ENERGY FORUM

A QUARTERLY JOURNAL FOR DEBATING ENERGY ISSUES AND POLICIES CONTENTS

Issue 86 November 2011 Technological Challenges and Developments

Ivan Sandrea – page 3 Technological developments and breakthroughs have been essential in the David Bamford – page 4 expansion of the global oil and gas industry for much of its history, and Petrobras and Boston particularly since the 1970s. Looking at the most recent decade (2000–11), Consulting Group – page 6 cumulative new gross world oil and gas reserves added amounted to Michelle Michot Foss – over 600 bn boe (2P), whilst oil and gas production rose by 38 mboe/d, page 10 defying a perceived shortage of reserves. Of the total additions, new con- Trisha Curtis – page 13 ventional hydrocarbons accounted for approximately 40 percent, whilst Samer Ashgar – page 17 non conventional hydrocarbons and offshore environments accounted R.G. Skinner – page 20 for the rest. During this period, LNG, SAGD, deepwater, horizontal Franz B. Ehrhardt – page 23 drilling, long reach drilling, EOR, fracking in tight rocks, 3D seismic Tara Shirvani and Oliver R. imaging and visualisation technologies, logging while drilling, among Inderwildi – page 25 others, became more widespread. – page 28 It would not be an understatement Bamford explains that in addition to po- Asinus Muses to say that during the last decade the litical and environmental issues, data in ‘technology factor’ helped transform much of the rest of the Arctic areas are the energy map in ways that were scarce or difficult to obtain and in some not conceived by long-term planners cases currently envisioned technologies and CEOs since the 1970s. However, are too costly in comparison with the among policy makers, energy institu- other options that explorers may have. tions, and most analysts, the impact of But could this all change? technological developments has been The discovery and development of treated more as a surprise factor, let Brazil deepwater pre salt, the most alone understood or predicted. significant new offshore province since This issue of Forum focuses on ‘tech- the North Sea, is no doubt a major nological themes’ across upstream and technological challenge, which Petro- downstream covering the Arctic, tight bras is undertaking pretty much alone. oil, deepwater pre salt, shale gas, heavy Crucially, the expectation that costs oil, EOR, GTL, all of which are centre will come down has been presented as stage today and have the potential to a major factor for its long-term suc- continue to transform the industry as cess. A paper by BCG and Petrobras well as the energy map. summarises the opportunities identi- David Bamford reviews the Arctic; in fied by the experience curve concept his view despite the huge potential, to the pre salt development campaign exploration success in the wider Arctic now underway. Petrobras has incor- is not a ‘given’; onshore Arctic explora- porated the experience curve program, tion and development has a significant which factors in technology and learn- history, notably in Alaska and West Si- ing curves among others as the scale of beria but outside remains undeveloped. the activity rises, as part of a process OXFORD ENERGY FORUM NOVEMBER 2011 to reduce the total cost of wells and subsea systems. technology will play a role in addressing increasing Michelle Foss discusses US shale gas, arguably the levels of heavier crudes. The most significant and main event that has transformed the story of un- innovative refining-related improvements can be conventionals. Foss starts by reminding us that US expected in the catalyst chemistry and application. shale gas production has caught the whole industry Ehrhardt concludes that there are economically at- by surprise, changed the structure of US gas prices, tractive technologies and processes available, especial- and led to new projections of production increases ly Delayed Coking that will continue to contribute, in US gas and exports for the foreseeable future. All and that it can be safely assumed that revolutionary of this thanks to improved interpretation of geologi- technology changes in fundamental thermal and cal models and integration of large volumes of data, hydro-treating processes in petroleum refining are drilling and stimulation technologies and application unlikely to emerge as game changers. of technologies that could help define ‘sweet spots’ at In a joint paper, Shirvani and Inderwildi provide an the exploration and exploitation stage. However, the analysis of GTL. With large stranded gas reserves, ‘backstory’ context may be more nuanced. The large GTL is viable, and may be very big. The authors shale resource abundance is not in doubt but the re- conclude that GTL fuel products may help to address covery of shale resources is, explains Foss, contingent energy security concerns and improve local air pol- on the ability of industry to achieve continued cost lution levels, but are by no means considered envi- reductions, driven by technological progress. ronmentally friendly fuels; yet due to significant lead Trisha Curtis provides an overview of the major US times, efficiency of the process, and the high upfront liquid rich tight rock, their history and outlooks. investment needed, it is unlikely that a substantial New crude oil, condensate, and natural gas liquid volume will go on-line in the foreseeable future. supplies, combined with the current surge in natural gas production, offer the promise of a renaissance. Contributors to this issue However, this dramatic increase in production will not come without complications and constraints. Samer Ashgar is Manager, Exploration and Today the industry leaves behind as much as 70 Petroleum Engineering Center, Saudi Aramco percent of the in place oil volumes in conventional David Bamford is at New Eyes Exploration Ltd reservoirs, and 90–95 percent of the in place volumes of difficult hydrocarbons including extra heavy oils, Trisha Curtis is at Energy Policy Research complex reservoirs and tight rocks. In conventional Foundation, Washington DC oil reservoirs, improved recovery and EOR (enhanced Franz B. Ehrhardt, is at CASCA Consulting oil recovery) techniques are the main alternative. Samer Ashgar of Saudi Aramco sheds light on the L.L.C. reservoir management practices that the company Michelle Michot Foss is Chief Energy has adhered to over the years, widely considered by Economist and Head, Bureau of Economic industry to be leading edge, and the direction it is Geology-Center for Energy Economics, The heading in this important area. University of Texas Looking at the difficult heavy oils, Robert Skinner Oliver R. Inderwildi is at the Smith School of indicates that the technology challenge in finding Enterprise and the Environment, University of and producing heavy oil is not simply to increase its Oxford volume, but most critically, to greatly improve the efficiency of its production, to improve unit econom- Ivan Sandrea is President of Energy Intelligence ics and reduce its environmental footprint. Skinner Tara Shirvani is at the Smith School of says that we hardly need reminding that technological Enterprise and the Environment, University breakthrough alone is not enough to assure a growing future for these difficult resources. Interestingly, in of Oxford Canada, probably the most benign link in the heavy R.G. Skinner is an independent energy oil value chain – transportation – has recently become consultant its weakest. * Authors of the Petrobras/Boston Consulting Franz Ehrhardt addresses the refining sector from Group article are listed on page 10 a strategic point of view and focuses on how

2 OXFORD ENERGY FORUM NOVEMBER 2011 Technological Developments and Challenges

Ivan Sandrea traces has also undergone significant changes 1970s which was mainly dominated and benefited from the diffusion of by political drivers (post colonisation global technological technology. In oil and gas explora- events, exercise of sovereign rights, tion, for instance, for several decades and re-alignment of interests) – during revolutions and the oil activities were dominated by follow- this period the impact of technological and gas industry ing oil seeps, surface structures, and developments (supply and demand) undertaking shallow onshore vertical was not strong or apparent – and a drilling – a technology that evolved second period, which started in the The broader impact of technological from earlier Asian experiences. All late 1970s and that continues until developments in society, industries of this changed with the coming of today. Post 1970s, a broad technologi- and economies has been well docu- seismic, wireline logs, improved earth cal revolution in the industry led the mented and researched by authors modeling, and when the industry way to the rise of the then technologi- including Kuznets, Schumpeter, developed the capability to drill cally complex shallow water oil from Freeman, and Perez. offshore in the 1950s. And crucially the North Sea, the Arctic took off, Looking back, research by Perez with the coming of the IT revolution, electronic trading took off and many shows that in the last 250 years, computers provided the industry with other developments that followed, global economic growth and politi- new tools, modeling, and measure- which one way or another impacted cal changes have gone through five ments and the ability to process ever OPEC decision making. distinct stages associated with tech- increasing complex volumes of data. nological revolutions resulting from The IT revolution coincided with the synergistic interdependence of a geopolitical events of the 1970s, which group of industries and diffusion of led to new technological inventions “Changes in OPEC oil technology. The five periods are: the which in turn supported important policy may also be linked industrial revolution (1770 to 1820), new oil and gas developments: The or framed to technological the age of steam and railways (1820 North Sea, Prudhoe Bay, 3D Seismic, to 1870), the age of steel, electricity are all examples. changes” and heavy engineering (1870 to 1910), Changes in OPEC oil policy may also the age of oil, automobile and mass be linked or framed to technological As a whole, there have been es- production (1910 to 1970) and the age changes rather than economic, price, sentially two types of breakthroughs: of information technology from late and political events. In fact, from a 1) those that in a relatively short 1970 to now. Each of these have lasted technological point of view, there period of time have suddenly appeared sixty years or so. may be two distinct periods in OPEC unexpectedly to industry and policy Through time, the oil and gas industry history: one from 1949 until the mid makers at large, and something that

Figure 1: Key Technological Developments 2000s

• 3D advanced seismic imaging, interpretation tools OPEC • Fluid flow prediction • Demand eff. tec. founded in 1960 • Ultra deepwater • Gas revolution drilling • OECD demand • Growth of offshore • Digital oil field growth • Start of deepwater • Nano technology • 2D seismic, wireline • 3D seismic • FLNG • Global conventional • Horizontal drilling • Remote sub sea • First well • US oil growth drilling • Advance wellbore developments Key petroleum Key petroleum events related • Kerosen • International • Start of offshore imaging tools • Advance subsurface • Seeps light expeditions • Start of LNG • Unconventionals measurements

Industrial Age of steam, Age of steel, Age of Age of information Revolution railways electricity petroleum technology

Global cycles 1770–1820 1820–1870 1870–1910 1910–1970 1970 – present

Source: Ivan Sandrea; Perez (modified)

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Equally, there are a growing number Figure 2: New Sources of Oil and Gas Reserves to 2020 of conferences on Arctic Technology, many of them seemingly assuming 30,000 that significant oil or gas discoveries will be made and therefore focussing

