OilVoice Magazine | April 2013

Edition Thirteen – April 2013

Why are oil prices falling?

Report: Oil and gas opportunities in Southern Africa Lower highs: The real trajectory of U.S. oil production

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OilVoice Magazine | APRIL 2013

Adam Marmaras Chief Executive Officer Issue 13 – April 2013 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: press@oilvoice.com Skype: oilvoicetalk Editor James Allen Email: james@oilvoice.com Director of Sales Terry O'Donnell Email: terry@oilvoice.com Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com

Welcome to the 13th edition of the OilVoice Magazine.

This month's edition contains great content like “Oil supply glut demand desert” by Andrew McKillop, “Will the final blow for America's shale gas 'revolution' be high prices?” by Kurt Cobb and "The New European Oil and Gas Health and Safety Directive - what are the implications for the UKCS?" by Malcolm Mackay.

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Adam Marmaras

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OilVoice Magazine | APRIL 2013

Contents Featured Authors Biographies of this months featured authors

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Innovative oil field equipment and strategies are reshaping industry

by Paul Moore

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Recent Company Profiles The most recent companies added to the OilVoice directory

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Insight: The increasing use of Gravity Gradiometry in the Exploration Workflow

by David Jackson

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Transforming the dash for gas into a low carbon, sustainable industry

by Tore Amundsen

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Report: Oil & gas opportunities in North Africa and the Eastern Mediterranean

by David Bamford

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Report: Oil and gas opportunities in Southern Africa

by David Bamford

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

by Kurt Cobb

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Oil supply glut demand desert

by Andrew McKillop

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The New European Oil and Gas Health and Safety Directive - what are the implications for the UKCS?

by Malcolm Mackay

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Insight: Global exploration for shale 'sweet spots'

by David Bamford

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

by Kurt Cobb

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Why are oil prices falling?

by Andrew McKillop

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Featured Authors Paul Moore Bakken Residence Suites Paul Moore works with several housing providers and covers a variety of business topics. He works with Bakken Residence Suites, a corporate housing 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 reservoir engineering.

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

Kurt Cobb Resource Insights Kurt Cobb is an author, speaker, and columnist focusing on energy and the environment. He is a regular contributor to the Energy Voices section of The Christian 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 has various roles with Parkmead Group plc, PARAS Ltd and New Eyes Exploration Ltd, and runs his own consultancy.

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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.

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Innovative oil field equipment and strategies are reshaping 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 into them than is returned it becomes a very stark reality that imprints itself on the retinas of company executives and investors alike.

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

Better Underground Imaging In medicine three-dimensional imaging using MRI and ultrasound technologies is improving healthcare in every facet of exploration into the depths, contours, and capacities of the human body. The same is true for 3D seismic imaging techniques that give geologists a better idea of whether or not a given rock formation has the potential to bear oil or gas. It has revolutionized oil and gas exploration by enabling optimization of functionality in the depths of wells in all ranges of geological formations. Complex regions that have in the past proven challenging to maintain, are now regulated and functioning at high capacity. Facts and data are easily assessed and evaluated and production is increasingly streamlined.

Now geological areas that have complex substructures can be explored. For example, salt formations cause huge problems for two-dimensional imaging techniques but are dealt with handily when the new 3D systems are employed. Being able to get a better understanding of what's happening thousands of feet below the surface results in drilling fewer dry holes. And when a clearer picture of the geology is 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 slant drilling, 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, the border was redrawn to bring the oil field into Kuwait. Fortunately, despite the often-heated debate about U.S. oil drilling, things don't get quite that fractious in the states.

It was after the U.S. Naval Facilities Engineering Service Center in Port Hueneme, California successfully ran horizontal drilling tests in 1993 that things really started to change. Water drill bits and pipe innovations successfully allowed drillers to go sideways for the first time. Oil and gas deposits are much bigger horizontally than vertically, so this was a game changer.

One of the immediate benefits was that horizontal drilling allows oil and gas developers to access deposits under environmentally sensitive land without having to erect drilling rigs on the land itself. Also, one horizontal well can sometimes be used instead of several vertical wells, which significantly lessens environmental impact. Horizontal drilling in combination with hydraulic fracturing (fracking) has led to the oil and gas boom in the Bakken Formation area of North Dakota and Montana as well as increased production in Texas and Pennsylvania.

Mixing Oil and Water Offshore oil production continues to be an important component of U.S. energy production, and Morningstar named Merrill (Pete) Miller Jr. of National Oilwell Varco its "2012 CEO of the Year" in large part as a result of innovations he has made in offshore oil rigs.

Miller recognized a major problem with offshore oil rigs – they were virtually all custom 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 would dramatically decrease costs.

Along with creating standard cabins, rails and derricks, Miller went further. Just like a computer 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 more productive and efficient day-to-day operations and made repairs significantly less expensive.

It was the near magic formula to produce much more profitability, allowing increased investment 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 and important to note that it's innovation and evolution within the industry itself that have perhaps the biggest effect on domestic oil and gas supplies.

View more quality content from OilVoice

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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 feature key data that allows users to focus on specific information or a full company report that can be accessed online or printed and reviewed later. Start your search today!

