

� Another shale play that is developing rapidly is the Haynesville, which a report claimed had overtaken the Barnett as the largest producing natural gas shale formation in the US. (Page 5)

UOGM 2011 Annual Review

UOGM 2011 Annual Review page 2




Debate is intensifying over the potential for unconventional gas extraction in the UK as the country’s first shale gas well continues to make progress in Lancashire.

According to Lord Browne, the former CEO of BP, who has a significant interest in the project, the UK “is in a strong position to benefit from potential growth in the unconventional gas.” But figures who oppose the embryonic industry have emerged in recent weeks, the latest being shadow energy minister, Huw Irranca-Davies, who has called for a temporary ban on shale gas and coal-bed methane (CBM) exploration.

Shale gas production in the US has grown dramatically in the last decade, almost tripling between 2007 and 2009 owing to improved exploration techniques. These have helped to turn the US gas industry on its head, flipping the global gas market from under-supply to over-supply.

However, the prospect of thousands of new hydro fracturing drilling sites being established in the coming decades has spurred environmental opposition to unconventionals in the US, with most concerns linked to the potential contamination of drinking water.

UK debut By contrast the technique is relatively new to the UK, where private company Cuadrilla Resources, founded in 2002, recently completed the first exploratory drilling by sinking a test well in the onshore part of the East Irish Sea Basin

in land near Kirkham more than 9,000 feet (2,743m) down into the so-called Bowland shale, which runs from Clitheroe to Blackpool in Lancashire.

The well is due to start extracting gas soon, and Cuadrilla has described it as the “first true shale gas” find in Europe, noting that preliminary drilling had confirmed and “possibly exceeded” its expectations. The firm counts among its backers a group of energy-focused private equity funds managed by Riverstone, which is reported to hold a 36% stake in the company. Lord Browne, who is now managing director of Riverstone Holdings’ European portfolio, and a board member at Cuadrilla, recently said: “Unconventional gas is proving to be a game changer in the oil and gas industry.” His comments are helping to promote an unconventional gas conference being held in Aberdeen in early March, but will likely do little to placate the environmentalist lobby now emerging within the UK. The topic of unconventional gas has recently been pushed far higher up the UK agenda,

after the publication in mid-January of a report from the Tyndall Centre for Climate Change, which argued that no shale work should take place in the UK until the end of 2012, when a US Environmental Protection Agency report into the topic will produce its first results.

UK prospects The UK is one of a number of European markets that have sprung to prominence as potential shale gas plays, and one where public awareness, has, until recently, been low. In addition to Lancashire, possible plays in the UK that have been mentioned in this context include Surrey, Kent, Hampshire, Cheshire and Nottinghamshire. However, experts have said that the UK’s reserves of shale gas are unlikely to change the landscape of the market in an identical manner to the effect of the gas discoveries in the US, where the shale basins are much larger. Although accurate data are still lacking, petroleum geologist Nigel Smith at the British Geological Survey (BGS) said in March 2010 that the UK’s shale gas might only increase onshore production by 12%, or 11.64 million cubic metres per year, a fraction of the UK’s total 73.4 bcm gas output in 2008. The report from the Tyndall Centre, as well as pointing out the environmental impact associated with fracking techniques, drew attention to the lack of publicly available information on its safety and stressed that more research was needed.�

JANUARY

Spotlight shines on UK’s

unconventional gas As the UK’s unconventional gas industry gathers momentum questions are being raised about its environmental impact and sustainability By Kevin Godier � Cuadrilla Resources is advancing its shale gas oper ations in north-west England � Environmentalists are advocating close scrutiny of fracking and a possible moratorium on drilling � The government would find it difficult to ignore a new domestic energy source with gas imports rising

With the UK expected to have to import 80% of its gas supplies by 2020, an opportunity to tap into

fresh domestic resources may yet prove to be an irresistible opportunity





It also predicted that gas drilling in Lancashire would give rise to a range of local concerns, including noise pollution, high levels of truck movements and land-use demands. The report was funded by the Co-operative, which offers green investment funds and is campaigning against the expansion of ‘toxic fuels’ such as crude from Canada’s oil sands.

Kevin Anderson, a professor of energy and climate change at the Tyndall Centre at Manchester University, who authored the report, has contended that the shale gas should be left in the ground.

“In an energy-hungry world any new fossil fuel resource will only lead to additional carbon emissions. In the case of shale gas there is also a significant risk its use will delay the introduction of renewable energy alternatives,” he said.

The report’s launch also coincided with a visit to the UK by Josh Fox, director of the Oscar-nominated anti-shale gas documentary Gasland, which investigates the effects of shale drilling on local communities.

The UK’s official governmental reaction has to date been cautious. Acknowledging that it is aware of reports from the US of environmental and health issues linked to some shale gas projects, a letter from the Department of Energy and Climate Change quoted by The Guardian newspaper in mid-January said: “We understand that these are only in a few cases and that, when carried out correctly, shale gas exploration and development does not pose a threat to

aquifers or local communities.”

Caudrilla response Cuadrilla has rejected the call by Irranca-Davies, who revealed on January 27 that he had written to UK Minister of State for Energy Charles Hendry urging a moratorium and to “properly explore the full implications of shale gas and CBM for the UK” while environmental concerns over hydro-fracking techniques were studied. This would prevent ministers being “caught napping” by a surge of applications from companies looking to exploit shale gas reserves, he said, in comments that will inevitably place fresh pressure on Westminster to address the growing controversy surrounding fracking.

“The government must assure itself and the wider public that fracking and the associated processes used for extraction of gas from shale or CBM are safe for use in the UK,” Irranca-Davies added. “Ministers cannot turn a blind eye and sacrifice our natural environment, or compromise on our climate change targets.”

Cuadrilla responded on January 27 with a statement that said it had around 200 years of cumulative experience in its team, including drilling and/or fracture stimulation of more than 3,000 wells, mainly in the US. “The potential risks associated with shale gas exploration are not unique and are common to all hydrocarbon exploration,” it stressed. “Shale gas exploration techniques,

including directional drilling and fracking, are conventional and have been used across the wider oil and gas industry (including previously in the UK) for many decades.”

The company defended the composition of its fracking fluid, which includes a biocide used at a low concentration, and said that it had submitted evidence to a House of Commons energy committee’s inquiry into shale gas.

It additionally contended that the new industry could offer a “triple win” for UK citizens: by helping to ensure energy security through new domestic energy supplies; by lowering the cost and price volatility of energy to consumers and by reducing greenhouse gas emissions by replacing coal as a power station feedstock.

Cuadrilla made an earlier statement on January 17 seeking to reassure Lancashire residents and environmentalists that its processes were safe. “We are doing this by the book,” said its CEO, Mark Miller, before adding: “We are using the best technology the industry has.”

With the UK expected to have to import 80% of its gas supplies by 2020, an opportunity to tap into fresh domestic resources may yet prove to be an irresistible opportunity despite the building clamour from the environmental lobby.�

After 10 years of development, shale gas has the potential to impact global energy markets dramatically. But commercial

development of that potential will focus on North America, and the US in particular, for the next decade, according

to Global Shale Gas Technologies and Markets.�

JANUARY

FEBRUARY

Reflections on a decade of shale A new report analyses the impact of shale gas on the global gas market and highlights the long-term opportunities that exist in the unconventional energy sector By Jim Brumm





Noting that demand for natural gas was expected to continue to increase, the SBI Energy report projected it would account for nearly 24% of global energy supplies by 2020. That compares with the less than 23% of global energy demand met by gas in 2010, noted Shannon Shuflat, an SBI Energy analyst and co-author of the report.

“The confluence of growing natural gas demand and breakthroughs in technological advancements has made investments in shale plays attractive in recent years,” said the report’s co-author Akash Shah. “Advancements in horizontal drilling and hydraulic fracturing technologies have enabled the achievement of high rates of gas production from deep, low-permeability shale formations. These breakthroughs have facilitated access to some of the largest undeveloped gas resources in the world,” Shah explained. Estimating the shale gas resource base at 18,775 trillion cubic feet (531.7 trillion cubic metres), the report said the resource potential of shale gas exceeded that of conventional global resources. Noting that world natural gas consumption in 2010 is estimated at 112 tcf (3.17 tcm), the SBI analysts point out that even if only 25% of the total shale resource base becomes technically recoverable, shale gas alone can meet natural gas demand for over 40 years at current consumption levels.

In North America, reserves that can be economically recovered using current technologies total over 3,700 tcf (104.8

tcm) – enough resource for almost 140 years at current levels of consumption, according to ICF International’s vice-president of gas market modelling, Kevin Petak. Over 50% of the assumed resource is shale gas, he noted.

So far, shale gas production is predominantly limited to North America, with the US accounting for the vast majority of historic and current production. As a percentage of total North American gas production, shale gas has climbed from virtually nothing in 2000 to 13% in 2009, enabling the US to eclipse Russia as the world’s leading producer of natural gas, the SBI report said. Production in Canada, as yet the only other nation extracting shale gas in commercial quantities, has grown from about 5 billion cubic feet (141.6 million cubic metres) in 2006 to 172 bcf (4.9 bcm) in 2010, accounting for 3.5% of current global output.