25,000 Unconventional on how to develop fields in seasonal ice, what to do about icebergs, pipe- 20,000 LNG/GTL line routes and petroleum export. Of course, onshore Arctic exploration Heavy Oil and development has a significant 15,000 history, notably in Alaska and West Mboe/d Deepwater Siberia, and there has been intermit- 10,000 tent exploration in the Barents, Conventional southern Kara, Chukchi and Beaufort 5,000 Arctic Seas, so there are many ideas – both conceptual and proven – to look at. 0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Nevertheless, a significant part of the Arctic is represented by the largest Source: Energy Intelligence and Gordon Energy shelf on Earth, the Eurasian epicon- tinental shelf, of which the major was not viable suddenly becomes fuels and how will it be met? And portion, amounting to some 3.5 mil- viable, 2) a second type when the third, how will the major players lion sq kms, is located in the Russian combination of old methods and including governments respond? In Arctic. As a calibration, this is an area new technologies resulted in a new all three cases, technology and techno- roughly equivalent to 700 offshore development. Looking at the oil and logical developments will continue to Angola deepwater blocks or 152,000 gas industry specifically, examples of be a major wild card. Gulf of Mexico deepwater blocks! the first, include wire line logging and The area is, to a large extent, sparsely seismic acquisition, whilst the second explored due to its harsh environment, case includes offshore and horizontal high cost of operations and forbidding drilling, seismic imaging, fluid predic- logistics. tion, and tight rock fracking to name a few. What Data and Knowledge do we In the upstream side, most reports Have at the Moment? and outlooks today explain that From the efforts of Soviet scientists incremental new sources of future oil and their successors, we know that and gas reserves and production will the Eastern Barents, Kara, Laptev, come from technologically challeng- East Siberian and Chukchi Seas ing reservoirs and environments. For contain over 40 sedimentary basins. most of these the technology is in For most of the basins, there is a place or there are expectations that reasonable understanding of stratig- new developments and advances will David Bamford raphy, sedimentology and structural make material contributions. The geology; long wavelength gravity and new source volume coming from looks at exploration magnetic data are available, as is a uncoventionals, deepwater, heavy oil, technology for the certain amount of 2D refraction and Arctic, and via LNG is in fact quite reflection data, the latter of which can significant but it is interesting to note Arctic be supplemented to some extent. that this was not part of the con- ventional wisdom just a decade ago. Western oil and gas technical journals The Russian Barents and the southern These represent the majority of the as well as ordinary newspapers wax Kara Seas represent the most explored new oil and gas reserves added in the lyrical over the hydrocarbon resources petroleum provinces with large proven last decade, and the bulk of the Yet to of the Arctic, typically referring to resources. In contrast, the North Kara Find. (Figure 2) it as the next global frontier. Huge is virtually unexplored, and there is only sparse seismic data over the other The oil and gas industry has always resource estimates are bandied about areas. lived with many uncertainties, but – the USGS has suggested as much three are important to single out. as 400 billion barrels oil equivalent Drachev, Malyshev & Nikishin (in a First, what is going to happen to oil remains to be discovered, with over publication by the Geological Soci- and gas prices in the future? Second 80 percent of that thought to lie in ety, London, 2010) give an excellent what will be the demand for fossil offshore fields. overview of the Tectonic History and

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Petroleum Geology of the Russian generated significant gas plus possibly Perhaps the next stage of geophysics Arctic Shelves, and I have no inten- oil at the basin margins. should be to fly extensive Full Tensor tion of repeating what they say here. It is not surprising therefore that Gravity (gravity gradiometry) surveys However, building on this overview, in addressing question 1 above, the which experience onshore, for exam- I believe explorers face three key current actions of western IOCs seem ple in East Africa, has shown can be questions: oriented towards either a fresh look a reliable tool for defining significant 1. How do we prioritise the afore- at the Barents Sea or accessing the leads in a basin; two or three compa- mentioned 40 plus sedimentary South Kara Sea – the target of BP’s nies offer this service. Integrated with basins? ill-starred venture with Rosneft. existing knowledge, this approach is capable of producing a basin-by-basin 2. Can we figure out in advance of lead inventory. drilling which ones are ‘oily’? The next step in the exploration proc- There is a prejudice that these ba- ess would then be to shoot ‘postage sins may be dominated by gas due “the Eastern Barents, Kara, stamp’ 3Ds over the most interesting to the provenance of the organic Laptev, East Siberian and leads, to mature them into prospects: material in the source rocks. Chukchi Seas contain over drilling could then follow. 3. Is it even remotely possible to 40 sedimentary basins” I hope I don’t make this sound too envisage huge swathes of Arctic simple? Getting to grips with potential ‘exploration’ 3D seismic at an af- source rocks and generating a recon- fordable price? IOCs have got used It’s difficult to see other areas opening naissance exploration data base is to exploring with vast amounts up rapidly given the absence of source an expensive, extensive and detailed of ‘exploration’ 3D seismic. For rock indicators. Relevant technolo- project which is beyond any one com- example, the 40–50,000 sq kms of gies do exist. It is possible to infer pany and needs to be commissioned deepwater and ultra-deep water the existence of active source rock by the Russian government prior to Angola are covered ‘wall-to-wall’ systems from satellite imagery – at licensing rounds. with such 3D, enabling Total, BP least this has been achieved in open and others to enjoy a success rate oceans – and there are direct sampling of >90 percent in Blocks 15, 17, 18, methodologies. 31 and 32. This 3D typically costs around $3000 per sq km. “drilling in the Arctic What about Seismic Acquisition? Let’s begin by considering the second could be up to four times as point. Broadly speaking, the Arctic presents expensive as drilling in the two related problems to seismic When one starts digging into the North Sea” acquisition – the ice itself and the knowledge base on source rocks for limited time when the ice is open. the Russian Arctic, using compilations by for example the USGS, Bernstein Two seismic service companies – ION Research and the aforementioned Geophysical and Polarcus – have What about Exploration Drilling? stated that they are addressing this review by Drachev et al., it quickly Just recently DNV presented the issue and elsewhere I have reviewed becomes apparent that actual data are results of intense and targeted their approaches in a little more detail generally absent. Thus for example work, coming up with a concept for (Geoexpro, 8, 5, 2011). These compa- in the Laptev Sea, one may freely year-round drilling and exploration nies have great technology ideas, great speculate, unconstrained by any hard offshore north-east Greenland. More innovations, but with the best will in facts, that there may be present Palae- than anything their work illustrates the world I cannot see either of them ocene and Mid-Eocene marine shales a massive need for new technologies, shooting vast tranches of ‘exploration’ or Lower Cretaceous and Paleogene improved standards and increased 3D at a cost of $3000 per sq km – five syn-rift sediments, or for the Russian Arctic research. But that’s not all; or ten times that, perhaps? Chukchi Sea that there may well be they predict that drilling in the Arctic analogues to the prolific petroleum My point is that this changes – dis- could be up to four times as expensive systems of the Arctic coast of Alaska. places – what has been the basis as drilling in the North Sea. And this But in truth, the areas where there is for efficient and effective offshore could be an underestimate. actual positive evidence of working exploration since the mid 1990s and makes me wonder whether Arctic source systems are the East Barents One Final Issue that we Need to exploration can in fact be undertaken Sea where there are Triassic organic- Face rich gas-prone coal-bearing shaly at a reasonable cost? If we go back to sediments and the South Kara Sea exploring with 2D seismic, then we The Deepwater Horizon/Macondo where there are Bazhenov bituminous face drilling $100m plus wells at a risk tragedy set shock waves around the shales, the main source rock of the of 1 in 4 or worse – not what we want industry at large, leading to a focus West Siberia basin, which may have to do! on how wells are designed, how rigs

5 OXFORD ENERGY FORUM NOVEMBER 2011 communicate with onshore, how success in the Arctic is not a ‘given’. construction of oil wells and installa- well trained rig crews are and so on. In addition to profound political and tion of subsea systems in the presalt, With reference to the Arctic, North environmental issues, data are scarce reducing Petrobras’ expected produc- American academics and other experts or difficult to obtain and in some tion development capex over the next have asserted that a similar spill in cases (seismic, drilling) currently en- 20–30 years. This article provides a Arctic waters could be devastating, visioned technologies are exceedingly brief summary of the applied concept, with ice possibly hampering any spill costly – leading to exploration that methodology and results achieved. responses for months. Many of the is expensive in comparison with the problems are logistical. Apart from other options that explorers may have, Concept: Experience Curves having only a few months to do any for example, probing ‘resource plays’ remedial or clean-up work, airfields (shale oil, shale gas) in North America The experience curve concept, which are remote, weather can ground flights or more conventional exploration in posits that unit costs for a given and workers for weeks at a time, and Deep Water or Onshore. product or process will decline at a it would likely be impossible to bring predictable rate as cumulative produc- Whilst I have focussed here on the large numbers of boats (remember tion volume increases, was developed Russian Arctic, my commentary could there were up to 1000 employed in the by BCG founder Bruce Henderson in be applied equally to the Canadian Gulf of Mexico clean-up) up to the 1968. In contrast to the well-known Arctic for example and to a large Arctic. concept of a learning curve, which extent to West and East Greenland. typically represents a passive observa- tion of short-term gains in repetitive processes, experience curves cover “Both Greenpeace and the longer periods of time and can en- WWF are very exercised compass a large range of factors, from planning and process optimisation to by the prospect of a major scale effects and the implementation Arctic spill” of new technologies. In this context, they can be used to direct investments and managerial efforts to the places Few companies have the resources to where they will yield the most impact. do what BP did in the Gulf anywhere, While a cost curve converges to an let alone in the Arctic. Shell has asymptote as volume increases in a described what they believe is needed, linear scale, on a log-log graphic it ap- saying that for its proposed offshore proaches a straight line; this has been Alaska drilling programme, it has a Petrobras and Boston defined as the experience curve. three-tier Arctic oil-spill response Consulting Group The slope of an experience curve system consisting of an on-site oil- describes the relationship between spill response fleet, near-shore barges authors* investigate cost and volume – specifically, the and oil-spill response vessels, and the impact of percentage decrease in unit cost for a onshore teams – with the latter able to given percentage increase in cumula- respond within one hour. Clearly this experience curves on tive volume. If a product has an 80 is a major undertaking and cost. the development of percent experience slope, its unit costs Both Greenpeace and the WWF are will decline 20 percent (1 minus the very exercised by the prospect of a Brazil’s presalt cluster experience slope) every time cumula- major Arctic spill, for which they tive production volume doubles. claim that no oil company is ad- Petrobras, working in partnership Experience curve slopes typically equately prepared, painting a picture with the Boston Consulting Group range from 70 to 90 percent, and their of relief wells unable to be completed (BCG), recently conducted a study calculations in real-world processes in a single drilling season, oil trapped applying the concept of experience involve a complex set of analyses and – and moving – under ice, and so on. curves to the development of Brazil’s data adjustments to isolate intrinsic Not only has Greenpeace targeted rigs presalt cluster in the Santos basin. experience effects from those related that are currently drilling offshore Underlying the study was the belief to commodity prices, exchange rates Greenland but also ‘polar bears’ have that the magnitude and duration of the and inflation, for example. broken into an oil company’s head presalt development campaign would offices in Edinburgh. strongly drive experience-effects gains Estimating Experience Curves for via continued optimisation efforts. Presalt In Conclusion The study, thus, had as its key objec- tive the identification of initiatives The methodology applied in this What I have attempted to explain in that could intensify the experience study involved five main steps, this short review is that exploration effects for critical items in the developed by Petrobras’ key managers