Kitsault Energy

JP Energy Partners

LNG

Service

Kitsault Energy is a company dedicated to the establishment of a Liquefied Natural Gas (LNG) Plant and Energy Export Terminal at the site of an abandoned mining town on Observatory Inlet, one of the northernmost fiords on Canada's west coast.

Kitsault Energy's OilVoice profile

Venari Resources Exploration

JP Energy Partners brings years of collective experience working within the energy industry.

The company is creating a portfolio of diversified midstream services that support an integrated refinery services solution. They own and operate assets that play an integral role in providing midstream services throughout the Southwest and Midcontinent of the US, including supply and logistics, terminal and storage services, and wholesale and retail marketing.

JP Energy Partners’ OilVoice profile

Venari Resources is a privately held offshore exploration and production company founded in 2012 by deepwater E&P expert Brian Reinsborough.

Venari Resources' OilVoice profile

Dakota Plains Service Dakota Plains Holdings, Inc., a Nevada corporation, was founded in 2008 for the purpose of developing and owning transloading facilities throughout the Williston Basin oil fields of North Dakota.

Dakota Plains Holdings' OilVoice profile

CaiTerra Oil & Gas

Caiterra International Energy is a publicly traded oil and gas company pursuing acquisitions of international oil and gas exploration and production opportunities.

Caiterra has currently built a significant portfolio of land positions in Alberta, specifically in the Faust, Lac La Biche and Amadou regions.

Caiterra International Energy's OilVoice profile

Union Jack Oil Oil & Gas Union Jack Oil plc joined the ISDX Growth Market in December 2012 as a vehicle to identify drilling, development and investment opportunities in the hydrocarbon sector.

Union Jack Oil's OilVoice profile

Impact Oil & Gas Oil & Gas Impact Oil & Gas has built a portfolio of underexplored blocks in geologically prospective frontier areas off southern Africa.

The company has one of the largest holdings offshore South Africa [for a private company] which currently consists of 75,991 square kilometres. The board seek to further increase Impact's footprint in the region as the current portfolio is progressed and developed.

Impact Oil & Gas' OilVoice profile

Health, Safety, Environment and Risk Management RPS Energy is a global multi-disciplinary consultancy, providing integrated technical, commercial and project management support services in the fields of geoscience, engineering and HS&E.

Contact James Blanchard T +44 (0) 20 7280 3200 E BlanchardJ@rpsgroup.com

rpsgroup.com/energy

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Insight: The increasing use of Gravity Gradiometry in the Exploration Workflow Written by David Jackson from ARKeX Overview of Full Tensor Gravity Gradiometry Gravity gradiometry is the study and measurement of spatial variations in the acceleration due to gravity. The gravity gradient is the spatial rate of change of gravitational acceleration.

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

What is it?

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

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

Figure 1. - Simplified view of Gravity and Gravity Gradiometry

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Full Tensor While a conventional gravity survey records a single component of the threecomponent gravitational force, usually in the vertical plane, Full Tensor Gravity Gradiometry 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 accurate representation of the gravity field being surveyed. This is shown in Figure 2.

Fig. 2. Conventional gravity measures ONE component of the gravity field in the vertical direction Gz (LHS), Full tensor gravity gradiometry measures ALL components 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 scalar gravimetry which results in a significant increase in resolution and accuracy.

Firstly being the derivatives of gravity, the spectral power of gravity gradient signals is pushed to higher frequencies. This generally makes the gravity gradient anomaly more 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 at 1 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, so that 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 the signals of interest.

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

Case Studies East Africa: Reducing Exploration Timelines with Full Tensor Gravity Gradiometry East Africa has received its fair share of exploration attention over the past few years. The discoveries in Uganda in the Albertine basin have instigated significant exploration 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 partner Africa Oil have already been reporting encouraging results with their first well in Kenya’s Block 10BB demonstrating a working petroleum system in the region.

The challenges in these frontier areas are enormous, however - vast tracts of remote exploration acreage with limited or no data coverage to explore and against an ever challenging 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 sediments juxtaposed against a much denser Achaean basement, is ideally suited to the use of this gravity exploration technique. FTG measures the variations of the Earth’s gravity field with such a high degree of resolution and bandwidth that detailed basement structure maps can be derived which, in turn, allows for the optimal positioning of the seismic 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 rapidly over large areas and thereby focus the seismic budget. The environmental footprint is also negligible.

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

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 insufficient depth 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 cross section was created from existing seismic data and then extruded into the Y-direction to generate a pseudo 3D model (Figure 4). The model was then offset to simulate strike-slip faults and the conventional airborne gravity and gravity gradiometry response 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 is poor. Strike-slip movement is only imaged where the basement is very shallow.

Figure 5 (top): Conventional gravity Figure 6 (bottom): Gravity Gradiometry With the gravity gradiometry data deeper basement blocks are imaged as well as strike-slip motion at depth. The FTG generates such positive and clear results from the rift due to the inherent way the technology works. It can accurately map the contrast between the basement and sediment cover and pick up the architecture of the 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 Rift’s geology, decreasing exploration disk and increasing exploration success.