Commercial production in Canada currently comes from shale gas wells in the Montney and Horn River shale plays, while the majority of US production is derived from the Barnett, Haynesville, Antrim, Woodford and Marcellus shales. The successes in the North American shales, particularly in the US, have piqued the attention of governments and gas companies alike around the world, the SBI report said.

Noting several countries around the world hold prime targets for shale gas exploration, it said significant gas shale resources had been identified in Poland,

Sweden and Austria. A number of gas shale basins have also been identified in Australia, China, India and southern African nations.

By 2015, the report said, commercial shale gas production is likely to be occurring in Poland, China and India, whilst many other countries will have advanced exploration and development efforts under way.

Global shale gas production volume is expected to grow by 10.8% per year from 5.04 tcf (142.7 bcm) in 2010 to 8.44 tcf (239 bcm) in 2015.

The vast majority of the increase in output is expected to come from North America, with US and Canadian production rises accounting for over 96% of global growth during the period.

While US shale gas production is expected to increase by 7.7% per year to 7.07 tcf (200.2 bcm) in 2015, Canadian growth is expected to be dramatically higher, averaging over 48% per year, with output reaching 1.24 tcf (35.1 bcm) in 2015.

Global shale gas production growth is further expected to grow by 6.1% per year until 2020, reaching 11.34 tcf (321.1 bcm).

Long-term opportunities The long-term opportunities presented by shale plays have attracted new participants into the industry. The successes in profitable shale gas recovery in North America have begun to attract the attention of international oil companies (IOCs) seeking to replenish reserves and foreign national oil companies (NOCs) that are seeking to gain technical expertise in extracting unconventional resources. A notable recent example of this is the gas deal signed by PetroChina and Encana.

Merger and acquisition activity between independents and the energy majors in the US shale plays began an upward trend in 2008 is likely to continue as major energy companies seek to buy into US shale gas resources, the SBI report said, adding this will change the landscape for shale producers substantially over the next several years.�

FEBRUARY





The Haynesville Shale in northwestern Louisiana has become the largest producing natural gas shale find in the US, surpassing the more mature Barnett Shale in North Texas, according to the country’s Energy Information Administration (EIA).

For the past decade, the Barnett has been the US’ largest shale producer, hosting the drilling of around 10,000 wells and leading the North American revolution underway in the natural gas sector. But the EIA noted in a March 18 report that Haynesville was now the new top dog, after its gas players lifted their production above their Barnett peers by

mid-February, having taken advantage of technological advances in drilling and expanded pipeline infrastructure that more efficiently gets the gas into the market.

Haynesville surge Citing data from Bentek Energy, the EIA said the Haynesville – which experts say could hold up to 39 trillion cubic feet (1.1 trillion cubic metres) of natural gas – was currently producing around 5.5 billion cubic feet (155.8 million cubic metres) per day of gas.

Even after the Texas site recovered from freezing weather that can shut down

gas wells, it was only producing about 5.25 bcf (148.6 mcm) of gas per day, the EIA noted, citing reported gas pipeline flows.

Illustrating the production strides made by Haynesville producers in recent years, the Louisiana Department of Natural Resources (DNR) said recently that the state had issued permits for around 2,000 wells in Haynesville and that more than 1,000 had gone into production since mid-2008.

The agency said 500 more wells were near completion and that 121 were currently being drilled – and stressed that Louisiana’s natural gas production had exceeded 2 tcf (56.6 bcm) in 2010 for the first time since 1982.

The EIA – a division of the US Department of Energy (DOE) – listed several factors as contributors to the Haynesville surge.

It said that drillers and producers in Haynesville had been able to take advantage of what had been learned while developing Barnett to help ramp up production far more rapidly.

For example, nearly a decade of shale-focused drilling was needed to reach production of 5 bcf (142 mcm) per day in Texas, using early prototypes of horizontal drilling programmes, whereas the same level was reached in less than three years in northwestern Louisiana, the EIA underlined, as Haynesville operators have been able to tap into that experience.

“Technology-driven efficiency gains have enabled the Haynesville producers to reach that level with far fewer wells,” it said.�

MARCH

Haynesville claims pole position The US EIA has released data indicating that the Haynesville Shale has overtaken the Barnett Shale as the largest producing natural gas shale formation in the US By Kevin Godier � According to the EIA, the formation is producing 15 5.8 million cubic metres per day of gas � Drilling volumes in Barnett have flattened as explo rers have turned their attention to US$100 per barr el oil � However, El Paso-based Lippman Consulting has said that Haynesville has not overtaken Barnett…yet





Moreover, regional infrastructure is also a key factor, as major expansions to the gas transmission system that have been developed in northwestern Louisiana have supported the rising natural gas production from the Haynesville. Pipeline capacity expansions were recently completed on the Regency, Midcontinental Express, and Gulf Crossing systems, each of which transports Haynesville gas.

Characteristics One of the so-called “Big Four” key shale formations in the US – the others being the Fayetteville, Marcellus and Barnett shales – the Haynesville formation is a layer of sedimentary rock more than 10,000 feet (3,048 metres) below the surface of northwestern Louisiana, southwestern Arkansas and eastern Texas, with some of the formation stretching well across the northern central portion of Louisiana.

Named after the town of Haynesville in Claiborne Parish, Louisiana, and identified by geologists 60 years ago, the formation is of a type once considered too costly to explore, but rising energy prices and newer technology and processes have changed that, leading to a rush of activity as energy exploration companies have taken out leases on property in north Louisiana.

The most active areas in this respect have been Caddo, Bienville, Bossier, DeSoto, Red River and Webster Parishes of Louisiana, plus adjacent areas in south-west Arkansas and east Texas where the shale element of the formation is believed to run at its thickest.

Focus Its rise to prominence has come at a time when drilling in all US shale basins has increased tremendously, although Barnett activity may now be tailing off because of a swing in focus to liquids-rich plays.

The EIA report observes that drilling volumes have been flattening in the Barnett as explorers turn their attention to US$100 per barrel oil.

It said: “As gas-directed drilling in the Barnett slows and natural gas prices

remain relatively low, operators are turning their attention to the more liquids-rich areas of the play, thereby reducing the emphasis on gas.”

The data from Bentek Energy – an Evergreen, Colorado-based consulting firm – said that Barnett Shale production had been maintained at about 5.35 bcf (151.5 mcm) of gas per day in the first several weeks of 2011, but fell off sharply in mid-February before recovering to its current level. At about the same time that Barnett production was just getting back on line, Haynesville production began following a sharp upward trend toward its current peak.

According to Matt Marshall, Bentek senior energy analyst, shale gas production in the Fort Worth Basin has been in slight decline since November 2010, at the same time as the Haynesville has entered a strong growth trend.

“Haynesville would have passed the Barnett in a couple of months anyway if these trends had continued,” he told Platts on March 21. Marshall estimated Haynesville’s current production at around 5.62 bcf (159 mcm) per day, compared with 5.40 bcf (152.9 mcm) per day in the Barnett Shale.

Casting doubt However, not all market observers are convinced by the Bentek and EIA views that the Barnett Shale has been eclipsed by the Haynesville Shale as the US’s number one natural gas field.

At Lippman Consulting, an El Paso-based natural gas consulting firm,

president George Lippman has taken firm issue with the claim, underlining that “our data clearly show that the Barnett production is still greater than the Haynesville production”.

In an e-mail to the Fort Worth-based Star-Telegram, on March 22, Lippman said his firm’s estimates showed Barnett production averaging 5.52 bcf (156.3 mcm) per day in February, easily exceeded the output of 5.03 bcf (142.4 mcm) per day from Haynesville.

Lippman said his company’s calculations were derived from Texas Railroad Commission data, “plus the most recent data from our Gas Processing Plant database that collects daily volumes at the outlet of all gas-processing plants in each region and then extrapolates that data back to wellhead volumes.”

According to the Star-Telegram, Steven Grape, the Dallas-based domestic reserves project manager for the EIA, and Gene Powell, publisher of the Fort Worth-based Powell Shale Digest, said on March 21 that the agency needed further clarification and confirming data before it could be assured that the Haynesville was the new leader.

Lippman said that although he expected that Haynesville would surpass the Barnett in production “in the months ahead ... [it] has not happened yet”.

These comments go to show that shale gas production is something of a moveable feast where the lead can change hands on a regular basis. Some industry analysts have predicted that drilling in the Haynesville will probably be on the end of a slowdown similar to the Barnett if oil prices remain high and gas prices remain low, while other have highlighted how the severe decline rates that follow initial shale gas production spurts may yet alter the figures dramatically in the months and years ahead.

For the time being, at least, the Haynesville producers have grabbed pole position in the US and are likely to lead the “shale gale” peloton into the next bend in the route.�

MARCH

The Haynesville – which experts say could hold up

to 39 trillion cubic feet (1.1 trillion cubic metres) of

natural gas – was producing around 5.5

billion cubic feet (155.8 million cubic metres) per

day of gas





The Indonesian government has signed nine new production-sharing contracts (PSCs) in its coal-bed methane (CBM) sector, four of which involve BP ventures in the Barito basin of South Kalimantan.