6 OXFORD ENERGY FORUM NOVEMBER 2011 and technicians and BCG’s upstream • Four subsea collection systems, fields and the limited existence of experts: having as variables the number of wells in comparable situations around interconnected wells, whether or the world. It is, however, possible 1. Definition of standard scenarios for not the systems use manifolds, and to analyse a presalt well through its wells and subsea systems and their whether the systems’ risers are rigid subcomponents, by identifying ap- respective cost structures or flexible plicable analogs for which there might 2. Prioritisation of critical items • Three subsea gas-export systems exist historical databases and adjusting according to cost materiality and based on riser type (auto-sustaina- these using pertinent normalisations experience potential ble hybrid, rigid or flexible). (e.g., adjustments by water depth, well length and geometry, etc.) to calculate 3. Identification of applicable analogs For each of these wells, subsea collec- for each critical item and estimation the respective individual experience tion and subsea gas-export scenarios, curve for each subcomponent (Table of respective historical experience a detailed cost breakdown was de- curve slopes 1). These curves could then be com- veloped leading to the prioritisation pounded to generate the synthetic 4. Projection of the experience curves of ten critical cost items for wells experience curve for a whole oil well for the prioritised items in the and five critical cost items for subsea or subsea system. presalt context for the next 20–30 systems. Those items included drilling years systems (bottomhole assembly, bits, Based on the defined analogs and fluids, etc.), reservoir evaluations, rigs collected data, the next step was to 5. Consolidation of the individual and their respective maritime logistics determine historical slopes for each experience curves for each critical support, subsea trees and manifolds, critical cost item. This entailed the item into single experience curves and the installation of flowlines and definition and vetting of a number of for a presalt oil well and subsea umbilicals. parameters, such as the ones illus- system. trated below that were used to define It is important to note that experience The first step was to define standard the historical experience curve slopes curve projections were run initially types of wells and subsea system associated with productive rig time in for each of the selected critical items scenarios that would be applicable to the drilling stage: rather than for the wells and subsea the presalt campaign. This analysis led systems of the presalt as a whole. This Choice of Analog. Given limited to the following: is because the curve calculation de- historical data for presalt drilling, the • Three types of wells: vertical, pends on a historical cost base that is performance from Petrobras’ postsalt vertical lean (an open well without technically comparable to the presalt fields was used as an analog. This intelligent completion and minor situation. This historical base is not analog was considered applicable to reservoir-evaluation intensity), and available for presalt wells due to the the presalt due to the finding that, via open horizontal recent discovery of the Santos basin several simulations, the experience

Table 1: Examples of Analogs to the Presalt Environment

Example of prioritized items Analog Rational for applying to presalt

Drilling sysems Drilling performance (ROP) in offshore Analysis indicates that the experience curve postsalt wells (internal data by bit type, slopes are similar, regardless of bit type, geology and well geometry) geology or well geometry considered Subsea trees Time recorded by Petrobras in the installation Installation process for subsea trees in deep of subsea trees in deep and ultra-deep waters and ultra-deep waters is similar; analysis in the postsalt (normalized by water depth) should only consider the normalization by water depth Special metallurgy Material perspectiv: Stainless steel cost Experience effects are related to the steel Product perspective: OCTG cost production process (billets and pipes) and not Triangulation with Super 13-Cr data to the presalt in particular Rig performance Productive rig time in the construction of Curves have similar slopes regardless of offshore production development wells by the typ of rigs (shallow, deep or ultra-deep Petrobras waters) Flexible and rigid lines Product and material perspective (standard Both standard and special-metallurgy lines metallurgy lines) will be used in presalt (not disruptive vs. Material perspective (special metallurgy lines) industry practice elsewhere) Nonproductive time (NPT) %NPT in the industry and at Petrobras No specific NPT root causes exist in the (Europe, Gulf of Mexico and Brazil postsalt) presalt vs. other offshore operations

7 OXFORD ENERGY FORUM NOVEMBER 2011 curve related to drilling performance and horizontals, with tricone and shallow water have very distinctive tended to present the same slope, PDC bits and for different lithologies, characteristics, including different regardless of the lithology, bit type or such as carbonates), performance gains installation processes, and, therefore, well geometry in question. in drilling across the years presented could not be used as a reference for very similar slopes. Accordingly, the the presalt. Thus, when consider- Applied Assumptions. Due to the same obtained slope value could be ing volume projections for presalt absence of a global database on applied to the drilling phases in a subsea trees, the starting reference drilling efficiency, Petrobras’ internal presalt well, regardless of the respec- base should be the total volume of all data was used as an approximation tive lithology of each phase. deepwater and ultra-deepwater subsea of performance for the industry as a trees installed up to the current time. whole. Considering that the compa- This process for estimating historical nies supplying drilling systems are slopes was performed for each critical Slope. This would be the historical major corporations operating globally, item in the wells and subsea systems, slope estimated as described previ- this approach was assumed to faith- with each estimation considering a ously in this paper using analogs fully reflect the historical rate of gains careful selection of reference bases and for which historical cost bases and in drilling efficiency for the industry. applicable analogs, as illustrated in operational performance indicators the example above. Having obtained were available. Experience Curve Metrics. For the y- those historical slopes, it was now axis, hours per metre drilled was used, Once these three parameters (C , V possible to project how the costs of 0 0 being a physical measure of drilling and slope) were obtained for each each critical item would evolve for the efficiency, including useful time and critical item applied in presalt well next 20–30 years given the experience maneuvers. For the x-axis, cumulative construction and subsea systems, effects over that time period. To do drilled metres in the industry was the respective projections of cost (or so, three key parameters had to be used. performance) for each item would estimated: then be directly dependent on the Applied Data. Records from Petro- Current cost reference for each item future duplications expectation of bras’ wells were mined for drilling in the presalt context (C ). This is their respective volume reference times as the source for the y-axis, and 0 bases. Projections could thus be made a selection of international databases the item’s unit cost today, from which experience effects are applied for how all of the relevant reference were used to estimate the reference bases would evolve for the next base as a source of the x-axis. at each doubling in the cumulative production volume. It is important twenty years and for the expected cost Required Normalisations. Because in reduction driven by experience effects. to emphasise that the initial cost C0 this example there were no monetary should be the one from which the After completing projections for measures involved (only physical respective production process leaves individual experience curves for ones; i.e., metres drilled), adjustments the ‘laboratorial’ stage (during which each item, consolidated experience to eliminate the effects of inflation or the unit costs exhibit erratic behavior, curves for an oil well and for a subsea changes in commodity prices were not with no statistical meaning), migrating system as a whole were estimated. needed. to a more standardised production That estimation was done through a Historical Curve Parameters. To esti- process (from which experience curve complex simulation model developed mate the historical curve parameters, effects start to materialise). Another by BCG, which compatibilised the important consideration is the defini- several databases were tested, includ- different reference bases (V0) of the ing a consolidated base of Petrobras’ tion of a proper metric for the unit individual items’ experience curves offshore wells (about 1200), a base cost measurement. For instance, for into one single reference base (number of drilling performances with PDC the experience curve for drilling bits, of wells) allowing the projection of and tricone bits (65 wells in Albacora several metrics could be used, such consolidated cost curves for different field and 69 wells in Barracuda field, as cost per bit, well, phase or drilled types of wells and subsea systems respectively), and a base of drilling metre. considered for the presalt. As inputs, performances in horizontal and verti- this model receives the individual Volume reference base (V0). This is cal wells (about 40 wells in Albacora). the current cumulative volume from experience curves estimated for the Estimation of slopes for each of the which volume duplications (dou- critical items and some other specific samples was performed through a blings) will be measured. To assess characteristics of the presalt campaign, regression on a logarithmic base (log- this parameter, it is vital to be clear including water depth, well length and log) according to the formula: about the reference base applicable rock formation composition. T = a + b ∙ log D to the item under consideration. In Based on the estimation of consoli- d the case of subsea trees, the reference dated experience curves, the potential where Td is the drilling time per metre base applicable to the presalt is that of for investment reduction in wells and D is the drilled depth in metres, b subsea trees in deepwater and ultra- and subsea systems across the presalt which yields a slope of 2 . For all of deepwater conditions, given similar campaign could be calculated. In the considered historical data samples operating environment characteristics. present value, these investment reduc- (offshore wells in general, verticals In contrast, subsea trees used in tions added up to 11 percent for well

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Figure 1: Experience Curve Intensification Patterns

Laboratorial Substitution Anticipation Gap closing Specialization

Company 2009 2020 2020 Generic Benchmark Specialization

Company

Benchmark

Abrupt shift of the curve Abrupt or over-time shift Trend anticipation, but Changing procedures Specialization allowing in the very beginnibg of thoughout the cycle with reversion to the to match industry increased doubling the product cycle original curve standards (faster advancement throughout time in the curve) in the same time period drilling and completion and 10 percent the information from well testing and operating cycles, would be deployed for subsea systems. Combined, these logging tends to be quite significant. for the construction of specific parts savings amounted to about 8 percent On the other hand, these reservoir of the well instead of having only one of the total forecast investment for the evaluations can be very costly to type of rig responsible for all drilling presalt campaign (including FPSOs). perform in the presalt context. The and completion activities. This model experience curve approach recognises would allow not only the intensifica- the fact that, as these evaluations are tion of experience effects through Intensifying Experience Effects performed, Petrobras will gradually specialisation and faster ramp-up of The approach used to seek op- reduce the uncertainty (or gain experi- crew and equipment performances, portunities to intensify experience ence) on how to best exploit the fields, but also an optimised use of the asset effects in the presalt included analysis changing its reservoir evaluation needs base, allocating the most sophisticated of key experience levers (identi- from more sophisticated methods rigs only to the most demanding steps fied by running simulations in the (drillstem tests conducted by rigs and of the well construction process. In model described above) and a series complete sets of wireline logging) to this initiative, two large stochastic of workshops with Petrobras expert simpler mixes of evaluations (produc- models were developed. The first teams by function and key processes. tion tests with or without bottomhole model tested the economic feasibility During these discussions, the technical closure by intelligent completion of different specialisation scenarios teams identified typical experience- systems and simpler logging sets). (which, at the limit, included up to eight different types of vessels/rigs effect intensification patterns, reflected From this basic concept, a detailed participating in the construction of a in increased slope or downward initiative to identify the optimum mix well) and generated Petrobras’ demand vertical shift of the curve (Figure 1). of reservoir evaluations was conducted curve for each type of rig for the next As a result of these exercises, more for all production modules and blocks 20 years (considering a 95 percent than 150 intensification initiatives in the presalt, shedding light not only service level to meet the desired were identified, with 30 of them being on how information through time exploitation plan and production prioritised as having the greatest po- would benefit the individual well, but curve). The second model then used tential impact for the presalt wells and also on how the evaluation of each this specialised rig fleet as an input subsea systems. The identified initia- specific well impacted the reduction and applied a predefined day-to-day tives are diverse in nature and include of uncertainty of its module and field. allocation rule for each rig in order to not only technical matters related to As a result, this initiative yielded a 33 test stochastically the expected degree the concept, planning and execution percent cost reduction in the presalt of fleet idleness. of the offshore production systems, planned investments in reservoir but also organisational considerations, evaluations, while ensuring the same As a result, a robust optimised performance management drivers and value from the information gathered specialisation scenario has been identi- supplier relationship development. in such evaluations as in the original fied, considering the use of a top-hole Three of these prioritised initiatives plan. driller for the first and second drilling are illustrated below: Rig Specialisation Model. The expected phases (the ones above the salt layer), Reservoir Evaluation Prioritisation. scale of the production development a sixth-generation rig to perform the Given the heterogeneity of the presalt campaign in the presalt allowed the more complex drilling (salt and reser- reservoirs and the magnitude of the analysis of a new rig allocation model, voir) and completion activities, and a development campaign, the value of in which specialised rigs, with shorter light workover rig to perform the well