NE Greenland: Integration of regional 2D seismic and full tensor gravity gradiometry Three phases of 2D seismic acquisition and PSDM processing were completed by ION GeoVentures from 2008 to 2012. The objective was to provide a regional evaluation of the untested NE Greenland Atlantic passive margin (Helwig et al, 2012). In 2012 ARKeX completed an airborne Full Tensor Gravity (FTG) survey for Ion over the area for both the pre-round blocks open to the KANUMAS Group and the blocks for the 2013 Greenland Licensing Round. (Figure 7) The FTG survey is the largest ever acquired offshore and covers 50,000 sq.km. The high resolution gravity gradiometry and magnetics have been integrated with the Northeast 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 Greenland margin can be built in order to guide structural interpretations and the implications for petroleum systems on this margin.

Figure 7: Tectonic elements of the NE Greenland Margin and locations of the Ion GreenlandSPAN seismic and the full tensor gravity gradiometry survey

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The prospectivity of the northern part of the Danmarkshavn Basin is likely to be heavily influenced by the presence and shape of salt bodies. Prior to the acquisition of the FTG survey over 25 individual diapirs had been mapped using Ion’s high quality PSDM seismic volume. However, even though the seismic quality is excellent, 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 the seismic, has enabled the building of a 3D architecture of the salt and associated sedimentary packages in areas away from seismic control. In addition to salt geometries, fault linkages have also been extrapolated away from seismic control.

Magnetic data analysis has also led to a better understanding of the basement composition, which along with fault linkages, allows models for reservoir fairway analysis 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 insufficient depth 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 seismic reflection data and geological-geophysical constraints. Third Conjugate Margins Conference, Dublin, 2012.

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

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Transforming the dash for gas into a low carbon, sustainable industry Written by Tore Amundsen from Technology Centre Mongstad The boom in shale gas has taken up full pace due to the vast volumes available and cheap cost, even using unconventional fracking methods for excavation. Many have also asserted the properties of gas as the ‘cleanest’ fossil fuel as rationale for locking in widespread shale gas production. However, in many cases, the claims of gas as a sustainable fuel are overstated. Certainly, gas burns cleaner than coal. It also ensures a constant supply of power unlike intermittent wind or solar. Yet the IEA reports that already two thirds of global carbon reserves are related to coal, 2% to oil and 15% to gas. With global energy demand expected to double in the next 20 years, 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 reducing emissions (if it had ratified the 1997 Kyoto protocol it would have now met its obligations), now stands to become the world’s largest gas producer by 2015. By 2035 nearly half of US gas production is expected to come from shale gas, up from around a quarter in 2010.

Countries such as the UK may also benefit from shale gas, providing space can be found to support the necessary infrastructure. For example, it is possible that the UK’s 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 Sea’s 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 and wind power, before 2030 is unrealistic, especially when the lower price of gas makes it harder for renewables to compete on short terms costs alone. But can the impact of 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 by companies are sub-prime assets. According to the Carbon Tracker Initiative, 80 per

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cent of fossil fuel investments are effectively unburnable, since doing so would blow legally binding greenhouse gas emissions budgets. In January 2013, market analysts at HSBC warned that oil and gas majors, that they could face a loss in market value of up to 60%, should the international community introduce global mandatory emissions reduction targets. But even in the absence of a global mandatory agreement on carbon, the direction of travel for the fossil fuel industry is towards increased carbon compliance.

With the dash for gas effectively boosting an already overblown carbon bubble, it’s up to the gas industry itself to decarbonise the supply to safeguard its place as a primary global energy source.

Transforming gas into a low carbon fuel The only way to effectively decarbonise our gas supply, by up to 90%, is through Carbon 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 total required carbon emissions reductions will come from CCS by 2050.

The rewards are there for those gas generators that invest, in terms of jobs created in this new industry. In the UK for example, a leader in CCS, research by the Carbon Trust found that CCS industrial development could contribute ÂŁ3-16bn to UK GDP cumulatively to 2050. Furthermore, as well as enabling generators to benefit from the rise in cheap unconventional energy, such as shale gas, CCS allows countries to simultaneously avoid penalties for missing legally binding carbon targets.

Generators have been capturing and transporting CO2 gases in large-scale plants for decades; which has been utilised in enhanced oil recovery, as well as the production of carbonated drinks. But the fact remains that unlike other now mainstream low-carbon technology sectors, such as wind and solar, CCS technologies do not currently exist at commercial scale. Currently, carbon capture is costly; the GCCSI estimates that each Mwh supported by CCS costs energy generators an additional $50 - $100, as well as substantial capital costs for development.

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 have partnered on the Gorgon initiative in Australia, the world’s largest CCS project. It has been set up to enable natural gas to travel through undersea pipelines to a liquefied natural gas plant on nearby Barrow Island. Once injection operations are at full capacity in 2015, 3-4 million tonnes a year of naturally occurring CO2 produced with the natural gas will be captured and injected into a deep sandstone formation 2.5 kilometres beneath the island. Significantly, once complete, Gorgon has an estimated 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 and financial risks, thereby creating the preconditions for success. The UK Energy Research Council (UKERC), which spent two years researching the means for establishing CCS as a mainstream technology, came to the same conclusion: a regulatory 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 is the most advanced of these, offering the ability to capture 100,000 tonnes of CO2 a year, 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 for testing, 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 emissions from shale gas, it is up to the gas industry to invest in the technology now, to enable gas profits to be maximised in the future, whilst simultaneously mitigating carbon emissions.

