OilVoice Magazine | April 2013

7/23/2019 OilVoice Magazine | April 2013

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Why are oil prices falling?

Report: Oil and gas opportunities in Southern Africa

Lower highs: The real trajectory of U.S. oil production

Edition Thirteen April 2013


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1 OilVoice Magazine | APRIL 2013

Issue 13 April 2013

OilVoiceAcorn House381 Midsummer BlvdMilton KeynesMK9 3HP

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EditorJames AllenEmail:[email protected]

Director of SalesTerry O'DonnellEmail:[email protected]

Chief Executive OfficerAdam Marmaras

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Adam Marmaras

Chief Executive Officer

Welcome to the 13th edition of theOilVoice Magazine.

This month's edition contains greatcontent like Oil supply glut demanddesert by Andrew McKillop, Will thefinal blow for America's shale gas'revolution' be high prices? by KurtCobb and "The New European Oil and

Gas Health and Safety Directive - whatare the implications for the UKCS?" byMalcolm Mackay.

Would your company like toadvertisein our next edition? Our rates are verycompetitive. Your advert will appearsandwiched between the industry'sbest content, and our other premiumadvertisers like TGS and RPS.Get intouchto learn more.

Happy reading!

Adam Marmaras

CEOOilVoice
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Contents

Featured Authors

Biographies of this months featured authors 3Innovative oil field equipment and strategies are reshaping industryby Paul Moore 5

Recent Company ProfilesThe most recent companies added to the OilVoice directory 8

Insight: The increasing use of Gravity Gradiometry in the ExplorationWorkflowby David Jackson

10

Transforming the dash for gas into a low carbon, sustainable industryby Tore Amundsen 17

Report: Oil & gas opportunities in North Africa and the EasternMediterraneanby David Bamford

20

Report: Oil and gas opportunities in Southern Africaby David Bamford 21

Will the final blow for America's shale gas 'revolution' be high prices?

by Kurt Cobb

22

Oil supply glut demand desertby Andrew McKillop 26

The New European Oil and Gas Health and Safety Directive - what arethe implications for the UKCS?by Malcolm Mackay

28

Insight: Global exploration for shale 'sweet spots'by David Bamford 33

Lower highs: The real trajectory of U.S. oil productionby Kurt Cobb 38

Why are oil prices falling?by Andrew McKillop 41


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Featured Authors

Paul Moore

Bakken Residence Suites

Paul Moore works with several housing providers and covers a variety ofbusiness topics. He works with Bakken Residence Suites, a corporatehousing provider in the booming oil region of North Dakota.

David Jackson

ARKeX

David has over 26 years experience in oil and gas exploration and production,and is a specialist in the integration of geology, geophysics and reservoirengineering.

Tore Admundson

Technology Centre Mongstad

Tore Admundson is Chair of Technology Centre Mongstad and CEO ofGassanova.

Kurt Cobb

Resource Insights

Kurt Cobb is an author, speaker, and columnist focusing on energy and theenvironment. He is a regular contributor to the Energy Voices section of TheChristian Science Monitor and author of the peak-oil-themed novel Prelude.

David Bamford

Finding Petroleum

David Bamford is 63. He is a non-executive director at Tullow Oil plc and hasvarious roles with Parkmead Group plc, PARAS Ltd and New EyesExploration Ltd, and runs his own consultancy.
http://bakkenresidencesuites.com/http://bakkenresidencesuites.com/http://www.arkex.com/http://www.tcmda.com/en/http://www.tcmda.com/en/http://resourceinsights.blogspot.co.uk/http://resourceinsights.blogspot.co.uk/http://www.findingpetroleum.com/http://www.findingpetroleum.com/http://www.findingpetroleum.com/http://resourceinsights.blogspot.co.uk/http://www.tcmda.com/en/http://www.arkex.com/http://bakkenresidencesuites.com/


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Andrew McKillop

AMK CONSULT

Andrew McKillop is a regular contributor to OilVoice.

Malcolm MacKay

Evaluate Energy

Malcolm Mackay is a Partner in Brodies Solicitors Aberdeen office,specialising in health & safety in the oil & gas sector.
http://www.evaluateenergy.com/http://www.evaluateenergy.com/http://www.lunarsafari.com/http://www.lunarsafari.co.uk/http://www.evaluateenergy.com/


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Innovative oil fieldequipment andstrategies arereshaping industry

Written by Paul Moore

Meetings with investors are nerve wracking for all involved. Figuratively speaking,anything can become a money pit. But when oil wells have more money thrown intothem than is returned it becomes a very stark reality that imprints itself on the retinasof company executives and investors alike.

Costing hundreds of thousands of dollars if not millions an oil or gas well is amajor investment by any measure. And when it comes up dry, the results can bedire. However, in recent years equipment innovations have allowed for newstrategies which are paying off with dramatically increased oil and gas production aswell as environmental benefits.

Better Underground Imaging

In medicine three-dimensional imaging using MRI and ultrasound technologies isimproving healthcare in every facet of exploration into the depths, contours, andcapacities of the human body. The same is true for3D seismic imaging techniquesthat give geologists a better idea of whether or not a given rock formation has thepotential to bear oil or gas. It has revolutionized oil and gas exploration by enablingoptimization of functionality in the depths of wells in all ranges of geologicalformations. Complex regions that have in the past proven challenging to maintain,are now regulated and functioning at high capacity. Facts and data are easilyassessed and evaluated and production is increasingly streamlined.

Now geological areas that have complex substructures can be explored. Forexample,salt formations cause huge problemsfor two-dimensional imagingtechniques but are dealt with handily when the new 3D systems are employed. Beingable to get a better understanding of what's happening thousands of feet below thesurface results in drilling fewer dry holes. And when a clearer picture of the geologyis combined with new drilling capabilities, operations become even more efficient.

New Directions in Drilling

Slant drilling in oil fields has been around since the 1930s, but advances made in the

1970s made it measurably more practical and much more common. It was slantdrilling, at least in part, that led to Iraq's 1990 invasion of Kuwait when Saddam
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Hussein accused the Kuwaitis of slant drilling into Iraqi oil reserves. After the war,theborder was redrawnto bring the oil field into Kuwait. Fortunately, despite theoften-heated debate about U.S. oil drilling, things don't get quite that fractious in thestates.

It was after the U.S. Naval Facilities Engineering Service Center in Port Hueneme,Californiasuccessfully ran horizontal drilling testsin 1993 that things really started tochange. Water drill bits and pipe innovations successfully allowed drillers to gosideways for the first time.Oil and gas deposits are much bigger horizontallythanvertically, so this was a game changer.

One of the immediate benefits was that horizontal drilling allows oil and gasdevelopers to accessdeposits under environmentally sensitive landwithout havingto erect drilling rigs on the land itself. Also, one horizontal well can sometimes beused instead of several vertical wells, which significantly lessens environmental

impact. Horizontal drilling in combination with hydraulic fracturing (fracking) has ledto the oil and gas boom in the Bakken Formation area of North Dakota and Montanaas well as increased production in Texas and Pennsylvania.