9 OXFORD ENERGY FORUM NOVEMBER 2011 testing and subsea tree installation, Basin Presalt Cluster (PLANSAL), the world regarding unconventional besides eventual necessary workovers. with the continued supervision of oil and gas resources in general, and This initiative has identified savings of Petrobras E&P top management and shales in particular. Even more, view- at least 9 percent in the rigs to be al- the support of BCG. points are being altered when it comes located in the production development to US energy supply and especially of the presalt fields, something made the ‘call’ on liquefied natural gas Conclusions possible given the concentrated scale (LNG) that was supposed to emanate of Petrobras E&P operations. The opportunities identified by from the United States. applying the experience curve concept Manifold Usage Optimisation. to the presalt development campaign The ‘story’ is that shale gas plays Traditionally, manifolds present very are now being rolled out broadly at essentially have made the USA energy limited experience effects over time, Petrobras, encompassing not only the independent, perhaps even moving the mainly due to their nonstandardised, presalt projects, but all of its major country into the column of natural gas project-by-project production charac- E&P development projects. In this exporters. (It already was an exporter teristics. In this context, an initiative context, Petrobras has incorporated by virtue of the first long-term LNG was conducted to analyse the tradeoffs the experience curve programme trade route, Alaska to Japan, albeit and potential experience effects structure as part of a systemic process one scheduled to go out of business at associated with a more standardised to reduce the total cost of wells and year-end 2011.) Moreover, shale gas use of manifolds in the sizeable presalt subsea systems, aiming for continu- abundance and production, and the campaign. The initiative analysed ous investment optimisation over the ability to deliver shale gas production different scenarios and was able to decades to come. ‘just in time’ through ‘manufacturing’ identify gains from the acceleration drilling and development schemes of experience effects representing * José Miranda Formigli Filho, Mauro that facilitate cost management, are roughly 17 percent of the cost of the Yuji Hayashi and Renato Da Silva expected to keep US natural gas prices overall subsea systems to be deployed Pinheiro, Petrobras; Jean Le Corre, low and stable for the foreseeable in the presalt campaign. Ilson Dalri, Jr., André Truzzi and future. The worldwide implications All in all, for each of the thirty Henrique Sinatura, Boston Consult- are clear: pressure on natural gas prioritised initiatives, the potential for ing Group prices everywhere by virtue of the low additional cost savings from experi- This article originally appeared in US Henry Hub price signal; pressure ence effect intensification was mapped, World Oil, September 2011, pp. 81–6. to shift gas supply contracts away resulting in an estimated aggregate Used with permission. from an oil price basis and toward capex savings of 17 percent in present a natural gas index like Henry Hub value for the presalt campaign as a (to the consternation of a number of whole. It is important to note that, gas exporting countries); widespread although this figure assumes a con- interest in proving up shale gas plays stant investment level for the FPSOs in every country that has potential. In (as they were not part of the scope of sum, the US experience would induce this project), it is certain that experi- a ‘golden age of gas’ worldwide. Gas ence effects are also applicable to these would be elevated from its status as a production units. If these effects were fuel for peak use and graduate to base included and correctly estimated, the load from its role as simply a ‘bridge’ total aggregate capex savings potential fuel to a cleaner energy future. Energy for the presalt campaign would most geopolitics would be altered. likely be greater than 20 percent. A The ‘backstory’ context is more separate internal Petrobras program nuanced and perhaps more realistic. has been carried out to optimise the Michelle Michot Foss Shale resource abundance is not in investments associated with FPSOs. looks at shale gas doubt. Recovery of shale resources Finally, all prioritised initiatives were is, however, fully contingent on the structured in individual projects, with development in the ability of industry players to achieve approaches, work plans and teams continued cost reductions extending assigned for their execution. Those USA into the less attractive portions of initiatives were then consolidated shale basins. This is no small chal- into an implementation program lenge, given the stubborn upstream The ‘Story’ and the ‘Backstory’ under the name Presalt Capex Opti- cost structure that companies face. mization Program (PROINV). In its Much has been written about the Shale basins are highly variable; current stage, this program is being impact shale plays are having on success is most likely where sufficient conducted until early 2012 under the the US exploration and production porosity and permeability exist to coordination of Petrobras’ Master businesses. Already, results achieved in enable commercial well completions. Development Plan for the Santos US drilling are altering views around Public concerns and opposition

10 OXFORD ENERGY FORUM NOVEMBER 2011 to drilling, and resulting pressures methane) and all locations (onshore, gas in place or GIP (canister desorp- for increased regulatory oversight, Lower 48 and offshore, predominantly tion at the wellhead) and the damage complicate matters and further strain Gulf of Mexico, as well as Alaska). done to shale production recovery costs. One arena of concern – the Various development eras introduced estimates with higher GIP measures amount of water required for hydrau- technology and other improvements that created the momentum needed to lic fracturing – has some legitimacy, that enabled the USA to sustain a re- push technology forward. Resource witnessed in drought stricken Texas coverable resource base of about 1600 play technologies – horizontal drill- and other sensitive locations. The trillion cubic feet (tcf) through the ing with multiple hydraulic fracture search for operational alternatives and 1990s. The most recent, 2009 resource stages to squeeze hydrocarbons out solutions is difficult, at best. Water is a assessment by the US Potential Gas of tight rocks – were the answer. powerful enabler of oil and gas devel- Committee puts recoverable natural Producers simply had to be able to opment. A relatively cheap substitute gas resources at about 2000 tcf with report recovery rates attractive enough is not in sight and water management the main difference being a more (about 30 percent) to justify capital approaches (recycling and so on) are pronounced contribution from shale expenditures through the mid- to late not easily done. The bottom line of gas basins. Notably, the USA also 1990s gas price swoon. the backstory context is not so differ- has abundant methane hydrates, with ent than US natural gas history to this the US Gulf of Mexico considered to The pronounced jump in US natural point, with higher and bumpier prices be the most prospective for eventual gas production year-over-year in while various stages and plateaus are commercial development. Some put September 2006 got attention. Subse- achieved in developing the potentially ultimate technically recoverable US quent years of production formed a rich but complex shale resource base. natural gas resources at thousands of trend that, by 2009, demonstrated the If deliverability from shales cannot tcf with these possible additions. turnaround in domestic gas supply be assured investment flows must be with all attendant future possibilities. drawn back to conventional plays, As usual, industry endeavor and shoved to the sidelines in the low gas success led to inevitable downward price environment, with their inherent “it is increased use of gas pressure on price, made worse with exploration (dry hole) risk. All of for electric power that is the 2008 recession and lackluster this certainly complicates and renders economic performance since then. The much more uncertain the benign driving future expectations buildup in gas supply crashed head on world view that has been put forth. most strongly” with deterioration in demand, result- ing in the 1990s-style low price deck What can be expected for the foresee- witnessed today. (Figure 1) able future? Will recoverable resource, geological favorability plus industry ‘Technically recoverable’ is the key Deployment of resource play tech- know-how, deliver a profitable, sus- terminology. The US oil and gas nologies also has been applied in new tainable business at, say, the roughly industry has demonstrated many times oil plays. A turnaround in US oil $4 per million cubic feet (mcf) that its resilience and ability to prove up production, initially from the North has prevailed since late 2009? Or, new tranches of hydrocarbons in Dakota Bakken but later in the Texas will a higher price deck be needed response to price signals and with Eagle Ford and other locations, was to provide adequate returns, encour- innovation. Yet innovation and, more achieved. In many respects, revitalised age interest, and keep investments pointedly, market penetration of domestic oil production is even flowing? new technology in this industry is more significant than the natural gas slow. Drilling in the Texas Barnett turnaround. US oil supply had been shale began in the early 1980s as disparaged for quite a long while. The Facts companies searched for then scarce Coupled with natural gas liquids The US natural gas resource base opportunities in the USA. Higher oil (NGLs) production, revenues from is known to be robust. Ever since prices and a variety of policy changes the more valuable liquids plays have disputes about reliability of natural geared towards debottlenecking the helped to offset losses in dry or gas supply in the 1970s, a progres- natural gas industry and reducing, and non-associated gas locations. Make no sion of resource assessments have ultimately eliminating, federal control mistake: without the benefit of higher affirmed what many had argued of wellhead prices spurred activity. It oil prices, and without the possibility persistently. The United States has a has taken more than thirty years for of liquids production to cover drilling large technically recoverable resource the combination of hydraulic fractur- economics, the US natural gas ‘patch’ base considering all geological features ing and horizontal drilling, neither would be in a much different, and (conventional reservoirs and uncon- one new in concept or practice but much more difficult, shape today than ventional sources – meaning ‘tight’ both modernised and transformed into it is. To a large extent, companies have formations of all types and ‘resource’ ‘off the shelf’ oil field service prod- been able to retain their skilled (if ex- plays in which hydrocarbons are ucts, to yield the results demonstrated pensive) exploration and development extracted directly from the source in the US shale plays since 2006. In staffs, honour leasehold obligations, rocks, including shales and coalbed truth, it was new ways of measuring continue to attract investment interest,

11 OXFORD ENERGY FORUM NOVEMBER 2011

regulatory requirements that have Figure 1: Natural Gas Production Trends broad implications. Laws and rules are evolving across all jurisdictions – 2,500 20 cities, counties, states, and the federal level. They are intended to address 15 2,000 nuisances like traffic and roads, and U.S. Dry Gas Production (Bcf) 10 public health concerns about clean air and water. Coupled with complex 1,500 5 geology and inherent development risks in the shale plays, the added 0 1,000 cost and complexity of policies and