Indonesian Energy Minister Darwin Zahedy Saleh announced the PSCs on April 1 and said the nine contracts in Kalimantan and Sumatra would help to revive flagging investment in Indonesia’s oil and gas sector. Together, the contracts account for investment of US$42.55 million with a total signature bonus of US$11.3 million across the nine blocks.

Illustrating the momentum that is building in the CBM industry in coal-rich Indonesia, the deals were announced on the same day that Dart Energy said it had produced first gas from its SCBM-1 well at the Sangatta West project in East Kalimantan. It is believed to be the first dedicated CBM well to produce gas from a PSC in Indonesia.

One of the reasons for growing interest in CBM in Jakarta is the soaring domestic demand for natural gas, which has made it difficult for Indonesia to maintain and expand its exports of liquefied natural gas (LNG) in recent years.

Jakarta’s jackpot Over 30 CBM PSCs have been granted by the government since 2008. These include exploration commitments of around US$150 million over the next three years as Jakarta pushes harder to develop its unconventional gas resources.

Indonesia holds a potential 453 trillion cubic feet (12.83 trillion cubic metres) of CBM reserves in-place, more than double the country’s natural gas reserves, according to a 2004 estimate by Stevens and Hadiyanto.

The commitments by BP – which has over 35 years of experience in Indonesia and is one of the largest foreign investors in the country – will be seen as a particular boost for Jakarta in this respect.

“BP has significant experience and expertise in the development of unconventional gas, including CBM, and we look forward to working with our partners to apply this to the potential of Indonesia’s coal resources,” said BP’s CEO, Bob Dudley.

Another PSC participant, Pertamina Hulu Energi (PHE), has emphasised that the contracts demonstrate support for Indonesia’s push to develop alternative energy resources to curb the country’s dependence on crude oil and conventional gas. “We hope that this strategy [developing CBM] can tackle the gas supply shortfall,” said PHE’s president, Dwi Martono, in a press release.

Nine blocks Of the nine CBM blocks, three were directly offered by the government to

potential operators, while those for the remaining six blocks were decided in auctions. The three directly offered blocks are: the Tanjung IV block in Central Kalimantan, which was awarded to a consortium of PHE Metana Tanjung IV and BP Tanjung IV; the Muara Enim II block in South Sumatra, which was awarded to a consortium of PHE Metana Sumatera 5, Metana Enim Energi and Indo CBM Sumbagsel 2, and the Muara Enim Block III, which went to a consortium of PHE Metana Sumatera 4 and Baturaja Metana Indonesia.

Three of the six auctioned blocks – the Kapuas I, Kapuas II and Kapuas III blocks – are located in Central Kalimantan. These were awarded respectively to: a consortium of Transasia CBM and BP Kapuas I; a grouping of Kapuan CBM Indonesia and BP Kapuas II, and a consortium of Gas Methan Utama and BP Kapuas III.

The remaining three blocks comprised: the Kutai Timur block in East Kalimantan, won by a consortium of Senyiur CBM and Total E&P Kutai Timur; the Kutai Barat block, also in the same province, won by Gas Methan Abadi, and the Sijunjung block in West Sumatra, awarded to a consortium of Inti Gas Energi and Bukit Asam.

BP push From BP’s perspective, the new PSCs add to its existing operations in Indonesia, including the Tangguh natural gas project in West Papua.�

APRIL

New acreage awards boost

Indonesia’s CBM sector The signing of nine CBM production-sharing contracts has provided a major boost to Indonesia’s flagging oil and gas industry By Kevin Godier � Together the PSCs account for investment of US$42.5 5 million � Four of the contracts involve BP ventures in the Ba rito basin of South Kalimantan � Over 30 CBM PSCs have been granted by the Indonesia n government since 2008

The commitments by BP will be seen as a particular

boost for Jakarta



www.newsbase.com Edited by Ryan Stevenson

All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All


The participation of the UK major comes shortly after its striking of agreements to access new gas resources in China, India and Australia, and also follows the company’s CBM joint venture in Indonesia with Eni and VICO, which in late 2009 was awarded a contract at Sanga Sanga near the Bontang LNG plant in East Kalimantan.

BP currently produces about 650 million cubic feet (18.4 million cubic metres) per day of gas in the San Juan basin in Colorado, which is currently its sole CBM-producing operation. The Indonesian activity suggests the UK giant is now branching out in its pursuit of CBM acreage around the world.

Together the four Indonesian PSCs cover an area of approximately 4,800 square km. BP said it had committed to spend US$15 million on seismic exploration and surveying over the next three years and might begin production within that period. BP will hold a 44% participating interest in the Tanjung IV PSC and co-owner Pertamina will hold the remaining 56%. Its stake in the three other PSCs will be 45%, alongside entities all controlled by Sugico, a Jakarta-based mining company.

How successful the nine new ventures

will be – and whether the gas extracted can be sold outside the lower-margin Indonesian market – remains to be seen. But the bigger point is that Indonesia appears to be on the verge of joining other markets where the CBM industry has made spectacular strides, notably the US, Canada, Australia and China.

The authorities in Jakarta will have been especially encouraged by the news from Dart Energy’s SCBM-1 well, which is the first of four pilot wells planned for Sangatta West, having been drilled last month to a depth of 830 metres.

Dart said that well testing over the next two to three months would determine production and reserves potential, once a stabilised gas flow is achieved, and that gas produced from the Sangatta West pilot holes would initially be sold under an approved gas-to-power scheme to the local grid.

Dart is the joint operator of the Sangatta West CBM PSC with Ephindo Energy, each firm holding 24%, while Pertamina holds the remaining 52%. Also in Indonesia, Dart said a joint operating agreement for the Tanjung Enim PSC has been signed by all parties, enabling the first exploration well on the Sumatra block to be spudded shortly.

Eventual gas output from the block is to be sold initially to the local market under a deal similar to that for Sangatta West.

Other initiatives under way in Indonesia attest to the country’s awakening of its unconventional gas potential. Houston-based Contractor Core Laboratories and Indonesia’s upstream oil and gas regulator BPMigas have commenced a study into the shale gas potential in Sumatra and Kalimantan in Western Indonesia, after indications from the Bandung Technology University that the country has around 1,000 trillion cubic feet (28.3 trillion cubic metres) of shale gas reserves in place.

Reports have said that ministers are hoping to offer blocks for shale gas evaluation and exploration by the end of the year, with a target of signing the first co-operation agreement to exploit shale gas in 2012. Indonesia’s Energy Ministry has also started a study into the shale oil potential on Buton Island in south-east Sulawesi.

Indonesia’s growing interest in its unconventional resources is inevitable, given the natural depletion of its mature oilfields, from which crude and condensate output has fallen from peaks of above 1.5 million barrels per day in the 1970s to 947,000 bpd in 2010.

Indonesia was also formerly the world’s second largest gas exporter behind Qatar, but has been overtaken by Malaysia after recent declines in its output owing to a decrease in production from the Arun LNG plant in Aceh and the rising use of natural gas at home to avoid costly imports and dwindling domestic supply.

BP’s willingness to dip its toes in one of the world’s largest and most under-explored CBM resources will ensure that other global energy giants follow progress in Indonesia’s CBM sector closely.�

APRIL





The environmental spotlight on North America’s unconventional oil and gas industries has intensified recently after a blowout at a natural gas well in Pennsylvania. The incident led to thousands of gallons of drilling fluid seeping into local waterways and intensified debate about the threat of water contamination posed by the hydraulic fracturing (fracking) process.

Elsewhere, the US Bureau of Land Management (BLM) has come under pressure from environmental groups in Utah, Colorado and Wyoming after launching discourse on opening up large swathes of the states to oil shale and oil sands development. Environmentalists are using ongoing hearings in Utah to lobby the BLM against sanctioning such development.

Fractious debate For the time being, the most contentious debate surrounds the extraction of shale gas and the threat this poses to water tables and the atmosphere. In Texas, a pending fracking disclosure bill would require drillers to disclose their array of chemicals, while another would require them to use ‘tracer’ fluid in the liquid they use for fracking, so that the industry would not face false claims of groundwater pollution.

Elsewhere, the boom in the Marcellus shale has led to claims of contaminated water, especially in Pittsburgh, where reports claim water in some areas has

reached a salinity level inappropriate for consumption owing to drillers’ use of chemicals in the fracking process.

Against this backdrop, the shale gas producers are looking to expand drilling to new parts of the US. But they will be braced for a barrage of criticism after the blowout at Chesapeake Energy’s well in Pennsylvania on April 19.

The accident in LeRoy Township, just south of the New York State border, reportedly spilled thousands of gallons of water and chemicals into the nearby Towanda Creek and forced the temporary evacuation of nearby families. Workers were able to contain the spill by April 20 and regained permanent control of the well on April 25. Nobody was injured in the incident and the Pennsylvania authorities said the environmental impact appeared to have been minor. Yet the events have further heightened the scrutiny on gas drilling in the Marcellus shale, the gas-bearing rock formation that

stretches from West Virginia to New York.