Mixing Oil and Water

Offshore oil production continues to be an important component of U.S. energyproduction, and Morningstar named Merrill (Pete) Miller Jr. of National Oilwell Varcoits "2012 CEO of the Year" in large part as a result ofinnovations he has made inoffshore oil rigs.

Miller recognized a major problem with offshore oil rigs they were virtually allcustom designs. There was little or no standardization. Taking a page from Henry
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Ford's playbook, Miller realized that if the rigs could be standardized, it woulddramatically decrease costs.

Along with creating standard cabins, rails and derricks, Miller went further. Just like acomputer has an operating system that enables it parts to work together, so does an

oil rig. Miller standardized the oil rig operating system. This resulted in moreproductive and efficient day-to-day operations and made repairs significantly lessexpensive.

It was the near magic formula to produce much more profitability, allowing increasedinvestment and exploration. At the same time Miller was making his improvements,the fleet of offshore rigs was aging, and oil prices were starting their dramatic rise.The company he leads became the "go-to" guys for new oil rigs.

National Energy Policy

While politicians from both parties debate national energy policies, it's interesting andimportant to note that it's innovation and evolution within the industry itself that haveperhaps the biggest effect on domestic oil and gas supplies.

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Recent Company Profiles

The OilVoice database has a diverse selection of company profiles, covering new

start-up companies through to multi-national groups. Each of these profiles featurekey data that allows users to focus on specific information or a full company reportthat can be accessed online or printed and reviewed later.Start your search today!

Kitsault EnergyLNG

Kitsault Energy is a company dedicated to theestablishment of a Liquefied Natural Gas(LNG) Plant and Energy Export Terminal atthe site of an abandoned mining town on

Observatory Inlet, one of the northernmostfiords on Canada's west coast.

Kitsault Energy's OilVoice profile

Venari ResourcesExploration

Venari Resources is a privately held offshoreexploration and production company foundedin 2012 by deepwater E&P expert BrianReinsborough.

Venari Resources' OilVoice profile

Dakota PlainsService

Dakota Plains Holdings, Inc., a Nevadacorporation, was founded in 2008 for thepurpose of developing and owningtransloading facilities throughout the WillistonBasin oil fields of North Dakota.

Dakota Plains Holdings' OilVoice profile

CaiTerraOil & Gas

Caiterra International Energy is a publiclytraded oil and gas company pursuingacquisitions of international oil and gasexploration and production opportunities.Caiterra has currently built a significantportfolio of land positions in Alberta,specifically in the Faust, Lac La Biche andAmadou regions.

Caiterra International Energy's OilVoice profile

JP Energy PartnersService

JP Energy Partners brings years of collectiveexperience working within the energy industry.The company is creating a portfolio ofdiversified midstream services that support an

integrated refinery services solution. They ownand operate assets that play an integral role inproviding midstream services throughout theSouthwest and Midcontinent of the US,including supply and logistics, terminal andstorage services, and wholesale and retailmarketing.

JP Energy Partners OilVoice profile

Union Jack OilOil & Gas

Union Jack Oil plc joined the ISDX GrowthMarket in December 2012 as a vehicle toidentify drilling, development and investmentopportunities in the hydrocarbon sector.

Union Jack Oil's OilVoice profile

Impact Oil & GasOil & Gas

Impact Oil & Gas has built a portfolio ofunderexplored blocks in geologically

prospective frontier areas off southern Africa.The company has one of the largest holdingsoffshore South Africa [for a private company]which currently consists of 75,991 squarekilometres. The board seek to further increaseImpact's footprint in the region as the currentportfolio is progressed and developed.

Impact Oil & Gas' OilVoice profile
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rpsgroup.com/energy

Health, Saety, Environmentand Risk Management

RPS Energy is a global multi-disciplinary

consultancy, providing integrated technical,

commercial and project management

support services in the felds o geoscience,

engineering and HS&E.

Contact

James Blanchard

T +44 (0) 20 7280 3200

E [email protected]


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Insight: The increasinguse of GravityGradiometry in theExploration Workflow

Written by David Jackson fromARKeX

Overview of Full Tensor Gravity Gradiometry

Gravity gradiometry is the study and measurement of spatial variations in theacceleration due to gravity. The gravity gradient is the spatial rate of change ofgravitational acceleration.

Gravity gradiometry data is used by oil, gas and mining companies to measure thedensity of the subsurface, effectively the rate of change of rock properties. It offers astep change in resolution and bandwidth from that of conventional airborne gravitydata. The acquired gravity gradiometry data assists in the building of sub-surfacegeological models to aid exploration.

What is it?

Gravity gradiometry measures the variations in the acceleration due to gravitybetween two or more points. The gravity gradient is the spatial rate of change ofgravitational acceleration. It can be deduced by differencing the value of gravity attwo points separated by a small distance and dividing by this distance. The twogravity measurements are provided by accelerometers which are matched andaligned to a high level of accuracy.

Simplified Explanation

An accelerometer is basically a mass on a spring. A gravimeter measures theacceleration of the mass due to gravity. In Figure 1 below, the gravity gradiometermeasures the acceleration of Mass A and B. The difference in acceleration is thencalculated and divided by Distance C. That figure is the gravity gradient.

Figure 1. - Simplified view ofGravity and GravityGradiometry
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Full Tensor

While a conventional gravity survey records a single component of the three-component gravitational force, usually in the vertical plane, Full Tensor GravityGradiometry uses multiple pairs of accelerometers to measure the rate of change of

the gravity field in all three directions. The end result is a more accuraterepresentation of the gravity field being surveyed. This is shown in Figure 2.

Fig. 2. Conventional gravity measures ONE component of the gravity field in thevertical direction Gz (LHS), Full tensor gravity gradiometry measures ALLcomponents of the gravity field (RHS)

Gravity v Gravity Gradiometry

In addition to measuring the entire gravity field about any given measurement point,Gravity gradiometry has two other major advantages over conventional scalargravimetry which results in a significant increase in resolution and accuracy.

Firstly being the derivatives of gravity, the spectral power of gravity gradient signalsis pushed to higher frequencies. This generally makes the gravity gradient anomalymore localised to the source than the gravity anomaly. The graph (Figure 3)compares the gz and Gzz responses from a point source.

Figure 3.

Vertical gravity and gravity gradient signals from a point source buried at1 km depth


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Secondly, and perhaps more importantly, the effects induced by platform motion (i.e.air turbulence or heavy sea state) are strongly suppressed. On a moving platform,the acceleration disturbance measured by the two accelerometers is the same, sothat when forming the difference, it cancels in the gravity gradient measurement.This is the principal reason for deploying gravity gradiometers in airborne/marine

surveys where the acceleration levels are orders of magnitude greater than thesignals of interest.

Due to these factors gravity gradiometry offers a significant increase in resolutionand accuracy over conventional scalar gravimetry.

Case Studies

East Africa: Reducing Exploration Timelines with Full Tensor GravityGradiometry

East Africa has received its fair share of exploration attention over the past fewyears. The discoveries in Uganda in the Albertine basin have instigated significantexploration enthusiasm in this vast region, as have the licensing of vast tracts of land(and lakes) in Ethiopia, Kenya, Malawi and Tanzania. Tullow Oil and its partnerAfrica Oil have already been reporting encouraging results with their first well inKenyas Block 10BB demonstrating a working petroleum system in the region.