Production, Bcf regulations have substantial negative

-5 Y-Y percent change Sep 86–Mar 01 connotations for natural gas upstream 500 38% Mar 01–Sep 05 Sep 05–Aug 11 costs and profitability. At an assumed 47% -10 Y-Y Chg Dry Gas Production -21% Henry Hub price of $4, US produc- 0 -15 ers already are dealing with negative margins given average breakeven Jan-86 Jan-88 Jan-90 Jan-92 Jan-94 Jan-96 Jan-98 Jan-00 Jan-02 Jan-04 Jan-06 Jan-08 Jan-10 Jan-12 costs of $5–6 (our work and review of numerous proprietary studies). A Author analysis based on production data as reported by US Energy ‘balancing’ price of $6 is most often Information Administration bandied about. This is well within the comfort zone of large customers and crucially, given US economic con- feedstock as well as fuel for US petro- that also deal in petroleum products, ditions, contribute jobs and income chemicals and manufacturing), or even as long as oil prices remain at current largely because the oil price premium to boost natural gas vehicle market levels. Sensitivities begin above $6, over gas provides a safe haven. The share are contingent on reliable supply but in various ways producers have precipitous drop in gas-directed drill- deliverability at competitive prices. signaled that $8 may be what it takes ing- a shift of 299 rigs by November Regulatory actions that could spur to attract and retain drilling invest- 2011 from a high of about 1200 in increased utilisation are very likely ment. (Figure 2) June 2005 – and the parallel surge in to be contradicted by an assortment The bane of the natural gas industry is oil-directed drilling – a gain of 970 or of decisions that would make natural price volatility, the essential trade-off so rigs from the low of 140 in June gas (and domestic oil) more scarce in the ‘grand bargain’ that constituted 2005 – were stunning, in retrospect. and expensive, rather than less. These regulatory restructuring in the USA For many market watchers, the shift range from rules that could affect (and Canada) since the 1980s. High couldn’t happen soon enough and drilling and well completions directly volatility – and volatility has been the continued additions of associated (hydraulic fracturing and water use higher for natural gas in its traded gas production made the tempered for drilling) to endangered species history than for oil and most other drilling activity a Faustian bargain. protections, air emissions and other The future is clouded by the rapidity of the shift away from gas drilling, the Figure 2: Average Breakeven Costs (All-in) for A Sample of US Natural Gas stress on upstream properties induced Producers by lower natural gas prices, and the great uncertainties created by the 8 whipsawing of events and policy and 10% Return regulatory actions that will affect both supply development as well as how 6 U.S. Cash Exploration natural gas is utilised. Henry Hub Costs $/MCFE Spot Price $4/MCF 4 U.S. Cash Operating Looking Ahead Costs $/MCFE $ per MCF Indeed, it would be fair to ask wheth- U.S. All Source FD er defeat might be snatched from 2 Costs $/MCFE the jaws of victory. All ambitions to use natural gas more aggressively for power generation (attractive given its 0 cleaner burning attributes), to re-build 2009 2010 the US industrial base (numerous proposals are being floated for NGLs Based on analysis by author and Miranda Ferrell Wainberg, senior researcher, offtake and natural gas is an essential Center for Energy Economics, using company financial reports.

12 OXFORD ENERGY FORUM NOVEMBER 2011 commodities – fosters perceptions Trisha Curtis critical advances in modern petroleum that natural gas is unreliable. While development: horizontal drilling and natural gas utilisation could evolve in describes the building hydraulic fracturing. Advances in the other directions, it is increased use of art and science of these petroleum gas for electric power that is driving blocks of the North development technologies are now future expectations most strongly. In American petroleum migrating to unconventional shale/ power generation, the cost of building tight oil plays throughout the United natural gas plants is relatively cheap. renaissance States. At times the cost of fuel has been In this article references to shale oil very expensive since restructuring was In 2009, the United States became the refer to a broad range of so-called completed in 1992, especially relative world’s largest producer of natural gas unconventional oil development to coal. Lower cost, abundant natural and all indications are it will remain including tight and carbonate oil gas with lower and more stable prices so for the next twenty years. The shift formations. US shale oil production now offers an alluring vision. The in expectations on domestic natural has taken root in North Dakota and main tensions centre around reliance gas output took place across a remark- Texas where combined production on coal, traditionally purchased ably short time span. In June 2003, has risen from negligible volumes to on long-term contracts and, until Alan Greenspan, Chairman of the 500,000 barrels a day (b/d) in just recently, cheaper than gas but more U.S. Federal Reserve, testified before three short years. These shale oil plays polluting, and ambitions to displace a the Congress Committee on Energy have helped raise US liquids produc- considerable amount of coal capacity, and Commerce that the USA was in a tion to its highest level in nearly a if not all of it, with natural gas-fired state of crisis due to declining natural decade, more than offsetting Gulf generation. Yet, periods when natural gas production. A consensus among of Mexico production losses from gas prices have moved strongly are both policy makers and much of the leasing and development delays after those when deliverability has been a domestic petroleum industry led to an the Macondo spill. It is no longer problem, either because drilling lagged accelerated programme to construct unthinkable that US production alone growth in demand (the situation facilities to import liquefied natural could rise by over 2 million b/d in the coming out of the 1990s gas bubble), gas (LNG). Approximately $30 billion next ten years. because of short-term disruptions was spent to construct LNG import (hurricanes that affected offshore facilities over a 3–4 year period, In a period in which the US economy production), midstream bottlenecks but the simultaneous turnaround in is suffering from high unemployment (pipeline outages), and the like. It is domestic gas output was large and and lagging economic growth, the worth noting that periods of higher quick. Today these import facilities petroleum industry remains a bright price volatility have occurred against are operating at less than 10 percent spot. Figure 1 illustrates the ratio the backdrop of expanding resource capacity. Some LNG facilities are now of national unemployment to four assessments and, in some instances, applying for licences to export Ameri- prominent oil- and gas-producing underlying growth in deliverability. can natural gas to world markets. states. For the state of North Dakota, the benefits from oil production are The future story hinges on many This remarkable shift in the outlook widespread. Taxes on oil production contingencies. Stay tuned! for natural gas production directly and extraction have allowed the state resulted from the application of two to put millions of dollars into a legacy This article is drawn from a new Figure 1: Ratio of State Unemployment Compared to USA working paper posted by OIES, The Outlook for US Gas Prices in 2020: 1.2 Henry Hub at $3 or $10? by Michelle Michot Foss. 1.0 US

0.8 North Dakota

0.6 Texas Ratio Oklahoma 0.4 Pennsylvania 0.2 Louisiana 0.0 2006 2007 2008 2009 2010 2011

Source: Data from the Bureau of Labor Statistics, seasonally adjusted, data for April of given year.

13 OXFORD ENERGY FORUM NOVEMBER 2011

found in formations characterised by Figure 2: Unconventional Production as a Percentage of US Production both low porosity and low permeabil- 8000 ity. Essentially the rock is hard and tight with minimal natural fractures; U.S. Field the lack of porosity (holes) and 6000 Production of permeability (connections) prevents Crude Oil the oil from easily flowing out.

Bakken (Oil and Traditional vertical well technology 4000 Liquids) and production methods touched only a portion of the producible rock. Niobrara (Oil and Liquids) This left the wellbore (the drilled 2000 Unconventional Production from hole exposed to the producing rock) Thousand barrels per day Bakken, Niobrara and Eagle Ford Eagle Ford (Oil exposed to only a small portion of is 10% of US production, or and Liquids) roughly 600,000 b/d the tight oil formation, thus not 0 allowing it to be produced to its true potential. Attempts to access shale

Jan-1990Jan-1992Jan-1994Jan-1996Jan-1998Jan-2000Jan-2002Jan-2004Jan-2006Jan-2008Jan-2010 oil in North Dakota using horizontal drilling technology had been tried Source: HPDI and EIA Data, EPRINC Calculations (conservative) in the past, but had not advanced to Note: Bakken production does include some NGLs (natural gas liquids) but longer laterals and multiple hydraulic is primarily oil; Eagle Ford includes more NGLs and about 20,000 b/d are fracturing stages in the correct layer oil; Niobrara does include some NGLs, but is primarily oil. of rock. This technique was pioneered in the shale gas revolution and applied to oil prone shale in North Dakota’s fund, to invest in water resources, competitive operating environment is Bakken formation where its success communities, education and research, characterised by low utilisation rates, has triggered a frenzy of investment and to lower income, corporate, and poor margins, routine closures and across the country’s liquid basins. property taxes. In the fiscal year of maintenance, and now the threat of (Figure 3) 2011 oil taxation brought in $977.8 additional capacity losses from per- million. manent closures. With the necessary development in infrastructure through North Dakota’s Bakken Beyond the direct benefits of pipeline and rail, light sweet Bakken improving the fiscal outlook for North Dakota is now the fourth oil could supplant portions of Middle oil-producing communities and largest oil-producing state with East imports on the East Coast or improving employment opportunities, production topping 464,000 b/d other refining sectors in the United rising oil production (both crude in September 2011. (Figure 4) The States and give refiners a potentially and natural gas liquids) provides majority of this production is Bakken lower cost alternative than waterborne cost-effective import substitution and oil from the Bakken and Three Forks imports. new competitive opportunities for formations. It is conventional, light- American refineries and petrochemical Due to a rise in Canadian imports sweet crude oil, trapped 10,000 feet plants. Most of the crude oil com- overtime and the increase in US below the surface within shale rock. ing out of these shale basins is of production primarily from the The Bakken shale play consists of premium quality, very light and sweet. Bakken, the two global crude oil three layers, an upper layer of shale Bakken oil from North Dakota and benchmarks, Brent and WTI, have rock, a middle layer of sandstone/ Montana typically has an API grav- diverged and this currently puts Brent dolomite, and a lower layer of shale ity of over 43 degrees. Light sweet at $10 premium to WTI. This means rock. The middle sandstone layer is crude oil is well matched to the less that East Coast refineries that import what is commonly drilled and fracked complex refineries on the East Coast waterborne crude are paying a higher with the horizontal lateral today. and some in the mid-continent. These price than Midwest refineries which The Bakken and underlying Three refiners typically operate on very have access to domestic produced Forks formations are part of the small margins and face fierce foreign crude, currently selling at a discount. larger Williston Basin, which encom- competition. Most refiners on the East Figure 2 shows unconventional passes Saskatchewan, Manitoba, North Coast must purchase high cost crudes production as a percentage of US Dakota, Montana, and South Dakota. from Nigeria and the Middle East – production. Bakken producing zones are mainly also subject to fierce competition from present in Western North Dakota, imports of gasoline components from Southern Saskatchewan, and Eastern European and even some Asian refin- The Plays Montana. Beyond the Bakken and eries – that can be processed in less Shale oil has historically been difficult Three Forks there are other potential complex facilities. This high cost and and costly to produce because it is rock members within the Williston

14 OXFORD ENERGY FORUM NOVEMBER 2011

NGLs (natural gas liquids), and dry Figure 3: US Shale/Tight Oil Formations gas respectively with play zones rang- ing in depth from 4000 ft. to 14,000 ft. As the play moves eastward across Texas from oil to gas it increases in Bakken depth, thermal maturity, and API gravity. Right now the most prolific part of Utica the Eagle Ford play is the wet gas/ NGL/condensate window. Conden- Niobrara sate valuations are similar to oil and remain a major target in exploration Granite and development efforts. Oil produc- Monterey Wash tion is increasing in the Eagle Ford Perminian Basin and is currently around 20,000 b/d, Eagle Tuscaloosa but will likely increase as necessary Ford take-away infrastructure comes online. Close proximity to the Gulf Coast refinery district has helped the Eagle Ford take off quickly, but substantial infrastructure constraints still ex- Source: EPRINC Map. Formations are not to scale and indicate roughly ist. Figure 5 shows liquids and gas their location for visual understanding. This is not inclusive of all US shale/ production from 2008 to 2011. tight oil.