Chesapeake, which had 87 active wells in Pennsylvania in the second half of 2010, said the accident was caused by a broken piece of equipment. While industry commentators suggested that the incident could hurt Chesapeake’s reputation for safety and could lead to calls for stricter regulation of shale drilling in Pennsylvania, the company stressed that its emergency response procedures and the design of the well site combined to minimise the amount of fluid spillage.

“We spend our time focused on ensuring that we have safe and environmentally responsible operations,” Chesapeake said in a statement. “If you take care of those two critical issues, reputation will take care of itself,” said the statement, which stressed that Chesapeake said it had had a well-control specialist on the scene in 30 minutes. “There was no delay in response or shortage of expertise throughout,” it emphasised.

Chesapeake, the second biggest US gas producer after ExxonMobil, has nevertheless elected to shut down all of its fracking operations in Pennsylvania and West Virginia until it ascertains what went wrong in LeRoy Township.�

IMAGE: Marcellus shale gas drilling tower in Pennsylvania

MAY

Fractious fracking debate explodes

in wake of Pennsylvania blowout Environmental groups are on the offensive against the unconventional gas industry after the recent blowout at one of Chesapeake Energy’s wells in Pennsylvania By Kevin Godier � The blowout led to thousands of gallons of drilling fluid seeping into local waterways � Chesapeake shut down all of its fracking operations in Pennsylvania and West Virginia following the in cident � The US government is under pressure over plans to d evelop oil sands and oil shale in the west of the c ountry






The US Environmental Protection Agency (EPA) has asked for details, including sources of the discharge and the extent of environmental damage. The EPA is conducting a two-year study on the safety of fracking and its impact on drinking water. Initial results of the peer-reviewed study are expected in late 2012.

In addition, Pennsylvania’s Department of Environmental Protection has sent the company a “notice of violation,” representing the first step in enforcement proceedings and marking the 58th notice of violation for Chesapeake in Pennsylvania since 2008, the third highest figure amongst Marcellus operators.

Most of those violations were minor, however, and did not result in environmental damage. Chesapeake has said in April that it will henceforth disclose the chemicals it uses on all of its fracking jobs.

Salt Lake City rumbles One the other side of the US, the BLM is examining whether as much as 1.9 million acres (7,690 square km) should be made available for commercial oil shale projects and also whether more than 400,000 acres (1,618 square km) should be opened up for oil sands leasing

and development. The first of seven hearings began on

April 26 in Salt Lake City, Utah, following a decision by US Interior Secretary Ken Salazar to take a fresh look at a federal oil shale plan covering Utah, Wyoming and Colorado that was released in 2008 by the Bush administration.

Hearings on the plans were due to be held in Wyoming on April 29 in Rock Springs and on May 5 in Cheyenne, and in Colorado on May 3 in Rifle and on May 4 in Denver.

Environmentalists have expressed concern not only about the impact of mining in Utah’s San Rafael Swell and the scenic Book Cliffs area, but also the potentials risks to air quality and water supplies downstream.

“The scoping process is designed to explain to the public what we’re about to do and gather their input early on,” said Mitch Leverette, chief of the BLM’s Solid Minerals Division. “Based on their comments, we hope to offer a range of alternatives in the final report,” he said, quoted on April 28 by Associated Press. A draft of the BLM report is due to be completed by late September, and the final report completed by December 2012, he said.

One environmental NGO, Living Rivers, is currently challenging Utah’s approval of a proposed commercial oil sands project at the PR Springs mine in the Uinta Basin, which would be the first of its kind in the US.

The group contends the scheme would dig up fragile topsoil, destroy limestone plateaus formed over thousands of years and pollute groundwater downstream that flows into the Colorado River. Living Rivers filed a complaint with the state, claiming that the Utah Division of Water Quality has not accurately assessed the potential for widespread environmental damage.

US President Barack Obama is generally supportive of developing domestic unconventional oil and gas resources in order to curb his country’s reliance on imported energy. Indeed, Obama has made natural gas the cornerstone of his energy policy. But despite support from the government, it is clear that unconventional energy developers in the US will continue to face pressure from environmental groups until they can prove that the drilling processes they use are both safe and clean.�

The unprecedented boom in shale gas in North America will have a worldwide impact, according to the International Energy Agency (IEA). However, a new

report from the Paris-based group said the US and Canada would remain largely isolated from the global gas trade – a blow to hoped for exports from North

America, based on liquefied natural gas (LNG).�

MAY

JUNE

Shale investments continue in

North American gas island Cash continues to pour into shale gas opportunities in the US and Canada, despite the prospects for exports diminishing By Ed Reed � ExxonMobil has affirmed its XTO shale gas position, acquiring two Marcellus-focused companies





Despite this projected lack of export capacity, companies are continuing to invest substantial sums in opportunities in the US and Canada. The most recent, ExxonMobil, has struck a deal to acquire two companies focused on the Marcellus shale.

Unconventional gas production in North America, under the IEA’s predictions, will increase from 360 billion cubic metres in 2008 to 670 bcm in 2035, making up around two thirds of the total output.

Marcellus move ExxonMobil, which took a substantial shale gas position through its US$41 billion acquisition of XTO Energy in 2010, has committed US$1.7 billion to buy Phillips Resources and TWP, both based in Pennsylvania. The two companies are to be incorporated into the XTO unit.

The deal, which completed on June 2, will involve ExxonMobil taking ownership of around 317,000 acres (1,282 square km) in the Marcellus. Under the transaction, ExxoMobil will add around 228 billion cubic feet (6.46 billion cubic metres) equivalent of proven gas reserves and around 50 million cubic feet (1.42 million cubic metres) per day of production.

A note from Tudor Pickering Holt said the deal appeared attractive for the purchaser, with below-average pricing of around US$5,000 per acre (US$1.25 million per square km) and that the south-west Pennsylvania assets were “in a good zip code.” The brokerage note said, following this deal, ExxonMobil’s total Marcellus acreage was around 700,000 acres (2,830 square km).

ExxonMobil – and the other large energy companies – are becoming increasingly reliant on gas reserves and production to prop up their company statistics. In February, ExxonMobil said 53% of its proven reserves were gas, with the remainder liquids. While it managed to replace around 100% of its liquids production in 2010 it added a substantial amount of gas – 328% of its previous production, or 2.6 billion barrels of oil equivalent – suggesting it will

become significantly more gas-focused. The ExxonMobil deal in the Marcellus

will provide reassurance for other companies, as there has been increasing talk of an investment “bubble” in shale gas, with leasing prices rising while hub prices remain low.

The IEA reported that seven transactions in North America in 2010 – not including the XTO deal – carried price tags of US$1-5 billion. This year, significant deals have focused on the Montney shale, in Canada, where PetroChina committed US$5.4 billion in February to a venture with EnCana and, earlier this month, Petronas struck a US$1.1 billion deal with Progress Energy.

Gas island Some commentators have pinned further growth in shale gas developments on the ability to export this feedstock, but recent research suggests this may not happen to the extent hoped.

The IEA’s recent report, “Are we entering a golden age of gas?” was released last week and set out a new scenario under which production of the feedstock would increase beyond previously held expectations. In North America, it said, “unconventional gas helps domestic production keep pace with increasing demand in the [new] scenario. Overall, the region will maintain its status as a marginal net importer [as a result of Mexico],” to 2035 and “will remain relatively isolated from the other gas markets.”

While prices in the US and Canada are likely to remain low, with “mechanisms in these countries continuing to apply

strong competitive pressure to move prices towards costs, North America should play only a minor role in net global LNG trade.”

While a number of plans have been mooted on exports from North America – with liquefaction plants planned for both the US Gulf Coast and Canada’s West Coast – the extent to which this will be followed through remains unclear and not everything will come to fruition.

In addition, while the ability of LNG export capacity has been cited as a means of hiking local gas prices – in effect opening North America up to global pricing – the impact is likely to be limited. Gas in Western Canada that is being considered for export, for instance via the Kitimat LNG plant, is stranded and will not play a role in meeting local demand. Infrastructure challenges will be significant in building these plants.

Plans for export capacity in the Gulf Coast, meanwhile, face a number of obstacles and analysts have predicted output will only reach 1-2 billion cubic feet (28-57 million cubic metres) per day by 2017, which will be insufficient to turn around the local glut.

A number of new LNG plants are planned around the world, particularly in Australia, which was picked out by the IEA as potentially challenging Qatar’s position as top producer by 2020.

In addition, the impact of shale gas development in other countries will also have an effect on liquefaction plans. China, for instance, is assessed as holding the world’s largest shale gas reserves. The Asian state will continue to be reliant on gas imports but North American LNG supplies will face competition from a number of sources and are likely to be at the higher end of world prices.

Domestic consumption While export opportunities are limited, the IEA’s new scenario suggests there may be substantial demand increases in the US. The “golden age” report predicts US demand could be nearly 790 bcm by 2035, up by 18% against previous scenarios.�

JUNE

ExxonMobil’s deal in the Marcellus will provide reassurance for other

companies, as there has been increasing talk of an

investment “bubble” in shale gas





This growth will come from power generation and transportation, with coal demand falling by 9% and oil by 6% by 2035. Coal’s share of electricity generation falls from 49% in 2008 to 30% in 2035, under the new scenario, with gas moving up to 27% of demand in that timeframe.