The challenges in these frontier areas are enormous, however - vast tracts of remoteexploration acreage with limited or no data coverage to explore and against an everchallenging time line. Against this backdrop, Full Tensor Gravity Gradiometry (FTG)is fast becoming a recognized technology addressing many of these challenges.

The East African geology, essentially comprising relatively young sedimentsjuxtaposed against a much denser Achaean basement, is ideally suited to the use ofthis gravity exploration technique. FTG measures the variations of the Earths gravityfield with such a high degree of resolution and bandwidth that detailed basementstructure maps can be derived which, in turn, allows for the optimal positioning of theseismic campaign.

The challenge in positioning seismic blindly in say a 10,000 square kilometre block,however, is fraught with difficulties. Poorly positioned lines may not image the

geology optimally and potentially condemn a vast area as being non-prospective.Being an airborne technique, an FTG survey can be acquired efficiently and rapidlyover large areas and thereby focus the seismic budget. The environmental footprintis also negligible.

Other advantages of deploying FTG in the unique exploration setting of East Africainclude an improved definition of the sedimentary basin and internal architecture;and the identification of structural leads which can become a focus for seismicacquisition.

The early seismic in the basin can also be calibrated to the FTG and if necessary,

the seismic programme can be altered in places of shallow basement or insufficientdepth of burial of potential source rocks.


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Modelling the East African Rift

In order to show how gravity gradiometry can be used in a Rift system, a 2D crosssection was created from existing seismic data and then extruded into the Y-directionto generate a pseudo 3D model (Figure 4). The model was then offset to simulate

strike-slip faults and the conventional airborne gravity and gravity gradiometryresponse calculated (Figures 5 & 6).

Figure 4. Pseudo 3D model with simulated strike-slip offsets

Broad basement geometry is imaged with conventional airborne gravity, but detail ispoor. Strike-slip movement is only imaged where the basement is very shallow.

Figure 5 (top): Conventional gravityFigure 6 (bottom): Gravity Gradiometry

With the gravity gradiometry data deeper basement blocks are imaged as well asstrike-slip motion at depth. The FTG generates such positive and clear results fromthe rift due to the inherent way the technology works. It can accurately map thecontrast between the basement and sediment cover and pick up the architecture ofthe rift in considerable detail.

Full tensor gravity gradiometry has been proven to be an important tool in gaining a


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clear picture of the East African Rifts geology, decreasing exploration disk andincreasing exploration success.

NE Greenland: Integration of regional 2D seismic and full tensor gravitygradiometry

Three phases of 2D seismic acquisition and PSDM processing were completed byION GeoVentures from 2008 to 2012. The objective was to provide a regionalevaluation of the untested NE Greenland Atlantic passive margin (Helwig et al,2012). In 2012 ARKeX completed an airborne Full Tensor Gravity (FTG) survey forIon over the area for both the pre-round blocks open to the KANUMAS Group andthe blocks for the 2013 Greenland Licensing Round. (Figure 7)

The FTG survey is the largest ever acquired offshore and covers 50,000 sq.km. Thehigh resolution gravity gradiometry and magnetics have been integrated with theNortheast GreenlandSPAN seismic data to enhance the understanding of frontier

basin architecture, and in reconciling the linkages of the inherent tectonic fabrics.From these data a higher resolution 3D structural model of the Northeast Greenlandmargin can be built in order to guide structural interpretations and the implications forpetroleum systems on this margin.

Figure 7: Tectonicelements of the NEGreenland Margin andlocations of the IonGreenlandSPAN seismicand the full tensor gravitygradiometry survey


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The prospectivity of the northern part of the Danmarkshavn Basin is likely to beheavily influenced by the presence and shape of salt bodies. Prior to the acquisitionof the FTG survey over 25 individual diapirs had been mapped using Ions highquality PSDM seismic volume. However, even though the seismic quality isexcellent, it is classed as a regional frontier survey with distances of over 50km

between some lines. Modelling of the gravity gradiometry, and its integration with theseismic, has enabled the building of a 3D architecture of the salt and associatedsedimentary packages in areas away from seismic control. In addition to saltgeometries, fault linkages have also been extrapolated away from seismic control.Magnetic data analysis has also led to a better understanding of the basementcomposition, which along with fault linkages, allows models for reservoir fairwayanalysis to be progressed.

Benefits for regional exploration programs

Improved definition of sedimentary and internal architecture Identification of structural leads which can become the focus for further

seismic acquisition early seismic in the basin can be calibrated to the FTG and if necessary, the

seismic program can be altered in areas of shallow basement or insufficientdepth of burial of potential source rocks

a fast and efficient way of exploring vast exploration acreage

References:

James Helwig J.H., Bird, D.; Emmet, P.; Dinkelman, M.G.; and Whittaker, R. (2012)Interpretation of Tectonics of Passive Margin of NE Greenland from new seismicreflection data and geological-geophysical constraints. Third Conjugate MarginsConference, Dublin, 2012.

Jackson et al (2013) The Sky Above, the Ice Floes, and the Earth Below. Geo ExProFebruary 2013

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Transforming the dashfor gas into a lowcarbon, sustainableindustry

Written by Tore Amundsen fromTechnology Centre Mongstad

The boom in shale gas has taken up full pace due to the vast volumes available andcheap cost, even using unconventional fracking methods for excavation. Many havealso asserted the properties of gas as the cleanest fossil fuel as rationale for lockingin widespread shale gas production. However, in many cases, the claims of gas as asustainable fuel are overstated. Certainly, gas burns cleaner than coal. It alsoensures a constant supply of power unlike intermittent wind or solar. Yet theIEAreports that already two thirds of global carbon reserves are related to coal, 2% to oiland 15% to gas. With global energy demand expected to double in the next 20years, so will the relative environmental impacts, in terms of carbon emissions.

Locking in fossil fuel as we enter a carbon constrained world

According to the IEA, the US, which has been making headway in reducingemissions (if it had ratified the 1997 Kyoto protocol it would have now met itsobligations), now stands to become the worlds largest gas producer by 2015. By2035 nearly half of US gas production is expected to come from shale gas, up fromaround a quarter in 2010.

Countries such as the UK may also benefit from shale gas, providing space can befound to support the necessary infrastructure. For example, it is possible that theUKs 1,000 square kilometer Bowland Basin may contain 300 trillion cubic feet of gas- the equivalent of 17 times as much gas as the North Seas known remaining

reserves.

It is predicted that fossil fuels will account for 60% of energy generation by 2030. So,the wholesale replacement of fossil fuels with renewable energy, such as solar andwind power, before 2030 is unrealistic, especially when the lower price of gas makesit harder for renewables to compete on short terms costs alone. But can the impactof the dash for gas be measured on excavation and importation costs alone?

Closer investor scrutiny on high carbon investment

Although the short term odds may stack up in favour of gas, there is increasing

awareness amongst investors that the huge reserves of coal, oil and gas held bycompanies are sub-prime assets. According to theCarbon Tracker Initiative, 80 per
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cent of fossil fuel investments are effectively unburnable, since doing so would blowlegally binding greenhouse gas emissions budgets. In January 2013, marketanalysts at HSBC warned that oil and gas majors, that they could face a loss inmarket value of up to 60%, should the international community introduce globalmandatory emissions reduction targets. But even in the absence of a global

mandatory agreement on carbon, the direction of travel for the fossil fuel industry istowards increased carbon compliance.