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

View more quality content from Technology Centre Mongstad

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Report: Oil & gas opportunities in North Africa and the Eastern Mediterranean Written by David Bamford from Finding Petroleum What exploration opportunities are there in North Africa and the Eastern Mediterranean, 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 perceived as a Frontier province.

Algeria has ‘always been open’ and now most plays and basins look quite Mature in exploration 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 significant basins have been equally explored, and there is a case to agree that exploration has, for the past several decades, not benefitted from the latest technologies.

Similarly to Algeria, Egypt has ‘always been open’ and most plays look quite Mature in exploration terms, although again there is a case that some modern technologies still have a role to play – for example sub-salt imaging in the Gulf of Suez and Full Tensor 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 well under way.

Above ground, of course there are some significant issues to contemplate, in particular with political and security stability still to result in Libya and Egypt in the wake 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 should anticipate an imminent ‘exploration Spring’ in the region, in particular whether further large discoveries can be foreseen, and if so, where?

Or should we anticipate a ‘deep Winter’, in which only the biggest companies are willing 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 and slide packs, please click here.

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Report: Oil and gas opportunities in Southern Africa Written by David Bamford from Finding Petroleum On 9th January 2013, Finding Petroleum ran a special event with the support of the South African dti, from the High Commission of South Africa The event reviewed the scope for oil & gas exploration and production in Southern Africa, including Nambia, Mozambique, Tanzania and South Africa.

The sensible starting point was to consider the large gas resources that have been reported for Mozambique and Tanzania. When will these be converted to reserves and 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 (from Mozambique) lies beyond 2020 and a categorisation as reserves must await the first signed gas contracts (as Shell discovered, to their cost, in Nigeria almost 10 years ago). 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's massive 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 play equivalent 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 Basin offer 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 need for a range of services, particularly engineering contracting. Additionally, access to large amounts of gas could drive the growth of a domestic chemicals industry.

South Africa itself offers access to skills and general infrastructure, including port facilities. UK companies seeking opportunities in South Africa might be able to take advantage of the bi-lateral UK-South Africa Trade Agreement which aims to double trade between UK and South Africa by 2015.

For the proceedings of this Forum, including videos of complete presentations and slide packs, please click here.

View more quality content from Finding Petroleum

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

Written by Kurt Cobb from Resource Insights As U.S. natural gas prices flirt with the $4 mark, some skeptics of the so-called shale gas revolution think prices are headed much higher. Such a move would, not surprisingly, seriously undermine the official story that the United States has a century of cheap natural gas waiting for the drillbit.

Several years ago when natural gas began flowing in great quantities from deep shale deposits beneath American soil, it seemed to be the beginning of the end of America’s troubled journey into dependence on energy imports—a journey marked by frequent worry, occasional war and enormous expense.

But, to some people this supposed solution to America’s energy needs has begun to

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seem as costly to the environment and human health as the country’s dependence on imported energy has been in terms of mental distress, money and blood. It turns out that this new kind of natural gas requires the industrialization of the countryside in 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 much easier on the climate than coal or oil. It didn’t take too long before people started looking into whether shale gas really was that much easier on the climate. A Cornell University researcher came to the conclusion that shale gas was probably worse for climate change than coal. His conclusion hinged in part on what are called “fugitive emissions”—unintentional, but unavoidable releases of unburned methane into the atmosphere during the hydraulic fracturingoperations performed to extract the gas.

Methane is some 20 times more potent than carbon dioxide as a greenhouse gas.

Naturally, the oil and gas industry responded vigorously to the researcher’s findings with its usual ad hominem attacks. But, it also highlighted uncertainties that are always part of any scientific study. This industry is, of course, the same one that has consistently denied the existence of climate change and continues to spend millions trying to convince the public that climate change either isn’t happening, or if it is, it won’t be that bad or if it is, it may actually be good for us.

The industry’s response to the study has, not surprisingly, been met with skepticism.

That is befitting an industry that, having spent the last two decades denying climate change, now suddenly embraces it as a reason to produce more natural gas. So, despite the industry’s best efforts, the meme that shale gas is worse than coal is out there 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, then came the 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 to energy independence would henceforth be treated as just another world commodity seeking the highest bidder—even if that bidder is in China, Japan or Great Britain.

The industry’s aim, of course, is to get higher prices for its product than customers in the United States can provide. As noted above, natural gas trades at around $4 per thousand cubic feet (mcf) in the United States. That compares to about $17 per mcf for 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 prices declined from double digits in 2008 and the shale gas boom proceeded apace, the industry convinced Americans that cheap, plentiful natural gas was the country’s future for a century to come. And, when natural gas prices plunged briefly to $1.82 per mcf last April, even the oil and gas industry began to wonder whether cheap natural gas was really such a great thing. At that price or anything below about $2.50 really, almost no wells were profitable.