ExxonMobil’s deal suggests continued confidence in domestic prospects and demand. While exports look unlikely, increased consumption will ensure there is a place for further investments in shale gas. Some prices being paid by other companies look too high – but shale gas will likely only become a more important part of North America’s energy mix.�

France recently sounded a major warning to the unconventional hydrocarbons industry, after it became the first country to ban the use of hydraulic fracturing (fracking) in drilling for natural gas and oil.

French senators voted to ban the controversial practice on June 30, meaning that oil and gas companies operating in France with fracking permits will have them revoked according to the legislation, passed by a 176 to 151 vote. However, Paris-based explorer Toreador Resources said it would continue to work to develop shale resources in the Paris Basin, in which it holds the most acreage of any explorer.

The bill had earlier passed the National Assembly, the country’s lower chamber, on June 21, and was published in the

French Gazette in early July to become law. “We are at the end of a legislative marathon that stirred emotion from lawmakers and the public,” French Environment Minister Nathalie Kosciusko-Morizet said on June 30 before the vote. Parliament would have to vote for a new law to allow research using the technique, she said.

The vote was divided along party lines, with the ruling centre-right UMP party voting in favour and the opposition voting against the bill, according to Le Monde. The Socialist Party opposed the bill because it did not go far enough, arguing that it left open possible loopholes and that it would not prevent the exploitation of shale oil deposits by techniques other than fracking. An earlier version of the bill, which the Socialists

had supported, would have banned any kind of development of the deposits.

As things stand, companies that currently own permits for drilling in oil shale deposits on French land will have two months to notify the state what extraction technique they use. If they admit to the use of fracking, or if they fail to respond, their permits will automatically be revoked.

French resistance The French bill, which was proposed at the end of March by the leader of the UMP’s parliamentary majority, came after environmentalists and Green Party activists rallied together to provide robust opposition to shale exploration in the country.�

JUNE

JULY

The Franco fracking furore France’s decision to ban fracking will have a major impact on companies that are exploring shale deposits in the country and the wider unconventional oil and gas industry By Kevin Godier � Companies operating in France with fracking permits will have them revoked, according to new legislati on � Firms with shale drilling permits have two months t o notify the state what extraction technique they u se � Companies that could suffer include Toreador Resour ces, Vermilion Energy and Schuepbach Energy





Before the bill’s passage into law shale gas drilling was still at the development stage in France. The country has abundant shale gas and oil reserves, with the most promising drilling area for gas covering 10,000 square km in the southeast. France opened its doors to shale gas exploration in March 2010, when former Environment Minister Jean-Louis Borloo granted three permits for periods between three and five years. The move was seen to have been heavily influenced by the so-called “shale gas revolution” in the US, which has helped that country reduce its dependence on imported energy and has eased prices while providing a fuel that burns more cleanly than oil or coal. However, since French oil and gas giant Total announced it wanted to start exploring for shale gas in the country’s southern region, politicians and environmentalist groups have clamoured to halt exploration because of the perceived impact that shale gas exploration techniques can have on the environment, in particular the risk to water quality and the threat of landscape disfiguration. Total has claimed its Montelimar shale acreage in southern France could hold as much as 2.38 trillion cubic metres of gas.

Franco fracking The clamour over fracking ramped up markedly during the first half of 2011, placing France at the centre of the wider debate in Europe about the dangers of the technique. And now it seems that France’s position is having an influence on other countries and their respective approaches to the fracking issue.

A UK House of Commons select committee has called for an investigation into the link between shale gas tests in northwest England and two minor earthquakes that occurred in the area shortly after operations started up. As a result, the Dutch Ministry of Economics, Agriculture and Innovation has said there can be no green light for shale gas exploration in the Netherlands until results from the UK government investigation can be assessed.

Certain parts of Germany have also banned fracking, which has only begun

in earnest in Europe in Poland. France’s fracking ban also comes at

the same time that the New Jersey State Senate has voted to ban the practice, over fears that it could contaminate drinking water.

Toreador Although the new French bill will come as a major blow to unconventional gas explorers, one entity that claims to be unaffected in the near term is Toreador Resources. The company sold its assets in Turkey, Hungary and Romania and moved its headquarters to Paris from Dallas in 2009 to focus on developing shale oil in the Paris Basin. The company has estimated oil reserves in the basin at 65 billion barrels. Toreador’s CEO, Craig McKenzie, said in a statement on July 6 that the company’s initial evaluation activity at its Paris Basin licences would not involve fracking.

“It is important to note that our plan to evaluate our exploration licences does not call for hydraulic fracturing,” McKenzie said. “We will not conduct hydraulic fracturing operations within any of our permit areas. We will make full disclosures and representations to the French regulatory authorities as may be required.” He went on to say that Toreador’s work would not stop because of the ban. “Notwithstanding the new law, we believe the oil resource potential of the Paris Basin can create jobs, provide local economic development, generate substantial revenues for the state and benefit all stakeholders ... We reaffirm our commitment to define and develop this basin to reach its potential

for all stakeholders, in compliance with French legislation and through co-operation with French authorities.”

Toreador decided to focus on its French portfolio in 2009, offloading its interests in other countries and staking its future on the success of shale drilling near Paris, where it also holds conventional oil assets. In May 2010, the arrival of US integrated independent Hess into the acreage held by Toreador in the Paris Basin delivered a very serious US$120 million of financial firepower to the venture, which was intending to conduct shale oil exploration drilling in the town of Doue (Seine-et-Marne) after April 15, 2011, under a data capture-oriented first phase of a two-phase work programme.

McKenzie told UOGM last year that extra processing capacity at Total’s Grand Puits refinery in the middle of the Paris Basin was a major selling point for Hess, which saw key similarities between Paris Basin shale and the Bakken shale in the US, where it is proposing to invest about US$1 billion per year over the next five years. McKenzie stressed at the time that the geology of the Paris Basin – in which there is some 2,000 metres of separation between the shale and the freshwater strata – would avoid contamination problems experienced in the US’ Marcellus shale, which is close to freshwater aquifers. Given the lack of alternatives to fracking to extract oil out of shale, Toreador’s medium-term strategy remains to be divulged. Some analysts have suggested that the company could participate in scientific research into shale gas exploration that French Prime Minister Francois Fillon has favoured, so as not to rule out technologies that do not harm the environment.

United front Other explorers that have won permits and are affected by the ban include Calgary-based Vermilion Energy, which has drilled two wells in the Paris Basin, and Schuepbach Energy, which has been looking to bring in GDF Suez as its partner in southern France.�

JULY





GDF Suez’ CEO, Gerard Mestrallet, has insisted that shale gas exploration is “a matter of national interest,” but all the indications are that France is united behind the fracking ban.

Meanwhile, Kosciusko-Morizet has talked publicly of the “devastated countryside” and “sullied water tables” in US regions where fracking has occurred. There is also a widespread view that

France’s large nuclear power industry gives it far less incentive to explore new approaches compared with other countries like Poland, where tapping into shale reserves has become a national priority to win independence from Russian gas imports.

On the face of it, Toreador is not giving up on its core strategy. “As a longstanding operator in France, we have

demonstrated our expertise and ability to conduct our Paris Basin operations in full respect of the environment and local residents where we operate,” McKenzie said. But bringing his company’s plans to fruition may now depend on a huge reserves find, and a consequent reconsideration of the ban by the French authorities.�

As the Maghreb states work to re-organise their energy sectors amid political and economic transitions, many are looking to the area’s shale potential as a viable, if controversial, path forward.

Barring Libya, where civil strife has led to a virtual halt to all exploration and production, the region has turned its attention towards exploiting its unconventional potential to bolster existing resources and diversify sources of supply.

In locations such as Algeria, the promise of shale projects offers a chance to rejuvenate an energy industry wracked with controversy and setbacks. This comes after two years of waning interest from foreign investors and domestic investigations into widespread corruption at the state-owned Sonatrach.

The impact of the corrosive atmosphere and increasingly unfavourable conditions for foreign companies has led to a sharp drop in interest from international firms. During

the last licence round, only two of the 10 available permits were awarded, one going to Spain’s Cepsa and the second to Sonatrach.

Over the last 12 months, though, the government and Sonatrach have sought to encourage shale development in the country, culminating with an agreement with Italy’s Eni to take the lead in the coming year.

For its part, Algeria represents an opportunity for Eni to compensate for lost production in the region that resulted from its heavy investment in neighbouring Libya over the past two decades. After investing billions of dollars, with the aim of securing a substantial resource base close to home, the violent conflict that has raged in Libya for the last few months has cast a pall over projects.

The Algerian agreement, signed at the end of April, will allow joint projects between Eni and Sonatrach to seek out what has been called a significant shale

gas potential.

Oil shale Meanwhile, in Morocco, where domestic energy resources have remained elusive for the leadership of King Mohammad VI, one company has plunged into the oil shale business.