With the dash for gas effectively boosting an already overblown carbon bubble, itsup to the gas industry itself to decarbonise the supply to safeguard its place as aprimary global energy source.

Transforming gas into a low carbon fuel

The only way to effectively decarbonise our gas supply, by up to 90%, is throughCarbon Capture & Storage (CCS) by effectively trapping the carbon dioxide at its

emission source, transporting it to a storage location underground) and isolating it.The International Energy Agency has estimated that as much as one fifth of totalrequired carbon emissions reductions will come from CCS by 2050.

The rewards are there for those gas generators that invest, in terms of jobs createdin this new industry. In the UK for example, a leader in CCS, research by the CarbonTrust found thatCCS industrial developmentcould contribute 3-16bn to UK GDPcumulatively to 2050. Furthermore, as well as enabling generators to benefit from therise in cheap unconventional energy, such as shale gas, CCS allows countries tosimultaneously avoid penalties for missing legally binding carbon targets.

Generators have been capturing and transporting CO2 gases in large-scale plantsfor decades; which has been utilised in enhanced oil recovery, as well as theproduction of carbonated drinks. But the fact remains that unlike other nowmainstream low-carbon technology sectors, such as wind and solar, CCStechnologies do not currently exist at commercial scale. Currently, carbon capture iscostly; the GCCSI estimates that each Mwh supported by CCS costs energygenerators an additional $50 - $100, as well as substantial capital costs fordevelopment.

However, if the funds saved on cheap gas can be reinvested into setting up this

infrastructure, generators will answer the problem of oncoming carbon regulation,whilst also creating a new industry for the future.

Industry is already rising to the challenge, Chevron, Shell and ExxonMobil havepartnered on the Gorgon initiative in Australia, the worlds largest CCS project. It hasbeen set up to enable natural gas to travel through undersea pipelines to a liquefiednatural gas plant on nearby Barrow Island. Once injection operations are at fullcapacity in 2015, 3-4 million tonnes a year of naturally occurring CO2 produced withthe natural gas will be captured and injected into a deep sandstone formation 2.5kilometres beneath the island. Significantly, once complete, Gorgon has anestimated lifespan of at least 40 years.

Technology testing is a vital route for verifying and demonstrating capture
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technology, which in turn can reduce costs, plus technical, environmental andfinancial risks, thereby creating the preconditions for success. The UK EnergyResearch Council (UKERC), which spent two years researching the means forestablishing CCS as a mainstream technology, came to the same conclusion: aregulatory approach making CCS compulsory in all fossil plants will only work if the

technology is more advanced. By bringing costs down and making the market viable,technologists provide a basis for global energy policy and investment.

To meet the need for testing, test centres have been developed on a major scale;allowing the safe simulation of carbon capture. CO2 Technology Centre Mongstad isthe most advanced of these, offering the ability to capture 100,000 tonnes of CO2 ayear, from post combustion oil, coal and gas-fired sources, as required. Crucially,TCM is the only large scale test centre providing gas fired carbon emissions fortesting, and so in the current times has a unique significance.

Reinvestment in CCS is critical to a sustainable gas industry

With CCS creating a solution to the predicted exponential rise in gas-fired emissionsfrom shale gas, it is up to the gas industry to invest in the technology now, to enablegas profits to be maximised in the future, whilst simultaneously mitigating carbonemissions.

There are no quick fixes to this issue, the lower prices of unabated gas should beviewed as a stepping stone to decarbonise this fuel for the future, throughreinvestment of savings. Certainly the prospect of cheap gas stands to liberate usfrom energy conflicts and increase energy self-sufficiency and importation for manycountries. But unless steps are put in place to limit the carbon impacts of gasthrough CCS, the industry will be locked into a situation where rising emissionsoutstrip our ability to adapt to the climate change they will cause.

View more quality content fromTechnology Centre Mongstad
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Report: Oil & gasopportunities in North

Africa and the EasternMediterranean

Written by David Bamford fromFinding Petroleum

What exploration opportunities are there in North Africa and the EasternMediterranean, from Morocco via Algeria and Libya to Egypt and Lebanon?

Below ground, these countries show different stages of exploration maturity.

Offshore Morocco has been quite active in leasing terms recently and is perceivedas a Frontier province.

Algeria has always been open and now most plays and basins look quite Mature inexploration terms.

For Libya, one would say that the Offshore is also a Frontier province. Onshore,whilst there is a long history of exploration and production, not all the significantbasins have been equally explored, and there is a case to agree that explorationhas, for the past several decades, not benefitted from the latest technologies.

Similarly to Algeria, Egypt has always been open and most plays look quite Maturein exploration terms, although again there is a case that some modern technologiesstill have a role to play for example sub-salt imaging in the Gulf of Suez and FullTensor Gravimetry onshore.

And the Eastern Mediterranean Frontier has seen considerable excitement in the last

year or two, with major - in fact, huge - gas discoveries; an 'exploration Spring' is wellunder way.

Above ground, of course there are some significant issues to contemplate, inparticular with political and security stability still to result in Libya and Egypt in thewake of the Arab Spring. And recent events in Algeria have cast a dark shadow.

Our Feb 12th 2013 Finding Petroleum Forum examined whether or not we shouldanticipate an imminent exploration Spring in the region, in particular whether furtherlarge discoveries can be foreseen, and if so, where?

Or should we anticipate a deep Winter, in which only the biggest companies arewilling to take the risk of exploring and operating in the region?
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For the proceedings of this Forum, including videos of complete presentations andslide packs, pleaseclick here.

View more quality content fromFinding Petroleum

Report: Oil and gasopportunities inSouthern Africa


On 9th January 2013, Finding Petroleum ran a special event with the support of theSouth African dti, from the High Commission of South Africa

The event reviewed the scope for oil & gas exploration and production in SouthernAfrica, including Nambia, Mozambique, Tanzania and South Africa.

The sensible starting point was to consider the large gas resources that have beenreported for Mozambique and Tanzania. When will these be converted to reservesand when might we see production, from the putative LNG schemes?

Given the large amount of global LNG-scale gas that has recently been discovered,not least in the USA, perhaps the earliest offshore gas production (fromMozambique) lies beyond 2020 and a categorisation as reserves must await the f irstsigned gas contracts (as Shell discovered, to their cost, in Nigeria almost 10 yearsago). Perhaps the earliest gas production will in fact be from onshore South Africa(for example, shale gas, or coal bed methane plays associated with South Africa'smassive coal reserves) or perhaps small discoveries onshore in Tanzania?

Offshore oil discoveries may reach production relatively rapidly. Are there 'oily'exploration opportunities in the region, for example, is the Namibian sub-salt playequivalent to, or at least similar to, the prolific plays offshore Brasil? And what about

South Africa itself; do offshore its East Coast or perhaps the Orange River Basinoffer soon-to-be discovered oil?
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If the oil and gas industry develops in Southern Africa, it means there will be a needfor a range of services, particularly engineering contracting. Additionally, access tolarge amounts of gas could drive the growth of a domestic chemicals industry.