Basin that could offer further oil as other major shale plays, the Eagle Colorado’s Niobrara production opportunities. Ford is now experiencing significant Unlike the success seen in the Bakken investment from both major and inde- What makes the Bakken unique from and the Eagle Ford, the Niobrara has pendent oil companies, accompanied other formations in the United States proven to be more difficult to crack. by high acreage costs, and multiple and the world is that it is a continuous Some initial well results were extreme- joint ventures. oil accumulation, possibly the largest ly promising, but over the past year in the world according to the USGS. The Eagle Ford is more of a carbon- production results have varied. Many It is an over pressured system which ate than a shale, but is produced in wells being drilled in the Niobrara are is in part why many wells experience the same manner as the Bakken with still vertical and companies are still such high initial production. The high horizontal drilling and multi-stage testing the prospectivity of much of pressure in the formation suggests fracking. It includes three hydrocar- the play. The most notable success has that the oil is contained within the bon windows: oil, wet gas/condensate/ been seen in Weld County in eastern petroleum system. This means that the oil remains in place and is tightly Figure 4: North Dakota, Montana, and Bakken Oil Production contained throughout the geologic structure. 500

While Bakken oil is of the highest North Dakota 400 quality, very light and sweet, it still Oil Production suffers from a discount due to its Eastern distance to major refining markets 300 Montana Oil and limited take-away capacity. This Production discount has substantially narrowed in 200 recent months with significant rail and Bakken (North pipeline developments. Dakota and Montana Oil Thousand barrels per day 100 and Liquids) Southern Texas’ Eagle Ford The Eagle Ford in south Texas has 0 become something of an overnight miracle. After years of proving up the 1-Jan-20071-Jul-20071-Jan-20081-Jul-20081-Jan-20091-Jul-20091-Jan-20101-Jul-20101-Jan-20111-Jul-2011 Bakken, drillers began an active explo- ration and development programme in Source: State production data from North Dakota Pipeline Authority, the Eagle Ford around 2008. As well Bakken production HPDI

15 OXFORD ENERGY FORUM NOVEMBER 2011

similar to the Eagle Ford in that it has Figure 5: Eagle Ford Liquids and Gas Production three potential hydrocarbon windows for production: oil, wet gas/conden- 900 160 sate/NGLs, and dry gas respectively (from west to east). Prospective drill- 800 GAS (left hand scale) 140 ing depths in Ohio range from 3500 700 Oil and Liquids (right hand scale) 120 ft. to 10,000 ft. The formation is 600 interlayered with shale and carbonate. 100 500 Time will tell if this play is in fact 80 400 similar in productive nature to the 60 Eagle Ford and if so may have a Thousand mcf/d 300 significant economic impact on 40 200 Thousand barrels per day employment in the rust belt as well 100 20 as the depressed refining sector on the East Coast, including refineries in 0 0 Ohio and Pennsylvania.

1-Jan-2008 1-Jul-2008 1-Jan-2009 1-Jul-2009 1-Jan-2010 1-Jul-2010 1-Jan-2011 1-Jul-2011 Looking Ahead Source: HPDI North America is at the beginning of a turnaround in domestic crude oil production driven by the same Colorado, known for its historical gas is accelerating and drilling is under- technology that sparked the shale gas production. way. Only a few well results have revolution. New crude oil, condensate, been released, but thus far the play The Niobrara is not a pure oil play and natural gas liquid supplies, com- looks extremely promising. like the Bakken. Weld County for bined with the current surge in natural example ranges from more gas pro- The Utica sits well below portions gas production, offer the promise of a duction to more oil production as you of the Marcellus and reaches from renaissance in petrochemical process- move north. The Niobrara – a broad eastern Ohio into Pennsylvania, but ing and petroleum refining industries. name that actually includes multiple the most prospective liquid prone This dramatic increase in domestic shales and basins – spreads across area is eastern Ohio and parts of oil production from unconventional parts of Colorado and Wyoming and Western Pennsylvania. According to reservoirs does not come without parts of Nebraska and is a mix of some images, the Utica source rock complications and constraints. In chalk, limestone, and shale. While this extends into New York, Virginia, West the coming years, both industry and play is not an overnight victory, many Virginia, and Kentucky as well. The policy makers will face challenges to companies are doing exceptionally Utica has received a lot of attention bring about essential infrastructure to well in Weld County and companies due to the success seen in the Bakken expand needed takeaway capacity with are still testing different fracking and Eagle Ford. It is also structurally the onset of new oil plays. techniques. Additionally, unlike typical shale wells Figure 6: Niobrara Liquids and Gas Production in the Bakken and Eagle Ford, which have high IP (initial production) rates 700 70 and substantial decline rates, some GAS (left hand scale) Niobrara wells indicate a moderate IP 600 60 rate and a flatter decline curve. With Oil and Liquids (right hand scale) a better understanding of the geology 500 50 across the play and application of 400 the appropriate completion methods, 40 the Niobrara may yield increasingly 300 30 positive results in the future. Figure Thousand mcf/d 6 shows liquids and gas production 200 20 from 1990 to 2011. Thousand barrels per day 100 10

Ohio’s Utica 0 0 In the past several months notable independents and major oil companies Jan-1990Jan-1992Jan-1994Jan-1996Jan-1998Jan-2000Jan-2002Jan-2004Jan-2006Jan-2008Jan-2010 have leased up sizeable amounts of Source: HPDI land in Eastern Ohio. Permit activity

16 OXFORD ENERGY FORUM NOVEMBER 2011 Horizontal drilling and multistage Samer Ashgar on over the years a huge water injection fracking technology used to unlock and oil-gathering infrastructure has shale gas has been proven in the the prudent use been put in place. In most reservoirs Bakken and Eagle Ford, but also has the oil flows naturally because of the the potential to yield additional crude of technology and healthy reservoir pressure supported volumes from plays on the periphery reservoir management by peripheral water injection. as well as older fields. Multiple shale best practices for The super-giant Ghawar was dis- plays not mentioned here have the covered in 1948, came on stream in potential to yield significant oil large carbonate 1951 and was put on peripheral water production results with time and injection in 1965. The field is 280 technology. The Granite Wash in reservoirs kilometres long and 40 kilometres at Texas and Oklahoma, for example, its widest. The main carbonate Arab- was historically known for its gas More than 60 percent of the world’s D reservoir produces an Arabian light production, but is now seeing drilling oil reserves reside in carbonate crude oil. The main strategic develop- in multiple layers of rock beneath the reservoirs. Saudi Arabia has the lion’s ment philosophy that Saudi Aramco gas. Oil that could not previously be share of these ‘giant’ hydrocarbon adheres to is maximising oil recovery. reached underneath the gas is being reservoirs. Given this magnitude of Some of the tenets of reservoir man- tapped and produced and offers a the resource, its exploitation and agement include low overall depletion prime example to the potential of new management becomes paramount and rates, maximum contact with the oil production from older fields across its management is the responsibility of reservoir rock, application of advanced the United States. In fact, the gas is Saudi Arabia’s national oil company, diagnostics, implementation of fit-for- said to be helping with the production Saudi Aramco. While Ghawar, the purpose state-of-the-art technologies, of oil in this play. Additionally, the world largest oil field, has been the and above all prudent reservoir well-known Permian Basin is seeing focus of much attention, the company management best practices. Adhering significant drilling activity and pro- manages several other large carbonate to these tenets has resulted in produc- duction with multiple shale and tight and clastic fields, producing both tion sustainability, outstanding sweep oil plays. oil and gas. Over the years Saudi efficiency, managed watercuts and Rising oil and gas production can Aramco has implemented best-in-class optimum reservoir performance. The generate sustained employment reservoir management and production philosophy has been in continuous growth and expand the national practices in its fields to play the role learning and improvement. economy. For American policy of an efficient, stable, and reliable oil Another excellent example of the makers the emerging paradigm shift producer that the world can depend benefits of this strategy is demon- in the outlook for North American on for their energy needs. This article strated with the performance of supplies of oil and gas creates both sheds light on some of the prudent Saudi Arabia’s oldest producing field, opportunities and challenges. Embrac- reservoir management practices that Abqaiq, which has been in production ing the new economic opportunity the company has adhered to over the since 1948. It continues to produce will provide revenue for state and years and the direction it is heading today with peripheral water injection, local governments and much needed to maintain that leadership role in low watercuts, and very high ultimate economic activity, but it will also providing reliable oil supply to the oil recoveries, all without tertiary require sophisticated management of world. or enhanced oil recovery (EOR) the challenges to the environment and implementation. the accompanying rapid industrial The Past development. From its beginning some 75 years ago, The Present Saudi Aramco has come a long way. Reservoir management at Saudi The company has positioned itself Aramco has adhered to the philoso- as a world leader in managing large phy of maximising oil recoveries while or super-large reservoirs. A lot has ensuring sustainable oil production. been shared in the literature about This has come about through life cycle Saudi Aramco’s reservoir management economics with the adoption of latest strategies, especially as it applies to technologies. The mantra has been to Ghawar, Abqaiq and a few other large lengthen the production plateau in fields. Saudi Aramco has a portfolio of the most cost-effective manner, while several large reservoirs, both carbon- maximising ultimate oil recovery. The ates and clastics, containing light to large carbonate reservoirs have been medium-heavy oils that have generally produced under peripheral water high porosities and permabilities. injection at a predetermined low Most of the reservoirs were developed depletion rate. This allows a delicate with peripheral water injection, and balance between gravity and other