Following four years of testing, and coming in the latter half of a three-year memorandum of understanding (MoU) with the government of Morocco, UK-based San Leon Energy announced this month that it was ready to begin production at a site in the southern part of the country.

San Leon, which is working on the Tarfaya oil shale field pilot project, arrived in the country at the same time as Brazil’s Petrobras. The UK minnow has so far been able to complete two wells, has set up an operational base camp and is on the verge of spudding a third well.�

JULY

AUGUST

Shale offers North

Africa alternatives Unconventional resources are on the up in North Africa as the region looks to drum up fresh interest in its energy potential By Christopher Coats � Algeria is struggling to find investors in conventi onal projects but has signed up Eni for shale gas w ork � Early-stage projects are under way in both Morocco and Tunisia � Concerns continue over the impact of fracking but a recent US report provides support for the practice





Regional analysts and government officials, who have boasted of the country’s shale potential but have so far shown little in the way of actual progress, have welcomed the announcement that production will soon start.

Shale gas Tunisia, despite the unrest which led to the removal of its president, Zine el Abidine Ben Ali, after three decades, appears to be continuing its own shale efforts with the aid of France’s Perenco and Canada’s Cygam.

In an operational update at the

beginning of the year, Perenco said none of its operations would be hindered by the political transition and that it intended to continue its shale efforts alongside its existing natural gas projects.

The company has had some success in hydraulic fracturing on its El Franig field and, if production begins, this will mark the first shale gas project brought onstream in North Africa.

This recent spate of new shale projects in North Africa comes as a part of a much larger wave of similar efforts across the globe, spurred by reports of enormous shale potential from China to

Argentina. Much of this new enthusiasm comes as companies and countries alike seek to repeat the results witnessed in the US, whose unconventional resource now provides 30% of supply.

However, progress has not been without controversy, as critics have cited the environmental impact of the process of fracking as being a reason for slowing shale projects. While Europe has seen such opposition result in moratoriums and outright bans on fracking, North Africa has not yet witnessed such public or political opposition.

That said, opposition in South Africa to work in the Karoo

Basin has been notable and it may well be that recent changes in government in Tunisia may play into this environmental trend.

Supporters of such shale movements outside the United States received impetus this week with the release of a study commissioned by the US government to assess the viability and environmental impact of shale projects.

While the report went on to suggest a number of new policies related to minimising the environmental impact of fracking, it appears to advocate expanding shale projects in the US and abroad.�

The emerging Utica shale in North America continues to make headlines, with Chesapeake Energy forecasting that hydrocarbons in the formation could be

worth half a trillion US dollars. Chesapeake has so far spent US$2

billion on its Utica acreage, and the company’s CEO, Aubrey McClendon,

recently predicted that the whole play “could be worth US$500 billion,” much of which would be extractable from the eastern Ohio section of the formation.�

AUGUST

SEPTEMBER

Chesapeake upbeat about Utica Chesapeake Energy’s CEO believes oil and gas reserves in the Utica shale could be worth US$500 billion and has urged speedy development of the formation By Kevin Godier





McClendon suggested that activity in the Utica in the years to come could be the “biggest thing economically to hit Ohio since maybe the plough.”

Speaking at an industry event in Ohio on September 21, McClendon admitted that fluctuating commodity prices made it difficult to estimate the value of the reserves in the Utica shale with any precision, but described his estimate as “reasonable,” according to a report by Natural Gas Intelligence (NGI).

Interesting figure Although the US$500 billion estimate is speculative and by no means a scientific analysis, it is an interesting figure, as it is among the first to have been offered for the fledgling Utica, which is a deeply buried rock formation that sprawls below parts of eight states stretching from Tennessee to New York in the US and the provinces of Quebec and Ontario in Canada.

Explorers have suggested that the richest oil reserves in the formation lie in eastern Ohio.

In its financial results for the second quarter of 2011, released in late July, Chesapeake said it believed the liquids-rich Ohio section of the Utica to be more than just economically viable. It said the shale “is likely most analogous, but economically superior to, the Eagle Ford Shale in South Texas.”

Chesapeake stressed that both plays had dry gas, wet gas and oil windows, allowing the overall play to remain economic even at times when oil or natural gas prices were depressed.

Unlike the Eagle Ford, the Utica is still too new to measure, McClendon said. “We know it’s big. How big is big? We don’t know and I can’t put volumes on it yet,” he said.

One estimate has estimated 20 trillion cubic feet (566 billion cubic metres) of natural gas in the Utica shale, which is believed to offer some unique exploration and extraction challenges, including a higher carbonate content and lower clay mineral count than the Marcellus shale, as well as significant depth and a lack of information

surrounding the play. Nevertheless, producers are cautiously

optimistic that advances in technology utilising multi-stage hydraulic fracturing (fracking) and horizontal drilling techniques can unlock the play’s potential.

Results As part of its second-quarter report, Chesapeake noted successful results from six horizontal and nine vertical wells drilled in its Utica shale holdings.

Based on its proprietary geoscientific, petrophysical and engineering research during the past two years, it said that its “industry-leading 1.25 million net leasehold acres (5,059 square km) in the Utica shale could be worth US$15-20 billion in increased value to the company.” Analysts at Baird Equity Research said at the time that the results constituted an implied acreage valuation of US$12,500-16,667 per acre.

The Chesapeake announcement – aligned with a disclosure from Devon Energy that it had acquired 110,000 acres (445 square km) in the region and planned to drill three wells there this year – added encouragement to growing hopes that the Utica shale would produce a significant and cheap new source of oil.

According to comments made by Manuj Nikhanj, head of energy research at trading house Investment Technology Group, the disclosures had helped propel lease prices in the Utica to about

US$4,000 per acre, around eight times the rates at the start of the year. “If you say it’s worth US$15-20 billion, you’re saying it’s a home run,” said Nikhanj, as quoted by the Wall Street Journal on August 6.

Chesapeake said the US$2 billion it had spent on drilling rights on its 1.25 million acres (5,059 square km) in eastern Ohio could now be worth 10 times that much, now that it has drilling results. “The Utica should emerge as a key driver in the future growth of US energy supplies,” said McClendon during a July 29 conference call with investors.

Utica interest Speculation that Chesapeake was targeting the Utica came when the Oklahoma City-based firm purchased around 500,000 net Appalachian acres (2,023 square km) from privately-held Anschutz Exploration in late 2010. “We started to look at Utica in Ohio here about two years ago and arrived at two conclusions: One, it’s big: two, a lot of the acreage on it was owned by EnerVest,” McClendon said last week, referring to the leading conventional oil producer in Ohio.

Chesapeake and EnerVest recently formed a joint venture to explore the Utica, but each firm is also exploring outside of that joint venture. Chesapeake has so far drilled 15 Utica wells this year, prompting it to say it would expand the number of rigs working there from five to 40 by the end of 2014.

It should raise its rig count to eight by the end of 2011 and reach at least a range of 16-20 rigs by the end of 2012. Chesapeake intends to drill as many as 12,500 wells in the Utica and McClendon expects around 10 companies to compete in the play, investing as much as US$200 billion in Ohio over the next 20 years. He said Ohio should have more than 100 rigs in the Utica once full capacity is reached. Illustrating the growing momentum, CONSOL Energy and Hess Corporation recently formed a joint venture in the Utica and Anadarko Petroleum Corporation is in the process of obtaining drilling permits.�

SEPTEMBER





Chesapeake said in July that it planned to mirror its strategy with its other shale play acreage, by using joint ventures and/or other monetisation alternatives, with at least one transaction likely to be completed by the fourth quarter of 2011.

Frack star Unsurprisingly, McClendon is an

unashamedly enthusiastic proponent of fracking. Maintaining his stance as the shale industry’s most aggressive promoter, he told opponents of fracking that he was “the biggest fracker in the world” as he entered the Ohio auditorium last week.

“I’ve done it 16,000 times since 1989 and I’m proud of it,” he said, explaining

that Chesapeake’s “plan” involved increasing jobs, lowering the cost of energy and helping the US become energy-independent. Responding to the argument that energy supply should come from renewables, he said: “It’s not reality. It can’t happen.”�

The impact of underground coal gasification (UCG) technology on the world energy map could be as significant as the shale gas revolution, a new study has claimed.

Energy research and consultancy group Zeus Development Corporation released the study on October 18, in which it highlights the cost advantages of UCG and the growing use of the technology in Australia, Asia, Europe, Africa and North America, where natural gas prices are below US$4 per million British thermal unit.

The Zeus report highlighted that 10 new UCG projects had been announced this year, which means 51 schemes that use the technology are currently in various stages of development around the world. Eight of these are operational and another 43 are in the planning phase, the report noted.

“UCG could solve a lot of the developing world’s energy supply challenges, provided [that] developers can manage environmental risks,” said a

Zeus analyst, Chris Cothran, who was a co-author of the study. “We believe it will be applied most extensively in countries such as India, China, Pakistan and Bangladesh, where governments have unmineable reserves and are keen to improve the standard of living without having to compete for high-priced oil.”