Last year independent petroleum geologist Art Berman, while reviewing the financial wreckage 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 for great profit. Despite three decades of experience with tight sandstone and coal-bed methane production that yielded low-margin returns and less supply than originally advertised, 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 at increasingly lower prices have intersected with reality.” The industry proceeded to abandon shale gas plays in favor of tight oil plays which have proven to be profitable with 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 natural gas won’t be endlessly cheap in America after all. As Berman foretold in an earlier piece, prices would have to rise to between $5 and $6 to make currently paid-for leases 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, the decade of the 1990s, the average annual U.S. price was $1.92 per mcf, according the U.S. Energy Information Administration.

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

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

The future is, of course, unknown to us. But, the present and the past suggest that the 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 as conventional natural gas production continues to decline. And, at some point shale gas might even allow U.S. production to rise modestly above current levels. But, two things are now abundantly clear: It won’t be easy and it won’t be cheap.

View more quality content from Resource Insights

Finding big oil & gas fields in South East Asia The Politics may overwhelm the Geoscience!

London, 14 May 2013 Delivering well integrity How best to manage well integrity - errant technologies, new technologies?

London, 22 May 2013 Developments with FPSO operations Better ways to make decisions about specifying and operating FPSOs London, 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 demand desert Written by Andrew McKillop from AMK CONSULT THE HIGHGROUND VIEW Understanding why oil markets are "sticky for prices" needs a look at the basics. Oil markets are among the most liquid, most traded and most sought after - not only by investors, traders and hedgers, but also by economic and monetary policy makers of the 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 but declined - on a constant long-run basis, almost unrelated to annual or multi-annual average prices. In 1973 oil supplied about 53% of world energy, but today it provides about 32%. By 2020, it may supply only 27%. This, for starters, should take the crisis-word out of oil analysis.

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

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 supply builds a glut, prices come down. This is already glaringly different from the "sticky market" which characterizes what we have.

Basic economic principles do operate, but with huge distortions - and this also is one key 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, rapidly changing, often distorted prices, more often than not. It can also become an "asset bubble", with its price almost unrelated to supply-demand fundamentals, the most recently 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 the economy. 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 rates below 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" energy policy, recently joined by "carbon consciousness" in the OECD group, and increasingly in Emerging and developing countries. One example is the oil share of electric power generation: in most OECD countries, today, this weighs in at around 1%. In some lower-income developing countries however, it can still take 33% - 50% of power generation: reducing this share is a recognized major economic opportunity.

On the supply side, Non-OPEC countries heavily dominant world roduction but not traded supplies. OPEC countries are the reverse of this paradigm: they produce less of world oil, but supply more of the oil that is traded and crosses at least one national boundary. OPEC's share of global traded oil is a prized metric for oil price analysts and forecasters, to be sure, but this metric is distanced by the pace of world crudeversus-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 huge overhang of European oil refining capacity: one result of this might be unexpected, a softening of refined product prices, a compression of light-heavy crude price spreads, migrating upstream to soften crude oil prices.

OPEC's quota system, also, is a prized metric for price forecasting, but here again the mix and mingle of technology, industrial, market and political issues and factors make this a cloudy gauge. The biggest supply-side reason is the exclusion of Iraq from 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 the ground" to havily volatile production runs and net export capacities, or "offer", from the majority of OPEC member states. Basic logic, however, tells us that in a global environment 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, the process can self-reinforce for some while.

OIL STOCKS AND PRICES The key metric, managed by the IEA is days-of-average-demand oil volumes stored in 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-profile treatment, to be sure, within market trading strategies, for example if most recent stock data shows OECD stored oil shrank from say 57 days, to 56 days demand coverage.

Particularly for the US and the world's biggest oil market, the Nymex, reported volumes at the Cushing (Oklahoma) oil basing point for physical traded oil, is a key oil storage metric. Here again however, big things are happening, including rapidly rising output of US shale oil, and increasing supply of Canadian tarsand oil - both of them to the North. US north-south pipeline debates, and rail transport of oil, are major 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 both parts of the stocks picture together produces not the impression, but the reality of serious oversupply pressures operating across the oil sector, today. How long this takes to "percolate" into the investment decisions and positions of Hedgers and Speculators, 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 itelf unstable and volatile making it always possible for markets to stumble into a "flash crash" as of May 2011, driving a price drop of over 9% in one day. The post-facto explanation from trade pundits was that extra long positions suddenly lost their attractiveness, 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 will decline, but the exact forecasting of this needs a lot more than Fibonacci chartgazing!

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The New European Oil and Gas Health and Safety Directive - what are the implications for the UKCS? Written by Malcolm Mackay from Brodies LLP Last month G端nther Oettinger, the European Commissioner for Energy, announced his eagerly-awaited plan for Oil and Gas European Health, Safety and Environmental regulation in the wake of the Macondo incident. The proposed directive that he unveiled 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 will continue. 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 Alpha disaster.

The intention to seek legislative change flows from the Macondo incident in the Gulf of 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 practice across Europe. In October 2011 the European Commission (EC) published draft legislative proposals for offshore safety as it believes “the likelihood of a major offshore accident in European waters remains unacceptably high.” The EC had signalled its intention to prepare a Regulation that would apply to all of the European Union’s (EU) 27 member states and Norway, which is a member of the European Economic Area (EEA).