17 OXFORD ENERGY FORUM NOVEMBER 2011 physical forces to help maximise the these technologies at a scale and high data (pressure, temperature, rates, ultimate recovery. degree of complexity for Saudi Ara- etc.) were transmitted in real-time to mco and, arguably, for the petroleum headquarters for monitoring, analyses The main success factors for opti- industry. It sets the stage, in many and proactive reservoir management mum reservoir management at Saudi respects, for a new era in upstream and well control. Aramco have been a close collabora- projects, specifically in the area of tion between engineering and other The production performance for real-time reservoir management. geosciences, coupled with the applica- Haradh-III has been excellent. The tion of fit-for-purpose technologies. A technology that has provided field has been meeting its production The role of new technology can be significant dividends in Haradh-III requirements. The reservoir perform- exemplified in several case studies, was real-time geosteering of wells. ance and reservoir pressure behaviour the Haradh Increment III, the newly The essence of this technology is the have met or exceeded the planned developed Khurais field, and other ability to steer the well as it is being criteria. Watercut from these fields has large scale carbonates. drilled using advanced equipment been very low and the productivity that transmits real time data from of the wells has been very high. The thousands of feet deep to identify the use of the cutting-edge technolo- trajectory of the well as well as the gies described earlier has resulted in “Reservoir management at reservoir quality. The objective is to production sustainability, managed Saudi Aramco has adhered place the well in a location to achieve (low) watercuts, and development cost to the philosophy of the desired well production rates. effectiveness (Figure 1). maximising oil recoveries Another technology that played a Since then, Saudi Aramco has applied key role was the Intelligent Field, while ensuring sustainable these game-changer Intelligent Field which was an integral part of real- technologies to all the new field devel- oil production” time reservoir management plans for opments and is retrofitting the older Haradh-III and Khurais complex. The fields to be Intelligent Field compli- producers and injectors in addition ant. It has given the opportunity to Haradh field is the southernmost part to dedicated observation wells were continuously monitor, manage and of the Ghawar complex and covers an heavily instrumented with Perma- optimise wells and field performances area that is 75 kms long and 26 kms at nent Downhole Monitoring System in real-time. its widest. The field consists of three (PDHMS), multiphase flow meters, sections of approximately equivalent and remotely controlled chokes for Advances in technology and leverag- reserves and each with a production real-time measurement of fluid rates ing best-in-class reservoir management capacity of 300,000 b/d. Production and well control. The surveillance practices have enabled Saudi Aramco at Haradh-I started in 1996, followed master plan called for a network of to maximise waterflood oil recovery by Haradh-II in 2003 and Haradh-III wells providing full areal coverage to before deploying more difficult op- in 2006. The field increment develop- monitor key reservoir performance at- tions such as EOR, which will not be ments spanning a period of over a tributes continuously. The Intelligent needed for a long time. The focus has decade provide a unique opportunity Field was used to monitor reservoir always been on ‘ultimate’ oil recovery to gauge the impact of technologies. performance during pre-production rather than ‘immediate’ oil recovery. Haradh-I was developed using verti- and production periods, and the This commitment to a long-term view cal wells exclusively, Haradh-II was developed using horizontal wells, Figure 1: Relative Unit Well Costs and Oil Rates for Haradh-III and Haradh-III was developed using maximum reservoir contact (MRC or MRC/Smart horizontal wells with multilaterals), 10,000 b/d smart completions with downhole 1.0 Inflow Control Valves (ICVs) for flow control, extensive use of real-time Horizontal 0.7 geosteering, and Intelligent Field 6,000 b/d

initiatives. The average well produc- Oil rate tion capacity rate in Haradh-III was Vertical targeted at 10,000 b/d and a total of 3,000 b/d 0.35 32 smart MRC wells were drilled to provide the targeted production ca- Relative unit costs, dimensionless pacity for the entire increment which is about three times less wells than HRDH I 1996 HRDH II 2003 HRDH III 2006 Vertical Horizontal MRC/Smart HRDH-I and 36 percent less wells than HRDH-II. Haradh-III stands Source: A.O. Kaabi, et al. ‘Haradh-III: Industry’s Largest Field Develop- out as a flagship in the convergence of ment’, SPE Production and Operations, pp. 444–7, November (2008).

18 OXFORD ENERGY FORUM NOVEMBER 2011 has ensured optimum exploitation of Intelligent and fully autonomous fields Through in-house research and by the company’s oil resource by keeping working with its technology partners The fully autonomous fields represent the depletion rates low, and improving Saudi Aramco is expanding the a target for the Intelligent Fields. The the secondary oil recovery through envelope in the area of deep reading, vision is to capture real-time data, sustainable development. or the ability to use direct measure- monitor the fields, facilities and wells ments in the 100 to 1000+ metres of remotely, visualise the data, evaluate reservoir space or depth of investiga- The Future reservoir and field performance and tion. The concept of deep diagnostics proactively make the best possible Some of the reservoir management using electromagnetic or seismic decision. The vision is analogous to strategies described earlier are the surveys helps in illuminating the an airplane that is on auto-pilot. The current state-of-the-art and Saudi reservoir, akin to an MRI or x-ray for pilots will be there but the field will Aramco has taken a leadership role in the human body. EM and seismic help be on ‘cruise control’. They can look implementing them in the company’s with better reservoir characterisation, at all the real-time streaming data large reservoirs. Some specific technol- deep measurements of key reservoir flowing into their consoles and steer ogy concepts, such as the MRC well properties, fluid front monitoring, and the reservoir/field towards the best construction and smart completions determination of fluid saturations and course. were developed specifically within the their changes with time. Significant company for deployment. The quest This will involve heavily instrument- value is being realised by combining to produce the maximum oil from ing the fields and facilities, placing the strengths of both seismic and EM its reservoirs continues and the next sensors in individual wells, both at the into one unified approach, and focus- frontier is to increase the ultimate surface and subsurface, to continu- ing on delivering an integrated EM oil recovery beyond conventional ously measure production/injection and seismic solution for both borehole waterflooding. rates, pressures, temperatures and and surface measurements. Surface stream data in real-time. The wells will gravity, as well as borehole gravity also have advanced smart completions techniques, is also being explored to with downhole remotely activated add value to this picture, thanks to the “Technology by itself may valves which enable flow optimisation recent advances in sensing capabilities. not necessarily improve of each lateral in multi-lateral wells. EXPEC ARC is working to develop reservoir performance. Most elements have been developed hyper-sensitive devices to measure and were described earlier. In addition, gravity accurately in the microgal … the efficient use of advanced simulation tools such as range. technology to improve Saudi Aramco’s GigaPowers reservoir simulator capable of efficiently simu- Another research initiative taken by performance is in the lating multi-billion cell models will be EXPEC ARC is in the area of nano- hands of the people who a key in realising its vision. technology. The researchers plan to develop and deploy these deploy in-situ reservoir nano-agents (RNA) or RESBOTSTM to ultimately Advanced reservoir monitoring and technologies” monitor reservoir parameters (e.g. surveillance temperature, pressure, pH, salin- Reservoir monitoring and surveillance ity, saturation, and so on). The first Saudi Aramco, through its upstream (M&S) plays a very important role generation RNAs or ‘smart tracers’, arm (EXPEC Advanced Research in understanding the reservoir and equipped with a sensing/activation Center – EXPEC ARC), has invested improving reservoir performance. The mechanism, have been manufactured heavily in R&D and is accelerating ability to track saturations and fluid and are currently being tested. The ul- the pace in the deployment of new movements in the reservoir helps in timate goal is to use them for reservoir technologies. The focus is on game- understanding reservoir characteristics, monitoring and surveillance, in-situ changer technologies that will have and in optimising oil sweep efficiency. sensing and intervention to improve a long-term impact on reservoir and This information also helps in iden- reservoir performance. recovery performance. Some of the tifying and minimising bypassed or new research and technologies on trapped oil and in intervening with In the framework of Next Genera- the drawing board include pushing corrective actions. Saudi Aramco has tion Intelligent Field developments, the envelope from intelligent to fully made a concerted effort to improve its the combination of ad-hoc logging autonomous fields (or the Next Gen- M&S capabilities over the years and surveys, with sensors permanently/ eration intelligent fields), advanced continues to do so. Some aspects of semi-permanently installed at the monitoring and surveillance methods, this emerging research include deep surface and inside borehole comple- application of nano-technology in diagnostics using electromagnetics tions will likely boost the deployment reservoir engineering, deep diagnostics (EM), seismic and gravimetry meth- of gravity, electromagnetic and seismic with the ability to ‘illuminate’ the res- ods, and the use of in-situ sensing and methods for reservoir mapping and ervoir, and tailored advanced recovery intervention through nano-technology monitoring. The challenge is to such as Smart Waterflooding. applications. integrate these illumination techniques

19 OXFORD ENERGY FORUM NOVEMBER 2011 into the reservoir life cycle and to boosting production rates, but to test when an aboriginal discovered that leverage their strengths for reservoir the feasibility of different methods if bitumen oozing from the oil sands characterisation and production and acquire field data. Sometime in on the river bank was mixed with the monitoring. The ultimate goal is to the future appropriate decisions can be tar or pitch from spruce trees, it made increase the recovery factors. made regarding the implementation of a far superior caulking material for one, or all of these methods to boost canoes than pitch alone. Advanced recovery technologies the recovery factor and the production As sources of lighter grades of crude rates. Saudi Aramco has primarily focused oil become depleted and what remains on waterflooding methods to increase increasingly inaccessible for the oil recoveries. Currently there are Postscript international oil industry, its attention has turned to unconventional oil and no enhanced oil recovery projects by Technology by itself may not neces- gas. A decade ago few knew or cared the traditional definition of EOR. sarily improve reservoir performance. about this sub-sector of the petroleum The company has started to look at Ultimately the efficient use of technol- business. By 2010 according to IHS advanced and fit-for-purpose EOR ogy to improve performance is in the Herold, unconventional resources methods including the impact of water hands of the people who develop and accounted for 25 percent of global oil chemistry on recovery. This includes deploy these technologies. Petroleum and gas M&A value; US and Canadian efforts on research and funding for engineers cannot work alone anymore. unconventional oil and gas deals game changing technologies that will They must work with researchers, amounted to $100 billion over the make a big difference on recoveries geoscientists, facility engineers, and past five years. In 2009 and 2010, 30 including low cost chemicals, and others to best develop and manage to 40 percent of all acquisitions were applications of nanotechnology. reservoirs. Multidisciplinary asset and by Asian NOCs. They seek a position functional teams are common and One of the options being considered in these vast resources and the techni- essential in almost every aspect of the is the use of ‘Smart Waterflooding’. cal expertise of the local companies, upstream value chain. Here the idea is to adjust injected who have been testing technologies water to an optimised composition (in to develop them, but lack sufficient terms of salinity and ionic composi- capital to launch major projects. tion) into the reservoir instead of any Paradoxically, while unconventional available water that may currently oil and gas have attracted a large share be injected or planned to be injected. of M&A capital, their contribution to Recent research has shown salinity world oil supply is unlikely to exceed and/or ionic composition can play 10 percent by 2030. Technological an important role in oil recovery breakthroughs could change this, but during waterflooding and may yield it is argued here, this is unlikely. significant additional oil recoveries when compared to unoptimised water injection. This option has several The Challenge advantages compared to EOR includ- To produce most forms of unconven- ing achieving a higher ultimate oil tional oil and gas we have to either recovery with minimal investment in reverse or accelerate geology; this current operations and infrastructure, Robert Skinner takes significant inputs of energy and it can be applied during the early assesses the other natural resources, materials, lifecycle of the reservoir as opposed manpower and technical ingenuity. to EOR, and the payback is faster. technological For example, to convert the kerogen, Saudi Aramco has initiated a strategic challenge of the precursor to hydrocarbons, in the research programme in this area to extensive, geologically immature shale explore the potential of increasing oil producing heavy oil deposits of south western USA, we recovery by tuning the injected water must hurry up geology. Similarly to properties. Laboratory studies and produce the gas and oil that has not preliminary field trials have shown a migrated out of mature shales requires Introduction lot of potential. prodigious quantities of water, chemi- Saudi Aramco is also conducting From the Indus Valley to Mesopota- cals, propants and energy to fracture research and exploring the potential mia, California and northern Canada, the shale to increase its permeability. of other EOR techniques in their natural seeps of degraded petroleum The 4 or 5 trillion barrels of heavy carbonate reservoirs. These include or bitumen have intrigued humans for hydrocarbons remaining in Ven- thousands of years. At some unknown ezuela’s Orinoco belt and Alberta’s the injection of CO2 and chemicals to maximise ultimate oil recovery. The time a value-adding technological Athabasca oil sands are the degraded main objective of planned field pilots breakthrough took place along the residues of what was once together and demonstration projects is less for Athabasca River in northern Alberta perhaps 10 or more trillion barrels of