The report reiterated the view expressed in a Lawrence Livermore National Lab report in 2008 that UCG developers could target low-grade coal buried deep in seams too thin to be mined economically. It concluded that UCG technology could thus increase recoverable reserves threefold.

Indeed, according to the US-based National Coal Council, UCG opens the possibility of a 300-400% increase in recoverable coal reserves because it offers a means to tap the 90% of reserves that are too deep, thin or low-grade to mine, representing perhaps one of the last untapped reserves of cheap energy.

The science bit UCG involves pumping air or oxygen underground to gasify coal in situ into synthesis gas, which is then pumped to the surface. This avoids the costly energy, labour and the infrastructure required to mine and transport raw coal, gasify it, and then to dispose of mountains of ash.

With UCG, the ash remains underground. Greenhouse gases (GHGs) can be captured and pumped underground or sold for enhanced oil recovery (EOR). The synthesis is harnessed as a cheap way to make electricity, diesel, petrol, lubricants, or other high-value products that are often imported at high prices.

The UCG concept has been considered for decades. Conceived in the UK in the 1890s, UCG was first developed in the former Soviet Union in the 1920s, until it lost out to cheaper Siberian natural gas. During the oil embargo years of the 1970s and 1980s, several UCG tests were conducted by the US and in Europe.�

SEPTEMBER

OCTOBER

UCG potential could

match shale gas Underground coal gasification could follow shale gas and be the next step in the unconventional energy revolution, according to a new report By Kevin Godier � A new study by Zeus Development highlights the cost advantages of UCG � Ten new UCG projects have been announced this year, meaning 51 are under way around the globe � The environmental impact of the technology has the potential to derail its large-scale application






In the 1990s, China began UCG research and development, and it is continuing this effort, with some 30 UCG projects in different phases of preparation. India and South Africa have also heavily invested in the technology, owing to their vast coal resources.

But it is only recently that technological advancements in seismology, drilling and electronics have converged to make the UCG process economical. Recent cost estimates for UCG projects have come in at levels less than half of those of conventional coal-gasification methods and well below shale gas production costs. “[UCG offers] an amazingly low-cost avenue to monetise one of the last remaining vast energy resources – coal – cleanly and cheaply,” the Zeus report said.

It added that UCG costs per million Btu have been estimated by three autonomous studies to range from US$2.00–US$3.06, which is below shale gas market prices and well below shale

gas production costs. In November 2009 Australian

company Cougar Energy began developing a pilot project to generate power from coal that was still trapped underground, a pivotal moment that has been viewed as a key factor in reigniting interest in the 100-year-old unconventional energy technology.

Several independent energy companies such as the Australia-based Linc Energy, Wildhorse Energy and Cougar are now using technological advancements to push their UCG capabilities forward.

Currently, eight projects in Australia, China, Poland, Canada and Uzbekistan are under way, the report stressed, with sites being surveyed to build another 43

UCG schemes around the globe. All of these intend to target deep reserves that were previously considered as non-commercial, and to manage environmental risks, in part by capturing and sequestering greenhouse gases.

Environmental concerns Yet environmental issues remain the key obstacle to UCG’s evolution. In this respect, four fundamental environmental challenges were categorised by the report.

First, there is public concern about groundwater contamination or air pollution if UCG fires burn in an uncontrolled manner owing to oxygen encroachment into the underground gasification chamber.

Secondly, the potential liberation of toxic chemicals such as benzene, from coal into ash that may leach into groundwater supplies is a concern.

Thirdly, surface subsidence caused by the void left when coal seams are converted to ash and syngas has been flagged as a potential problem.

Finally, increases in GHG emissions caused by converting coal into syngas and the burning or chemically converting the syngas into fuels and chemicals has also been identified as a negative factor.

Public concern about groundwater contamination and seismology has been heightened by widespread fracking for shale gas in North America. Moreover, at least one UCG pilot project conducted in Wyoming during the 1970s resulted in environmental harm being caused owing to poor design, the report observes.

The report commented: “In a time when public outrage is frequent and familiar, UCG developers will face significant if not insurmountable challenges, where outcry can result in regulatory injunction. To mitigate these risks and win government approvals, developers will have to demonstrate that they are able to select coal reserves that will not incur groundwater contamination.�

OCTOBER






Their designs must limit subsidence, and their operations will have to monitor tightly and control hazards and permanently capture and sequester GHG emissions. Many UCG developers are confident these challenges can be met while providing developing economies low-cost fuels and chemicals.”

Moving forward An agreed strategy among developers is now to target coal seams at least 150 metres below the surface. Furthermore, in the UK, sites for all conditional licences are offshore, eliminating risks of fresh groundwater contamination, uncontrolled fires, or ill effects from

surface subsidence. While some proposed UCG projects are being proposed at depths greater than 1,000 metres, most nevertheless fall between 200-1,000 metres, the report pointed out.

It predicted that if UCG developers could guarantee effective means to manage environmental risks, “they will go a long way in offering an environmentally viable, low-cost solution to developing countries that wish to improve their standards of living.”

Furthermore, for developing economies such as India, Pakistan, Bangladesh, China, Poland – and even developed nations like the UK and the US – UCG offers an escape from their

dependency on foreign oil. “These countries are most likely to

recognise UCG solves more problems than it presents. Therefore, we forecast that UCG development will accelerate as long as energy supplies remain constrained and prices stay high,” said Zeus.

With the shale gale having blown through the global energy sector it now looks like other technologies such as UCG could follow in its wake. But environmental problems will always have the potential to put the brakes on progress.�

Gas-to-liquids (GTL) plants have tended to be large-scale high-priced investments and have struggled to make much headway, given the demanding project economics. However, a new breed of small-scale plants are coming to prominence and represent a new method of tackling the problems of handling associated gas.

The International Energy Agency (IEA) issued a report on the “Golden Age of Gas,” earlier this year, highlighting the potential of GTL to tackle flaring.

“Advances in technology suitable for small-scale application [could] be important, particularly in the use of gas that is currently flared. If one half of the estimated 134 [billion cubic metres] of gas flared in 2010 were used as GTL feedstock this could produce around

700,000 barrels per day of additional liquid hydrocarbon fuel,” the agency said.

One company competing to fill this gap is UK-based CompactGTL. “There’s an incredible amount of interest in this space, with all sorts of businesses springing up claiming to have made some kind of progress on small-scale GTL. We treat that with a lot of scepticism because it is really not that straightforward. We’re the only company that’s actually achieved it,” CompactGTL’s business development director, Iain Baxter, told UOGM.

“We are the only business that’s truly positioned to contemplate providing a solution to oil companies – and that’s reflected in how oil companies are coming to us and starting to fund

feasibility studies for projects.” GTL has typically been considered to

be a means of turning natural gas into high-priced liquid fuels. However, CompactGTL’s process is slightly different – instead of producing fuel it turns out synthetic crude, which can be blended with the natural crude at the point of production.

Baxter said the decision to produce syncrude helped make the economics of installing its technology in a given location easier.

“We’re not really in the business of GTL,” he said. “That’s the difference” between CompactGTL and the traditional GTL players. “We’re really in the oil business – our process enables further oil production.”�

OCTOBER

NOVEMBER

Moving GTL into the oil business CompactGTL has developed a small-scale GTL process to consume gas that might otherwise be flared By Ed Reed � CompactGTL’s technology is targeted at associated g as, and produces syncrude � The process would be applicable to offshore extende d well tests � The economic rationale for CompactGTL’s technology is bolstered where flaring caps are in place





The company, Baxter said, bases its technology on “oilfield economics” and as such “we have much lower sensitivities to some of the usual GTL economic factors.”

In terms of scale, CompactGTL’s process works best up to around 1.4-1.7 million cubic metres per day. “It’s a case of adding more modules,” Baxter said. “If you start to make the plant too big there will come a point where it doesn’t make practical sense – if you’ve got that much gas you start to reach the point where you wouldn’t need a modular approach.”

Floating GTL One area in which CompactGTL hopes to have success is offshore Brazil, where extended well tests are required for the subsalt. Baxter declined to give any details on the company’s plans with Petrobras.

The GTL company has been running an onshore 20 barrel per day test plant in Brazil for around nine months and has entered into a co-operation agreement with SBM on integrating the full GTL process into floating producing, storage and offloading (FPSO) units.

In order to achieve the optimal combination, he said, the GTL plant has to be designed as part of the FPSO from the beginning, rather than retrofitting the technology into such a unit.

“In terms of lead time for a typical FPSO, from the final investment decision [FID] it would take under 36 months – and certainly our GTL project plan would fall within that delivery timeline,” Baxter said. The company’s plan involves its strategic supply chain partners to ensure “the GTL plant isn’t the thing that holds up the FPSO project.”

Japan’s Sumitomo Corp. and Sumitomo Precision Products have signed up as manufacturing partners for CompactGTL – also investing in the company – and an unnamed catalyst provider has also joined up.

In addition to syncrude, the CompactGTL process produces an amount of tailgas and wastewater. These can be recycled back into the plant or treated, depending on the local legislative and client operational requirements. The GTL plant produces around one barrel of water – containing 2% alcohol and some trace oil – per barrel of syncrude.