There was concern that a large oil release/spill could affect several EU or EEA member states. Given the extent of the Macondo spill and the fact that such a spill would not be bound by national boundaries the EU sought to introduce panEuropean regulation to ensure consistency in relation to offshore health and safety and 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 established regimes 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 these advances, combined with the high price of oil, were also making reserves that were in deeper water with high pressure high temperature wells more viable. Of course, these new opportunities also mean new risks in areas earmarked for exploration drilling in deep water West of Shetland, off Norway toward the Arctic and in Romanian waters of the Black Sea. Of course, the UK has established a health and safety regime that is widely regarded as the 'gold standard', built on the harsh lessons learnt following the Piper Alpha explosion in 1988 and the recommendations made by Lord Cullen's public inquiry into 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, post Macondo, there was a prompt and comprehensive response by the UK, for example convening the Oil Spill Prevention and Response Advisory Group (OSPRAG), which EU representatives were invited to attend and observe. In addition, there were various reviews, such as the report commissioned by Oil & Gas UK and GL Noble Denton and further comment, analysis by Professor Maitland who reported on the UK response in December 2012.

Along with the meetings and reviews there was also action. In May 2011, a major two-day drill, Exercise SULA, was carried out to simulate how the UK would react to a major oil spill incident offshore, with a focus on well control, at sea counter pollution measures and shoreline protection. The exercise tested subsea well control response 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 gas industry also successfully tested its ability to deploy a well capping device in the waters 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 long established but continually improving goal based, robust system operated by the HSE could be replaced with a potentially less safe system of EU regulation. Under EC law, a regulation must be applied across all member states. A directive, which is what is now being proposed, is only binding in terms of the result that must be achieved. That means each member state can decide for itself what measures it wishes to implement to achieve the desired outcome. The laws of a member state may sometimes already comply with this outcome, in which case the state concerned would be required only to keep its laws in place. Usually, however, a member state needs to make changes to its law (transposition) for a directive to be implemented correctly. If a member state does not pass the required national legislation, or the national legislation does not adequately comply with the requirements of the directive, the EC may initiate legal action against the member state in the European Court of Justice.

Robert Paterson of Oil & Gas UK said: “Oil & Gas UK has worked tirelessly to highlight the very real damage that an EU Regulation could have done to workers’ safety. The Commission’s decision today to establish a directive on offshore safety is the best way to achieve the objective of raising standards across the EU to the high levels already present in the North Sea. The UK oil and gas industry looks forward to working closely with the Commission to help disseminate North Sea experience and good practice across Europe by ensuring the directive is appropriately worded.”

From a commercial viewpoint an entirely new Offshore health and safety system operated and administered by another regulatory entity would have caused a great deal of disruption in the UKCS. The crucial question of what measures need to be put in place to ensure that the UK legislation complies with the directive is still to be addressed. The main elements of the preliminary EU directive are:  





licensing rules for effective prevention of and response to a major accident; independent national competent authorities responsible for the safety of installations will verify the provisions for safety, environmental protection, and emergency preparedness of rigs; emergency planning requires companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins; technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation. Companies will publish information about standards of performance. The confidentiality of whistle-blowers will be protected and operators 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 or platform risk assessments and EU member states will likewise take full account of these plans when they compile national emergency plans, which will 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, the geographical zone will be extended to cover all EU waters, including the exclusive economic zone (about 370 km from the coast) and the continental shelf where the coastal member states exercise jurisdiction; offshore inspectors from member states will work together to ensure effective sharing of best practices and contribute to developing and improving safety standards. The EU Commission will work with its international partners to promote the implementation of the highest safety standards across the world.

Operators working in the EU will be expected to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations.

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

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Insight: Global exploration for shale 'sweet spots' Written by David Bamford from Finding Petroleum Not a week seems to go by nowadays without an international ‘deal’ for the exploration for unconventional resources being announced in the ‘trade press’.

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

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

Equally, the popular media continues to focus on the supposed downsides of ‘fracking’ – 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 in North America, especially in the USA. And the large amount of froth generated by media coverage is, in my humble opinion, obscuring the fact that the revolution is in fact underpinned by some good ‘old fashioned’ geoscience. This is driven by the huge amount of data, especially well data – logs, cuttings, cores - available in almost every 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 actually translate into the international arena, especially in plays where there is relatively less data, and if Yes, do most companies have the geoscientists who would be capable of 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 oil exploration 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 earth’s surface. However, understanding how much hydrocarbon a source rock might

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generate and then what proportion has migrated away compared with what proportion has stayed in, or very close to, the source rock itself demands significant insights in petroleum geochemistry – a much neglected science in seismicdominated oil & gas companies.

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

Using their global dataset of petroleum system mass balance calculations, they estimate that typically around 50% of hydrocarbons generated remain within the source 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 we can be 100% sure that at least one prolific source rock exists Their estimates for recoverable unconventional resources in the largest global onshore basins show a potentially enormous prize that could equate to or exceed 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, and here I have been able to draw on extensive work from Kimmeridge Energy themselves, Alliance Bernstein (who have access to large amounts of data and offer insightful analyses) and also a recent paper by Rystad Energy. All of these companies presented at a recent Finding PetroleumForum(4).