South Africa itself offers access to skills and general infrastructure, including portfacilities. UK companies seeking opportunities in South Africa might be able to takeadvantage of the bi-lateral UK-South Africa Trade Agreement which aims to doubletrade between UK and South Africa by 2015.

For the proceedings of this Forum, including videos of complete presentations andslide packs, pleaseclick here.


Will the final blow for

America's shale gas'revolution' be highprices?

Written by Kurt Cobb fromResource Insights

As U.S. natural gas prices flirt with the $4 mark, some skeptics of the so-called shalegas revolution think prices are headed much higher. Such a move would, notsurprisingly, seriously undermine the official story that the United States has acentury of cheap natural gas waiting for the drillbit.

Several years ago when natural gas began flowing in great quantities from deepshale deposits beneath American soil, it seemed to be the beginning of the end ofAmericas troubled journey into dependence on energy importsa journey markedby frequent worry, occasional war and enormous expense.

But, to some people this supposed solution to Americas energy needs has begun to
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seem as costly to the environment and human health as the countrys dependenceon imported energy has been in terms of mental distress, money and blood. It turnsout that this new kind of natural gas requires the industrialization of the countrysidein order to extract it. And that, say those closest to the action, risks tainting air, land,and drinking water and compromising the health of humans and animals alike.

Well, at least we can say that shale gas is plentiful, cheap, American, and mucheasier on the climate than coal or oil. It didnt take too long before people startedlooking into whether shale gas really was that much easier on the climate.A CornellUniversity researcher came to the conclusion that shale gas was probably worse forclimate change than coal. His conclusion hinged in part on what are called fugitiveemissionsunintentional, but unavoidable releases of unburned methane into theatmosphere during thehydraulic fracturingoperations performed to extract the gas.Methane issome 20 times more potentthan carbon dioxide as a greenhouse gas.

Naturally, the oil and gas industryresponded vigorouslyto the researchers findings

with its usual ad hominem attacks. But, it also highlighted uncertainties that arealways part of any scientific study. This industry is, of course, the same one that hasconsistently denied the existence of climate change and continues to spend millionstrying to convince the public that climate change either isnt happening, or if it is, itwont be that bad or if it is, it may actually be good for us.

The industrys response to the study has, not surprisingly, been met with skepticism.That is befitting an industry that, having spent the last two decades denying climatechange, now suddenly embraces it as a reason to produce more natural gas. So,despite the industrys best efforts, the meme that shale gas is worse than coal is outthere and being repeated again and again by opponents of shale gas drilling.

Well, at least we can say that shale gas is plentiful, cheap and American. But, thencamethe industry campaign to end federal limitations on the export of natural gas.What had been touted by the industry as a fuel that would help lead America toenergy independence would henceforth be treated as just another world commodityseeking the highest biddereven if that bidder is in China, Japan or Great Britain.The industrys aim, of course, is to get higher prices for its product than customers inthe United States can provide. As noted above, natural gas trades at around $4 perthousand cubic feet (mcf) in the United States. That compares to about $17 per mcffor liquefied natural gas delivered to Japan. The price in Europe is around $12.

Well, at least we can say that shale gas is plentiful and cheap. As natural gas pricesdeclined from double digits in 2008 and the shale gas boom proceeded apace, theindustry convinced Americans that cheap, plentiful natural gas was the countrysfuture for a century to come. And, when natural gas prices plunged briefly to $1.82per mcf last April, even the oil and gas industry began to wonder whether cheapnatural gas was really such a great thing. At that price or anything below about $2.50really, almost no wells were profitable.

Last year independent petroleum geologist Art Berman, while reviewing the financialwreckage of the once flourishing, but now fallen shale gas drillers,noted that the

industry was based on:
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an improbable business model that has no barriers to entry except access to capital,that provides a source of cheap and abundant gas, and that somehow also allows forgreat profit. Despite three decades of experience with tight sandstone and coal-bedmethane production that yielded low-margin returns and less supply than originallyadvertised, we are expected to believe that poorer-quality shale reservoirs will

somehow provide supe

As Berman noted back then: Improbable stories that great profits can be made atincreasingly lower prices have intersected with reality. The industry proceededtoabandon shale gas plays in favor of tight oil playswhich have proven to be profitablewith oil prices consistently crisscrossing $100 a barrel in the last two years.

Apparently, price does matter when it comes to natural gas. And so, it seems naturalgas wont be endlessly cheap in America after all. As Berman foretold inan earlierpiece, prices would have to rise to between $5 and $6 to make currently paid-forleases profitable from this point forward and between $7 to $8 to make new leases

worth pursuing. For comparison, back in the heyday of cheap natural gas, thedecade of the 1990s, the average annual U.S. price was $1.92 per mcf,accordingthe U.S. Energy Information Administration.

So what exactly has happened to U.S. natural gas production as reality has set inand companies have withdrawn drills to await prices that might actually beprofitable? The answer ought to be troubling to those who are counting on endlesslyescalating supplies large enough to displace the majority of oil and coal used in oureconomy. To wit,U.S. marketed natural gas production has been almost flat for thelast two years.

The trend is so ominous that two industry insiders I know believe that U.S. naturalgas production could actually start declining soon and send prices soaring. They saydrillers have fallen so far behind that it will be impossible to make up for productionlost from existing shale gas wells. Those wells typically see production decline ratesof 85 percent after two years. (Translation: Some 85 percent of existing productionfrom shale gas wells must be replaced every two years BEFORE production cangrow.)

The future is, of course, unknown to us. But, the present and the past suggest thatthe so-called shale gas revolution is about to be laid to rest. Yes, shale gas might

prevent total American natural gas production from dropping off a cliff even asconventional natural gas production continues to decline. And, at some point shalegas might even allow U.S. production to rise modestly above current levels. But, twothings are now abundantly clear: It wont be easy and it wont be cheap.

View more quality content fromResource Insights
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Finding big oil & gas fields in South East AsiaThe Politics may overwhelm the Geoscience!London, 14 May 2013

Delivering well integrityHow best to manage well integrity - errant technologies, new technologies?London, 22 May 2013

Developments with FPSO operationsBetter ways to make decisions about specifying and operating FPSOsLondon, 04 Jun 2013

Russia & the FSU- plenty of opportunities below ground, plenty of problems above ground!London, 18 Jun 2013

Exploiting deep water fields

....it's not as easy as explorers think!London, 19 Sep 2013

Exploring internationally for unconventional oil and gas.......finding the "sweet spots"London, 02 Oct 2013


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Oil supply glut demanddesert

Written by Andrew McKillop fromAMK CONSULT

THE HIGHGROUND VIEW

Understanding why oil markets are "sticky for prices" needs a look at the basics. Oilmarkets are among the most liquid, most traded and most sought after - not only byinvestors, traders and hedgers, but also by economic and monetary policy makers ofthe world, due to the geopolitical sentiment that runs alongside oil. This highground

can, and often does shade the basic supply-demand energy role of oil to an also-ran,but this has limits.