The water can be treated to the extent where it can be used to generate process steam or to the point that permits local discharge, with the second option usually cheaper.

Water to feed the reforming reactors can be brought onboard via a desalination plant, which can use the low-grade heat generated from the Fischer-Tropsch process.

Costs for a plant capable of producing 1,000 bpd of syncrude were estimated by Baxter to be in the US$150-200 million range, although utility considerations and tailgas handling would play a large role in determining them.

“It’s how you integrate that plant with the rest of the production facilities: what else is there that can make use of the tailgas, can power be generated from that or do you have to have zero tailgas? If that’s the case then you have to recycle it and that makes the plant capable of producing more syncrude – but it also has a [capital expenditure] impact,” he said.

Liberated crude An area of particular interest for the GTL process is one described by CompactGTL as “liberated crude.” Baxter explained that this was of interest where a company was forced to deal with a legislative cap on gas use, for instance where flaring is prohibited.

Typically, he said, there will come a point where in order to meet such standards oil production will have to be shut in. “That’s not what the oil company wants and it’s not what the country’s government wants either, as it will lose tax revenue or profit oil,” Baxter said.

By not flaring the gas, a company can avoid shutting in production. It can benefit from the additional stream of syncrude but conforming to the gas use limit can allow far more crude to be produced.

Based on an associated gas-to-oil ratio (GOR) of 1,000 cubic feet (28 cubic metres) per barrel of crude, Baxter said treating 10 million cubic feet (283,000 cubic metres) without flaring could free up to 10,000 bpd of extra crude production – plus the 1,000 bpd of syncrude.

Working out how much such a plant would provide in terms of additional revenue would depend on a number of factors, such as the fiscal regime, but a US$40 per barrel netback would generate an additional US$150 million per year of additional revenue, Baxter said.�

NOVEMBER





“There are a range of projects and some don’t reach that level, but it can be very attractive. We feel that to drive small-scale GTL at current costs this has to be on the back of freeing up oil production,” he said.

The prospect of halting flaring and liberating additional crude is one that has received support from a number of sources in the industry. While CompactGTL appears to have made its most progress in Brazil, an official from Nigeria’s National Petroleum Investment Management Services (NAPIMS) told UOGM that the process would also be applicable to the West African state.

Nigeria is one of the world’s top flarers of gas and the government faces pressure

to reduce this wasteful practice. Efforts have been made to stop flaring but with little success, as the majors working in the country find it easier to pay the fines. In addition, Abuja previously demonstrated that it was unwilling to suffer a reduction in oil flows that would come about as a result of stopping flaring.

The NAPIMS official said the smaller companies operating in Nigeria would be the most likely to pick up the technology and predicted project finance would play a role in supporting its implementation.

Future facing CompactGTL hopes to be in a position where, in 10 years time, it will be

providing “multiple clients in multiple continents with different scales of plants, both on- and offshore, dealing with associated gas problems and enabling them to carry on with their oilfield activity.”

The first commercial order from CompactGTL will come “fairly soon,” Baxter predicted.

One area in which the company’s role will continue will be in servicing the GTL modules. Catalysts in the reactors do become less efficient as time goes by and Baxter said CompactGTL would provide a service of swapping out modules for refurbishing.�

Energy prices in Argentina are poised to rise in what could prove to be a boon for upstream investors in the country. The news comes as interest in Argentina’s unconventional oil and natural gas reserves begins to ramp up.

With upstream investment revitalised, Argentine Planning Minister Julio De Vido, the government’s chief energy architect, said last week that oil and gas prices would likely be reviewed.

“We will work with the Oil Industry Chamber to analyse putting a value on these resources,” he said.

The price increases will form part of a 2020 strategic plan for economic expansion that will be announced in the

next few weeks, he said. He cautioned that energy would be kept at prices thought beneficial for industry to compete against imports and in export markets.

“Not [every] price is good,” he said. “It has to be competitive.”

This is in line with the economic policies of Argentine President Cristina Fernandez de Kirchner and her late husband and predecessor, Nestor Kirchner.

They pulled the economy out of the crisis that crippled the country in 2001-02 with pro-growth measures, including controls that made gas and power price among the lowest in the world.

Residential consumers, for example, pay about US$0.50 per million British thermal units for gas compared with the US$3 per million Btu spot price in the US.

The low prices helped spur industrial output to power the economy, which has grown by an average of 8% per year since 2003.

But the low prices have proved hard to sustain, with the government over the past month cutting subsidies for public services – including gas – to safeguard state finances against a prolonged slowdown in the global economy.�

NOVEMBER

DECEMBER

Argentina ready to reap rewards of

its unconventional potential The growing interest in Argentina’s shale reserves is likely to revitalise the country’s oil and gas output and provide a boon to the government By Charles Newbery � Energy prices in the country – among the world’s lo west – could rise as the government seeks investors � Repsol’s chief believes US$28 billion should be inv ested in the development of shale resources in Neuq uen � A strong legal framework and regulatory environment is necessary to attract significant investment





The downturn could reduce demand and prices for its exports, in particular from China, the biggest buyer of its soybeans.

Argentina relies heavily on taxes – including those on soybean exports – to finance the state because it has not fully settled a US$100 billion debt default from 2001 to regain access to global capital markets.

The flipside is that without higher prices the country cannot develop its huge shale gas and oil resources.

Bouncing back Energy companies reined in spending after the 2001-02 economic crash ushered in greater state intervention, including the price controls as well as higher taxes, export restrictions and sudden regulatory shifts. This led to a plunge in oil and gas production and reserves, with crude output extending declines to hit 566,000 barrels per day this year, a third less than a record 847,000 bpd recorded in 1998. Gas production is down 13% to 125 million cubic metres per day from a record 143.1 mcm per day in 2004.

The dwindling output has led to energy shortages and a cutback in exports in order to feed the domestic market. Yet with the economic boom, the government has had to step up imports to meet demand – paying up to US$16 per million Btu for liquefied natural gas (LNG).

This has sparked calls for raising domestic prices to stem the decline in production, calls that have strengthened over the past year with estimates of the country’s huge shale potential.

The US Energy Information Administration (EIA) said in April that the country had 774 trillion cubic feet (21.9 trillion cubic metres) of shale gas

resources, far more than its 13.4 tcf (379.5 billion cubic metres) of proven conventional gas reserves.

YPF, which is backed by Spain’s Repsol, has already recently made major headway in the unconventional sector, discovering 927 million barrels of shale oil, with production from its shale assets ramping up to 5,000 bpd.

Price adjustments Oil companies say that while the domestic price of crude, which averages US$55 per barrel, is adequate for shale oil development, the natural gas price is too low.

It needs to be around US$6-8 per million Btu to take into account the hefty costs in drilling, hydraulic fracturing (fracking) and technological advances.

It appears the government wants to use the country’s shale potential as a springboard to develop drilling technology in Argentina and create new jobs.

“We will have a gigantic development in technology and in the metalworking

and steel industries,” De Vido said. This news is encouraging oil

companies. “The energy industry has a lot to do

and it has huge advantages that need to be [exploited],” said Andres Carosio, director of public affairs at Medanito, a Buenos Aires-based oil company.

Medanito has created partnerships with EOG Resources and Shell this year for shale oil and gas development in Argentina. The deals are for a total of US$1.2 billion in spending over the next five years in four blocks in Neuquen, a southwestern basin.

Yet such spending is small beer, according to some estimates.

Repsol’s CEO, Antonio Brufau, earlier this month said that US$28 billion should be invested in the development of shale oil resources in Neuquen.

Legal framework With big investment numbers being mooted by top-level executives, there is clearly a growing buzz about Argentina’s unconventional potential. The country’s

demand for gas – which currently stands at 120 million cubic metres per day – is growing, as are opportunities to export new production. The country also has one the most mature gas market in South America.

However, for investors to commit to developing Argentina’s vast shale resources, they require a strong legal framework and regulatory environment in which to operate.

“Investments in shale development so far have been moderate,” said Luis Giussani, an independent energy consultant in Buenos Aires. “Clear rules and legal security are needed for the investment to turn around the slide in reserves. There is a market for the production but Argentina is not the securest place to invest.”�

DECEMBER

UOGM 2011 Annual Review Back Page

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HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

Oil and Gas Sector

AfrOil The Kenyan government is mapping out seven new bloc ks in the Indian Ocean.

AsianOil Senior Thai government officials have visited Myanm ar to negotiate new gas concessions on behalf of PTTEP.

ChinaOil CNOOC is set to begin drilling its first well in Bl ock F offshore Cambodia’s southern coast.

EurOil Statoil will spend a total of US$5.84 billion on de veloping the Luva field in the Norwegian Sea.

FSU OGM Poland has urged Russia to invest in its own shale gas deposits.

GLNG Gazprom is to export 10 million tonnes per year of LNG to India from 2016.

MEOG Gulfsands Petroleum is continuing its Syrian explor ation work despite a halt in production.

Downstream MENA Total is in talks with QP to “significantly” expand the 146,000 bpd Ras Laffan condensate refinery.

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Unconventional Oil & Gas - 2011 Annual Review