Well over 250 shale formations, worldwide outside North America, have been evaluated 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 Toarcian shales); Volga-Urals (Domanik shale); Timon-Pechora (Domanik shale); Amu-Drayu (Jurassic shales).

Incidentally, Russia, Ukraine and Kazakhstan also figure in the ‘top 12’ countries by size 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 basins being Tarim (Cambrian, Ordovician, Carboniferous, Jurassic shales); Junggar (Permian lacustrine shales); Sichaun (Cambrian, Silurian, Permo-Triassic, Jurassic shales); Ordos (Paleozoic –> Mesozoic shales); Songliao (Cretaceous lacustrine shales); 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 Bed Methane reserves.

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

Finding the “sweet spot” Kimmeridge Energy’s analyses(4) show that the economics of a US shale play can vary 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 relatively straightforward, especially when there is a huge data base with which to work – of well logs, cuttings, core, flow rates etc; the whole lends itself to statistical analysis. In a data-rich basin, this analysis may even be possible pre-drill; as Kimmeridge Energy 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 successfully translate their US and Canada experiences to the international scene? Costs are likely to be higher almost anywhere on the planet outside North America and so defining the ‘core’ – the ‘sweet spot’ - of a shale play pre-drill will be absolutely critical; to do this, companies promising to succeed internationally will need access to key skills, perhaps especially in petroleum geochemistry, that have been neglected in the pursuit of offshore, especially deepwater, provinces.

Also, the amount of data, and perhaps especially its quality, will be significantly less than that typically found in the USA. And if we believe in historical analogues, we can point to the relative failure 20-25 years ago of many companies, with skills honed in the even then extremely, and relatively, data-rich USA and Canada, to succeed in international settings.

So whilst there has been a logical focus on exploitation issues in thinking about exporting the US ‘shale gale’ to the Rest of the World – whether the necessary drilling & completions equipment exist in the required numbers elsewhere, whether public and political opinion will support exploitation, whether the necessary supporting 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 seems to be Yes; there have been several studies of the geophysical properties of shales with several recent examples prompted by the ‘shale gale’(5). It’s somewhat different from say mapping channel geometries in deep water clastic systems, and then predicting fluid fill and porosities from acoustic impedance or AVO, but it can be done.

Historical data also show that well productivity is a function of the induced fracture extent and how well the formation can maintain those fractures. ‘Frackability’, the propensity of the formation to fracture and maintain the fracture, is directly correlated with brittleness and thus an important additional requirement of predicting shale ‘sweet 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 rock generates micro-fractures and these fractures will then evolve under the action of natural differential stress in the earth, typically acquiring a preferred orientation over geological time. These micro-fractures then control first of all the likely movement of hydrocarbons within and through the source rock and also the innate brittleness of the rock. These aspects of geomechanics must then be linked to our ability to interpret seismic data; the simple summary is that three component (3C) seismic data brings an ability to use shear waves (and sometimes P wave velocity) to map fractures, an ability which cannot be achieved with conventional seismic data(6).

So, in principle seismic could be used to find ‘sweet spots’…………if it were not for the prices charged by cable-using seismic contractors!

Thus, at least in my humble opinion, two key questions are – can we use nonseismic techniques to focus our efforts in a play into a relatively small area, and then use cable-less seismic technology to acquire (3C) 3D at a “not losing your shirt” cost?

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_Arck aringa_Basin/a1e5f880978b.aspx (4)http://www.findingpetroleum.com/event/Developments_with_unconventionals/260f 5.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 real trajectory of U.S. oil production Written by Kurt Cobb from Resource Insights The way the oil industry is touting gains in U.S. crude production, you would think that production is soaring to new all-time highs. But the facts say otherwise. Below is a monthly plot of U.S. crude oil production through December 2012.

U.S. production remains well below the peak achieved in 1970 and below a secondary peak in 1985—a lower high, if you will—which resulted from the ramp-up of production in Alaska. But since then production has gone relentlessly downhill until just recently.

It is true that a new form of hydraulic fracturing—high-volume slick-water hydraulic fracturing—has made available sources of oil not previously accessible. But it is also true that the industry’s hyperbole doesn’t square with the evidence. The U.S. Energy Information Administration’s (EIA) latest estimate of technically recoverable oil from so-called tight oil deposits—the ones made accessible by this new type of hydraulic fracturing—is 33 billion barrels (see below). It sounds like a lot. But, in fact, it would only supply the United States for about 6½ years (assuming current net annual consumption 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 billion barrels would last a little over a year. Beyond this, the estimate says little about how much of that oil will ever be economically recoverable. Wherever it isn’t, no one is going to extract it.

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But there is another column in the EIA table above that is worth focusing on, the one labeled “% of Area Untested.” We don’t yet actually know that much about the potential for the country’s tight oil (often mistakenly referred to as shale oil). In some areas drilling has only just begun, and in others there’s been no drilling at all.

There is reason to believe that things may not go as planned. In the areas already drilled, drillers have focused on a few sweet spots that have proven profitable. That makes perfect sense. But, it suggests that they must now venture beyond those sweet spots to find additional supplies from deposits that will be more refractory and thus more expensive and difficult to exploit. No one is certain how drillers will fare.

But logic suggests that production growth will slow and then at some point stop— after which a production decline will begin in earnest.