What we know for sure is oil's role in world energy has declined - not crashed butdeclined - on a constant long-run basis, almost unrelated to annual or multi-annualaverage prices. In 1973 oil supplied about 53% of world energy, but today it providesabout 32%. By 2020, it may supply only 27%. This, for starters, should take thecrisis-word out of oil analysis.

When we look at who are the suppliers, the classic approach splits suppliers intoOPEC and Non-OPEC (or NOPEC) countries, the same way that classic analysisdivides global demand into OECD (developed world) and Non-OECD (emerging anddeveloping world) countries. This again creates problems, today, due a large numberof factors, ranging from resource and technology issues, to market and tradingissues.

The supply-demand driven market theory would deliver predictable price change,that is if demand > supply, prices go up, and if there is slack demand and supplybuilds a glut, prices come down. This is already glaringly different from the "stickymarket" which characterizes what we have.

Basic economic principles do operate, but with huge distortions - and this also is onekey reason why oil's share in world energy has been declining, now, for 40 years.Since at latest the 1980s, oil is a heavily traded commodity with volatile, rapidlychanging, often distorted prices, more often than not. It can also become an "assetbubble", with its price almost unrelated to supply-demand fundamentals, the mostrecently in 2005-2008, and arguably since 2011.

SUPPLY-DEMAND AND SLOW ECONOMIC GROWTH

Oil was for decades "the swing fuel" whose demand was a bellwether for theeconomy. If the GDP number rose by 4%, oil demand would automatically rise by

3%. But if the GDP number does not rise at all, or stumbles forward at anemic ratesbelow 2% a year (with outright contraction in Europe), oil demand growth is almost
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impossible to envisage. Oil demand will contract faster than GDP.

Making this even more sure and certain, we have had decades of "anti-oil" energypolicy, recently joined by "carbon consciousness" in the OECD group, andincreasingly in Emerging and developing countries. One example is the oil share of

electric power generation: in most OECD countries, today, this weighs in at around1%. In some lower-income developing countries however, it can still take 33% - 50%of power generation: reducing this share is a recognized major economicopportunity.

On the supply side, Non-OPEC countries heavily dominant world roduction but nottraded supplies. OPEC countries are the reverse of this paradigm: they produce lessof world oil, but supply more of the oil that is traded and crosses at least one nationalboundary. OPEC's share of global traded oil is a prized metric for oil price analystsand forecasters, to be sure, but this metric is distanced by the pace of world crude-versus-refined oil market operations. One example is the USA's ever growing refined

products exports (now about 2.6 million barrels/day). Another concerns the hugeoverhang of European oil refining capacity: one result of this might be unexpected, asoftening of refined product prices, a compression of light-heavy crude pricespreads, migrating upstream to soften crude oil prices.

OPEC's quota system, also, is a prized metric for price forecasting, but here againthe mix and mingle of technology, industrial, market and political issues and factorsmake this a cloudy gauge. The biggest supply-side reason is the exclusion of Iraqfrom any quota limitation, and Iraq's oil production capacity which is growing rapidly.Quota system, to be sure, also means quota cheating and this translates "on theground" to havily volatile production runs and net export capacities, or "offer", fromthe majority of OPEC member states. Basic logic, however, tells us that in a globalenvironment of very slow oil demand growth - current IEA forecasts are around 0.8%for 2013 - quota discipline will tend to erode, and when market prices also erode, theprocess can self-reinforce for some while.

OIL STOCKS AND PRICES

The key metric, managed by the IEA is days-of-average-demand oil volumes storedin the OECD group, broken down to US/Europe/Asia-Pacific. This metric, however,rarely changes significantly, for reasons which include the simple physical capacity

of storage, as well as its opportunity cost. The metric is often given high-profiletreatment, to be sure, within market trading strategies, for example if most recentstock data shows OECD stored oil shrank from say 57 days, to 56 days demandcoverage.

Particularly for the US and the world's biggest oil market, the Nymex, reportedvolumes at the Cushing (Oklahoma) oil basing point for physical traded oil, is a keyoil storage metric. Here again however, big things are happening, including rapidlyrising output of US shale oil, and increasing supply of Canadian tarsand oil - both ofthem to the North. US north-south pipeline debates, and rail transport of oil, aremajor ongoing themes in the US, with a constant ability to influence daily prices.

What we can call "static stocks" of the Cushing type ignore the oil-in-transit "stock",


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by pipeline, rail, barge and tanker shipping: this is a very big number! Bringing bothparts of the stocks picture together produces not the impression, but the reality ofserious oversupply pressures operating across the oil sector, today. How long thistakes to "percolate" into the investment decisions and positions of Hedgers andSpeculators, is a complex subject - but here again the answer is sometime, and not

never.

The double-headed role of Hedgers on one side, Speculators on the other, is itelfunstable and volatile making it always possible for markets to stumble into a "flashcrash" as of May 2011, driving a price drop of over 9% in one day. The post-factoexplanation from trade pundits was that extra long positions suddenly lost theirattractiveness, on the back of a weaker US economic data, and caused the crash.We can be sure that in coming weeks that net long positions in Brent and WTI willdecline, but the exact forecasting of this needs a lot more than Fibonacci chart-gazing!

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The New European Oiland Gas Health andSafety Directive - whatare the implications

for the UKCS?

Written by Malcolm Mackay fromBrodies LLP

Last month Gnther Oettinger, the European Commissioner for Energy, announcedhis eagerly-awaited plan for Oil and Gas European Health, Safety and Environmentalregulation in the wake of the Macondo incident. The proposed directive that heunveiled confirms that, although there will be further points to follow from Europe, the

role and remit of the existing UK Health and Safety Executive (HSE) system willcontinue. This was greeted warmly by Oil and Gas UK as welcome recognition of the
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high standards in offshore safety that have been achieved since the Piper Alphadisaster.

The intention to seek legislative change flows from the Macondo incident in the Gulfof Mexico, the tragic consequences of which are well known, and the determination

to prevent a similar disaster happening in the North Sea by adopting best practiceacross Europe. In October 2011 the European Commission (EC) published draftlegislative proposals for offshore safety as it believes the likelihood of a majoroffshore accident in European waters remains unacceptably high. The EC hadsignalled its intention to prepare a Regulation that would apply to all of the EuropeanUnions (EU) 27 member states and Norway, which is a member of the EuropeanEconomic Area (EEA).

There was concern that a large oil release/spill could affect several EU or EEAmember states. Given the extent of the Macondo spill and the fact that such a spillwould not be bound by national boundaries the EU sought to introduce pan-

European regulation to ensure consistency in relation to offshore health and safetyand environmental regulation and obligations.

In autumn 2011 there were nearly 1,000 offshore installations operating in the EU.Nearly half were in the UK but there were also many off Denmark, Holland and Italy.Along with those with more established drilling activity and Health, Safety,Environment and Quality regimes there were newer entrants with less establishedregimes including Romania, Spain, Germany, Ireland, Greece, Bulgaria and Poland.There were also plans for drilling off Cyprus and Malta.

Developments in technology had been opening up opportunities and theseadvances, combined with the high price of oil, were also making reserves that werein deeper water with high pressure high temperature wells more viable. Of course,these new opportunities also mean new risks in areas earmarked for explorationdrilling in deep water West of Shetland, off Norway toward the Arctic and inRomanian waters of the Black Sea.