The EIA projects that U.S. oil production will peak later in this decade—a little below the previous secondary peak in 1985. That would result in a tertiary peak, or yet another lower high. In the meantime the extra supply promises to lower America’s bill for oil imports. But the modest turnaround in America’s oil fortunes won’t solve the larger problem of worldwide oil depletion which, despite American gains, has kept worldwide oil production on a bumpy plateau since 2005.

We live in a global oil market, and that market remains tight as is evidenced by an oil price hovering around $90 in the United States and $110 in Europe, the latter price being more representative of what most people pay.

For obvious reasons the oil industry doesn’t want us to think about weaning ourselves off oil anytime soon. They believe that if they can convince us that oil is abundant, we won’t even try. But oil prices have been telling us for almost a decade that supplies are much tighter than the industry is acknowledging. And, the facts about U.S. oil production tell us that if there is a revolution going on in American oilfields, it is only a minor one, and one that will soon be reversed.

That doesn’t leave us much time to prepare for a world in which oil supplies are almost certain to dwindle globally as the current plateau in worldwide production turns into a decline. And, that will be a problem for everyone including the United States, a country that remains the planet’s largest importer of crude oil.

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OilVoice Magazine | APRIL 2013

Why are oil prices falling?

Written by Andrew McKillop from AMK CONSULT AN EVEN MORE RIDICULOUS QUESTION Some folks might ask an even more idiot question: "Why aren't oil prices continuing to rise?" but this second question is only asked by the brightest traders going for the big chance each trading day. For a long time this year so far, oil prices literally defied gravity, and went on rising, decorated with the nicest-possible leading edge analyses and commentaries.

From late February the luck ran out and the headwinds became a little too strong for the fine talk to go on convincing the crowd. Oil like gold and silver, is facing troubled times. They profit during periods of asset inflation as in 2009-2012, but get hit when global macro trends shift to asset deflation. Equities, for basically political reasons and nothing else, can defy gravity a little longer than oil or gold: since 06/2012 major equity indices have rallied about 21% to this week, compared to -1% for gold bullion and -20% for the Amex Gold Bugs index tracking 16 major gold mining companies.

The Gold Bugs index has fallen 31% from its September high, while the yellow metal dropped 13% from its October 4, 2012 high near $1793 per Troy ounce. Another warning signal is clear: a similar 2.5:1 relation in the sell-off ratio for GoldBugs index/Bullion was seen during the 2008 crisis, when bullion fell 33% from its 2008 peak to trough, while the Gold Bugs index fell 71%. On this basis gold prices could theoretically fall to near $1500 per ounce, oil to near $75 per bbl WTI. NEW FUNDAMENTALS ARE NEGATIVE Old fundamentals also, called supply/demand and stocks. All kinds and types of classic conventional oil price drivers are negative for high-priced oil. The world car industry, recently an Emerging economy transplant showing double digit annual growth, is faced by a rapid turn down in sales in India and single digit annual growth in China. Car sales in Europe are a disaster. Car fuel economy is rising, everywhere.

Average annual car mileage operating rates are falling. This story can continue, but only sends more negative signals for the car fuel demand outlook. World container and bulk cargo marine transport, a sector consuming around 2 billion barrels-a-year in 2009 (6% of world total oil demand), continues to flatline after a major fall in 20092011. Telltale indicators like the port of Shanghai, the largest container port in China and the world, posted a YOY decline in throughput of 3% in 2012, and some months of the year, like February recorded a 28% decline.Oil-saving is now industry wide in world shipping, including the simplest expedient of all: slow steaming.

But the new fundamentals are, for sure, less visible but at least as negative for

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overpriced oil.

One useful tracker and predictive tool is the gold-oil ratio. Although many times 'bucked' by the real world, or out of synch with the real world, this ratio can help cool Oil Bug thinking:

This typical chart from Stockcharts.com makes it plain for anybody to see we are not in a pre-2008 situation. Interpreting this 28 February chart is however not easy, because one read out is a double challenge: both gold and oil are overstretched; possibly oil is set for a bigger correction than gold. When or if it come, it should be sharp, not through price erosion, but major daily cuts. The break profile is hard to map, and in any case gold bullion deflation will quickly become 'political' in more ways than most persons might think. If the slide in gold prices is slowed, or halted, or reversed oil can go on growing - but not otherwise.

QE IS A DOUBLE EDGE SWORD Ask any oil trader if they have to click the 'Buy' button on oil futures any time that QE seems to be coming back, either in the US, Europe or Japan, and they will say yes.

However, the QE story is not what it used to be, and contrarian counter-cycle effects of QE are being felt, ever more powerfully, especially in Europe and soon in the US. QE, surprisingly enough, means longterm asset deflation not inflation. This can operate through back channels like QE's effects on currency values - globally strengthening the dollar - with an immediate hit on oil prices. It also operated by

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further deepening the recession, breaks up rational asset pricing, and makes investors draw back from playing a now overheated and risky market: oil.

We can look for supporting data for that argument in many places, including US CFTC data on relative call/put buying, and weekly volumes of cash flowing in and out of bets on oil. The retreat by The Herd could become impressive in coming weeks preceding a major oil price correction, downward.

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