Of course, the UK has established a health and safety regime that is widely regardedas the 'gold standard', built on the harsh lessons learnt following the Piper Alphaexplosion in 1988 and the recommendations made by Lord Cullen's public inquiryinto the disaster. The EU had commented that the North Sea "risk-based regulatory

framework is considered amongst the very best in the world". In addition, postMacondo, there was a prompt and comprehensive response by the UK, for exampleconvening the Oil Spill Prevention and Response Advisory Group (OSPRAG), whichEU representatives were invited to attend and observe. In addition, there werevarious reviews, such as the report commissioned by Oil & Gas UK and GL NobleDenton and further comment, analysis by Professor Maitland who reported on theUK response in December 2012.

Along with the meetings and reviews there was also action. In May 2011, a majortwo-day drill, Exercise SULA, was carried out to simulate how the UK would react toa major oil spill incident offshore, with a focus on well control, at sea counter

pollution measures and shoreline protection. The exercise tested subsea well controlresponse capability, command and control functions, and the counter pollution


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response used to control an ongoing oil spill. During July 2011, the UK oil and gasindustry also successfully tested its ability to deploy a well capping device in thewaters west of Shetland.

Following the announcement by the EU in October 2011 of its plan to take control of

safety regulation of the oil and gas sector, there was significant concern that the longestablished but continually improving goal based, robust system operated by theHSE could be replaced with a potentially less safe system of EU regulation. UnderEC law, a regulation must be applied across all member states. A directive, which iswhat is now being proposed, is only binding in terms of the result that must beachieved. That means each member state can decide for itself what measures itwishes to implement to achieve the desired outcome. The laws of a member statemay sometimes already comply with this outcome, in which case the stateconcerned would be required only to keep its laws in place. Usually, however, amember state needs to make changes to its law (transposition) for a directive to beimplemented correctly. If a member state does not pass the required national

legislation, or the national legislation does not adequately comply with therequirements of the directive, theEC may initiate legal action against the memberstate in theEuropean Court of Justice.

Robert Paterson of Oil & Gas UK said: Oil & Gas UK has worked tirelessly tohighlight the very real damage that an EU Regulation could have done to workerssafety. The Commissions decision today to establish a directive on offshore safety isthe best way to achieve the objective of raising standards across the EU to the highlevels already present in the North Sea. The UK oil and gas industry looks forward toworking closely with the Commission to help disseminate North Sea experience andgood practice across Europe by ensuring the directive is appropriately worded.

From a commercial viewpoint an entirely new Offshore health and safety systemoperated and administered by another regulatory entity would have caused a greatdeal of disruption in the UKCS.

The crucial question of what measures need to be put in place to ensure that the UKlegislation complies with the directive is still to be addressed. The main elements ofthe preliminary EU directive are:

licensing rules for effective prevention of and response to a major accident;

independent national competent authorities responsible for the safety ofinstallations will verify the provisions for safety, environmental protection, andemergency preparedness of rigs;

emergency planning requires companies to prepare reports on major hazards,containing an individual risk assessment and risk-control measures, and anemergency response plan before exploration or production begins;

technical solutions presented by the operator need to be verifiedindependently prior to and periodically after the installation is taken intooperation. Companies will publish information about standards ofperformance. The confidentiality of whistle-blowers will be protected andoperators will be requested to submit reports of incidents overseas to enable

key safety lessons to be studied;
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companies will prepare emergency response plans based on their rig orplatform risk assessments and EU member states will likewise take fullaccount of these plans when they compile national emergency plans, whichwill be tested by the industry and national authorities;

oil and gas companies will be fully liable for environmental damage caused to

the protected marine species and natural habitats. For damage to waters, thegeographical zone will be extended to cover all EU waters, including theexclusive economic zone (about 370 km from the coast) and the continentalshelf where the coastal member states exercise jurisdiction;

offshore inspectors from member states will work together to ensure effectivesharing of best practices and contribute to developing and improving safetystandards. The EU Commission will work with its international partners topromote the implementation of the highest safety standards across the world.Operators working in the EU will be expected to demonstrate they apply thesame accident-prevention policies overseas as they apply in their EUoperations.

The UK has adapted and continually pushed Oil and Gas Health and Safety forwardfollowing Piper Alpha and Lord Cullen's report. This looks likely to continue, thoughthere will be additional points from the directive to consider. The success of Oil andGas UK (and others) in preserving the existing regime is to be praised and ought togive stability, continuity and certainty in the UK sector. It is reassuring to note thatthe new directive will not seek to duplicate what has been achieved in the UK, or tocompromise our regime, but instead build on the best practice achieved in the UK toraise safety standards across the EU.

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Insight: Globalexploration for shale'sweet spots'


Not a week seems to go by nowadays without an international deal for theexploration for unconventional resources being announced in the trade press.

So for example, Exxon and Rosneft are about to start exploring the Bazhenov shalein Russia, Ukraine and Shell have just announced a $10bn agreement for theexploitation of shale resources in that country(1), and China has just announced thatit has awarded the exploration rights of 19 shale gas blocks, through an auctionprocess which started in September last year, to 16 companies(2).

Equally, big numbers abound consider for example the most recentannouncements concerning the Arckaringa Basin in Australia(3).

Equally, the popular media continues to focus on the supposed downsides offracking alleged aquifer contamination and potential micro-earthquakes, for

example. And some politicians then respond to popular reservations

Of course, this interest is all triggered by the energy revolution that is taking place inNorth America, especially in the USA. And the large amount of froth generated bymedia coverage is, in my humble opinion, obscuring the fact that the revolution is infact underpinned by some good old fashioned geoscience. This is driven by thehuge amount of data, especially well data logs, cuttings, cores - available in almostevery play, then lithology correlation with a sprinkling of petroleum geochemistry,and extensive knowledge of conventional, historical, production.

This poses two interesting and related questions I believe. Will this approach actuallytranslate into the international arena, especially in plays where there is relatively lessdata, and if Yes, do most companies have the geoscientists who would be capableof carrying out.

But first we have to pose a simpler question.

Why does this work at all?

Most geoscientists will be aware that the key idea behind shale gas and shale oilexploration is that not all the hydrocarbons generated by a source rock are expelled

from that source rock and find their way into conventional traps or to the earthssurface. However, understanding how much hydrocarbon a source rock might
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generate and then what proportion has migrated away compared with whatproportion has stayed in, or very close to, the source rock itself demands significantinsights in petroleum geochemistry a much neglected science in seismic-dominated oil & gas companies.

Kimmeridge Energy has researched this topic extensively, taking a mass balanceapproach. Their conclusions are summarized in the sketch below:

Using their global dataset of petroleum system mass balance calculations, theyestimate that typically around 50% of hydrocarbons generated remain within thesource rock, and that:

A significant amount is often trapped in closely associated lithofacies Combined, the source rock and adjacent strata typically present the largest

continuous accumulation of hydrocarbons in a given basin Basins that have seen significant production of oil & gas from conventional

fields are often the best places to look for new unconventional plays, as wecan be 100% sure that at least one prolific source rock exists

Their estimates for recoverable unconventional resources in the largest globalonshore basins show a potentially enormous prize that could equate to orexceed the amount of oil and gas discovered in onshore conventional fields

What is the opportunity?

Again, I am grateful to Kimmeridge Energy for the map below.


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What follows from this is that it is possible to rank shale plays around the world, andhere I have been able to draw on extensive work from Kimmeridge Energythemselves, Alliance Bernstein (who have access to large amounts of data and offer

insightful analyses) and also a recent paper by Rystad Energy. All of thesecompanies presented at a recent Finding PetroleumForum(4).

Well over 250 shale formations, worldwide outside North America, have beenevaluated and reported on, with some countries having more than 10 candidates,others only one.

To highlight just two regions:

In the FSU, Russia, Kazakhstan, Turkmenistan and Ukraine offer large (Bboe)potential, figuring in the top 20 countries outside North America, with key basins

being West Siberia (Bazhenov shale; Jurassic & Cretaceous shales; Lower Toarcianshales); Volga-Urals (Domanik shale); Timon-Pechora (Domanik shale); Amu-Drayu(Jurassic shales).

Incidentally, Russia, Ukraine and Kazakhstan also figure in the top 12 countries bysize of Coal Bed Methane reserves.

In the Asia-Pacific region, China, Indonesia, India and Australia offer large (Bboe)potential, figuring in the top 20 countries outside North America, with key basinsbeing Tarim (Cambrian, Ordovician, Carboniferous, Jurassic shales); Junggar(Permian lacustrine shales); Sichaun (Cambrian, Silurian, Permo-Triassic, Jurassic

shales); Ordos (Paleozoic> Mesozoic shales); Songliao (Cretaceous lacustrineshales); Cooper (Permian shales); Canning (Ordovician); KG (Permian shales);


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Cambay (Upper Cretaceous> Tertiary shales).

These same four countries also figure in the top 12 countries by size of Coal BedMethane reserves.

So far so good but how do we explore these plays?

Finding the sweet spot

Kimmeridge Energys analyses(4) show that the economics of a US shale play canvary considerably depending whether you are in the core or non-core of that play.Post-drill of course definition of what is core or non-core is relativelystraightforward, especially when there is a huge data base with which to work ofwell logs, cuttings, core, flow rates etc; the whole lends itself to statistical analysis. Ina data-rich basin, this analysis may even be possible pre-drill; as KimmeridgeEnergy put it defining the core relies on mapping optimal convergence of various

technical attributes, for example mineralogy, depth, thickness, porosity,permeability, fracturing, TOC/R0, S1 for the target shale.

I find that I question how many North American players will be able to successfullytranslate their US and Canada experiences to the international scene? Costs arelikely to be higher almost anywhere on the planet outside North America and sodefining the core the sweet spot - of a shale play pre-drill will be absolutelycritical; to do this, companies promising to succeed internationally will need accessto key skills, perhaps especially in petroleum geochemistry, that have beenneglected in the pursuit of offshore, especially deepwater, provinces.Also, the amount of data, and perhaps especially its quality, will be significantly lessthan that typically found in the USA.And if we believe in historical analogues, we can point to the relative failure 20-25years ago of many companies, with skills honed in the even then extremely, andrelatively, data-rich USA and Canada, to succeed in international settings.

So whilst there has been a logical focus on exploitation issues in thinking aboutexporting the US shale gale to the Rest of the World whether the necessarydrilling & completions equipment exist in the required numbers elsewhere, whetherpublic and political opinion will support exploitation, whether the necessarysupporting workforce and infrastructure exists my focus is on whether we actually

know how to explore for these so-called resource plays in an international setting?

Can geophysics help, specifically seismic technology? The immediate answer seemsto be Yes; there have been several studies of the geophysical properties of shaleswith several recent examples prompted by the shale gale(5). Its somewhat differentfrom say mapping channel geometries in deep water clastic systems, and thenpredicting fluid fill and porosities from acoustic impedance or AVO, but it can bedone.Historical data also show that well productivity is a function of the induced fractureextent and how well the formation can maintain those fractures. Frackability, thepropensity of the formation to fracture and maintain the fracture, is directly correlated

with brittleness and thus an important additional requirement of predicting shalesweet spots is to forecast brittleness, identifying the reservoirs tendency to fail


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under stress and then to maintain a fracture.

This takes us into a novel area. The generation of oil or gas in a source rockgenerates micro-fractures and these fractures will then evolve under the action ofnatural differential stress in the earth, typically acquiring a preferred orientation over

geological time. These micro-fractures then control first of all the likely movement ofhydrocarbons within and through the source rock and also the innate brittleness ofthe rock. These aspects of geomechanics must then be linked to our ability tointerpret seismic data; the simple summary is that three component (3C) seismicdata brings an ability to use shear waves (and sometimes P wave velocity) to mapfractures, an ability which cannot be achieved with conventional seismic data(6).

So, in principle seismic could be used to find sweet spotsif it were not forthe prices charged by cable-using seismic contractors!

Thus, at least in my humble opinion, two key questions are can we use non-

seismic techniques to focus our efforts in a play into a relatively small area, and thenuse cable-less seismic technology to acquire (3C) 3D at a not losing your shirtcost?

References

(1)http://www.rigzone.com/news/oil_gas/a/123778/Ukraine_Shell_to_Sign_10_Billion_Shale_Gas_Deal

(2)http://www.rigzone.com/news/oil_gas/a/123607/China_Awards_Shale_Exploration_Rights_of_19_Blocks_to_16_Companies

(3)http://www.oilvoice.com/n/Linc_Energy_confirms_shale_oil_potential_in_the_Arckaringa_Basin/a1e5f880978b.aspx

(4)http://www.findingpetroleum.com/event/Developments_with_unconventionals/260f5.aspx

(5)http://tle.geoscienceworld.org/content/30/3/332.abstract

(6)http://www.geoexpro.com/article/Reservoir_Dynamics_and_the_New_Geophysics

/61d1026e.aspx

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Lower highs: The realtrajectory of U.S. oilproduction

Written by Kurt Cobb fromResource Insights

The way the oil industry is touting gains in U.S. crude production, you would thinkthat production is soaring to new all-time highs. But the facts say otherwise. Below isa monthly plot of U.S. crude oil production through December 2012.

U.S. production remains well below the peak achieved in 1970 and below asecondary peak in 1985a lower high, if you willwhich resulted from the ramp-upof production in Alaska. But since then production has gone relentlessly downhilluntil just recently.

It is true that a new form of hydraulic fracturinghigh-volume slick-water hydraulicfracturinghas made available sources of oil not previously accessible. But it is alsotrue that the industrys hyperbole doesnt square with the evidence. The U.S. EnergyInformation Administrations (EIA) latest estimate of technically recoverable oil fromso-called tight oil depositsthe ones made accessible by this new type of hydraulicfracturingis 33 billion barrels (see below). It sounds like a lot. But, in fact, it wouldonly supply the United States for about 6 years (assuming current net annualconsumption of about 5.1 billion barrels). Not bad; but not a world-changing number,especially when you consider that all oil goes onto a world market where 33 billionbarre