20 OXFORD ENERGY FORUM NOVEMBER 2011 light crude oil. To reverse this degra- Thermal technologies generally rely Significant advances have been made dation, we have to extract, thermally on horizontal wells to maximise by transferring in technologies from crack and re-saturate the long chain contact with the reservoir. The tech- other businesses: truck-and-shovel carbon molecules with hydrogen in a nology of choice in the Athabasca oil mining to replace draglines, bucket- resource-intensive, series of processes sands region is Steam Assisted Gravity wheels and conveyor belts; electrical that is far from being environmentally Drainage (SAGD); two horizontal scrubbing techniques used for soil benign. wells 500 to 1000 metres long in the remediation, and potentially, plasma lower part of the reservoir, where technology currently used to recover The technology challenge in produc- the upper well is the injector and the valuable noble metals from metal mine ing heavy oil is not simply to increase lower the producer. Some variation waste piles. its volume, but most critically, to on this basic well configuration is greatly improve the efficiency of its used for other emerging techniques production, to improve unit econom- Technology as Business Strategy that rely on solvents such as VAPEX ics and reduce its environmental (solvent only in gaseous state), hot Technology is always a sub-theme in footprint. And production is only liquid solvent and Solvent co-injection the business strategies for firms in the part of the battle; nobody wants pure (steam and solvent). The obvious oil sands. Every company, big and bitumen. It must be either upgraded challenge in using solvents is to ensure small, attempts to create a mystique at site or it has to be diluted with their maximum recovery and recycling around some ‘unique’ or ‘special’, lighter hydrocarbons (‘diluent’) in as their value is much greater than black box or technique in particular order to pipe or truck it to refineries bitumen’s. or the firm’s technological prowess with deep conversion capacity. It is a in general (often demonstrated in manufacturing, value chain business – Horizontal drilling techniques have some other part of the conventional pursuing efficiencies in all links of the made major strides in the last fifteen oil business, like the offshore, with chain in repeated, incremental phases years and are an enabling technology little or no relevance to being suc- of production over several decades. for heavy oil. Combined with advanc- cessful in the oil sands). They do es in 3-D seismic and Logging While this to attract investors or to placate Drilling it is possible to ‘see’ one’s their environmental critics, or even to “To produce most forms of way and drill into optimum reservoir convince themselves that this business and, in the case of SAGD well pairs, is for them. Strategies vary depending unconventional oil and gas keeping a constant and level distance on company size, capital, business we have to either reverse or between injector and producer to diversity and the quality and size of accelerate geology” avoid hot spots that can destroy their resource base. Most technologies very expensive electrical submersible being touted as potentially capable of pumps (ESPs). reducing energy intensity (and at the There are three basic means of pro- The technological complexity of the same time reducing carbon emissions) ducing heavy oil; primary, thermal or heavy oil value chain means there is are merely variants on what has chemical. The focus in this note is on great technological upside. Improve- already been tested by others over the the latter two and specifically as ap- ments worth a few cents/barrel apply last several decades with mixed results. plied to the extra heavy oil (<15°API, to a widening wedge of future produc- such as in Venezuela) and bitumen (10 tion. Some opportunities include, to 8°API) in the oil sands of Canada. In the Orinoco, because the reservoir • better understanding and 3-D “Technological change in is hot, the oil can be brought to the modelling of reservoir geometry, the heavy oil value chain surface without stimulation tech- • down-hole monitoring of steam has been slow” niques. However recovery rates are chamber evolution in combination less than 10 percent, wasteful from a with 4-D seismic, • ‘wedge wells’ (producers placed resource conservation perspective. Natural gas as the fuel for heat is not between well pairs), The viscosity of oil in the reservoir a long-term option; several promising • injection of non-condensable gas to can be reduced with heat or solvents. experiments are being conducted using utilise reservoir heat once steaming Heat can be sourced directly as in electricity. An IOC proposes to test stops, a fire-flood, with dry or wet steam, electrical, in situ upgrading in the frac- • ESPs for high temperature, cor- or using electricity – either direct tured, karsted carbonates beneath the rosive and abrasive conditions, conduction or indirectly by induction. oil sands, estimated by the authorities Generally, thermal technologies result • improved efficiency of heat to have more than 400 billon barrels in better recovery rates, perhaps as exchangers, in place. A small Canadian independ- much as 70 percent. However, no • more reliable water management ent has discovered a rich bitumen in situ technology is ever likely to systems, and zone in the carbonates beneath its achieve the recovery factors of mining • electricity-based production oil sands and is testing electrical – more than 95 percent. technologies. conduction heating in horizontal

21 OXFORD ENERGY FORUM NOVEMBER 2011 wells, referred to as Thermal Assisted construction or operating. If all were price and the impatience and fickle- Gravity Production (TAGP). Another to reach capacity as scheduled, total ness of investors. start-up has had success piloting a production from the oil sands would thermo-electrical project that takes exceed 7.7 mmb/d by 2020. In reality, Patents advantage of the electrical conductiv- the industry will be hard pressed to ity of the water skin between the reach 3 mmb/d by that date. Of the The dramatic surge in patents filed bitumen and sand grains. This and 17 SAGD projects currently operat- towards the end of the last decade for electrical induction technology hold ing, only a couple have achieved or technologies to produce, transport, promise for developing the billions of exceeded their design capacity. In the treat or upgrade bitumen from the oil barrels of bitumen that are too deep month of September, 2011 Alberta sands is a proxy for the increasing in- to mine yet too shallow for steam SAGD volumes were 360 kb/d with accessibility of developable prospects injection technologies. an annualised utilisation rate of 70 of conventional oil. Most were for percent (to some extent reflecting production technologies, one quarter several new projects in early ramp-up for thermal methods, fewer using Old is New Again stage); three CSS (‘Huff ’n Puff’, solvents, and more than half were Technological change in the heavy oil piloted more than fifty years ago) filed by large oil and gas companies value chain has been slow. Canadian operations produced 275 kb/d in the followed by the service companies. government scientists began testing Cold Lake oil sands area. While universities, independent techniques to extract the bitumen inventors, academics, vendors and from the Athabasca oil sands in the service companies do come up with late 1800s. The basic caustic soda innovative, new technologies or ideas, separation process used today in the “emboldened by the without oil leases or the financial mining operations was first dem- advice of experts from resources to pilot them, these ideas onstrated in 1925 by a government Hollywood, the Obama remain untested. Also, some inventors researcher. After two plants were built have unrealistic expectations, demand- and burnt, it wasn’t until 1967 that administration recently ing royalties measured in dollars the first commercial integrated mining ‘punted’ the decision per barrel when the operators are operation started, and is now operat- whether to approve the measuring successful improvements in ing at nearly ten times its original pennies per barrel. capacity. Most of the technologies for Keystone XL pipeline until after next year’s presidential Confronted with their business being development of the deeper deposits characterised as ‘Dirty Oil’, the in- (90 percent of the resource) in the election” dustry has responded with more than Canadian oil sands and extra heavy just public relations programmes. A oil were dreamt up in the seventies, major shift in attitude is seen in their generally by small companies or in Any company that claims its technol- approach to collaboration. Whereas government labs. SAGD, the technol- ogy programme will yield efficiency technology development used to be ogy of choice today for the Athabasca gains/emissions reductions beyond cloaked in secrecy, industry is now oil sands, was conceived over forty a modest, few percentage points collaborating on technologies for use years ago, piloted/confirmed by a within ten years – and they have ‘above the ground’ that can improve consortium of companies and govern- yet to put steel in the ground to test efficiency and decrease environmental ments about twenty years ago and saw their technologies – is simply naïve impacts, while competing below the its first commercial projects ramp up or attempting to mislead someone. It ground where improving recovery in the last decade. Of all the schemes can take more than three years just to confers a competitive edge. for production, only Steam Soak get regulatory approval, two to build, and Flood schemes (for example, in one to three to ramp up, monitor and ‘lighter’ heavy oil of California and measure and perhaps a couple more to Technology is not Enough Indonesia), Cyclic Steam Stimulation analyse – and that is only for a pilot, We hardly need reminding that tech- (CSS) and SAGD can be declared not a full-scale commercial project: nological breakthrough alone is not convincingly commercial. Solvent Co- that can take another four to six years enough to assure a growing future for injection is planned for at least one to produce initial results. And if the these enormous but difficult resources. SAGD project under construction. It history of piloting is any guide, the Probably the most benign link in the is critical to understand that technolo- analysis often concludes there were heavy oil value chain – transportation gies cannot easily be transferred from insufficient observation wells and – has recently become its weakest, if one geological formation to another measurements of the right parameters only by perception. Faced with well- or even within the same formation to provide conclusive data. organised, unrelenting and impressive as geological variability is so extreme Heavy oil is slow in more ways than opposition by groups who see heavy between oil sands leases. in how it flows. The interest in prov- oil as the marginal source of a com- There are over sixty oil sands projects ing up new technologies has waxed modity the world must stop using, announced, before regulators, under and waned with the fluctuation in oil emboldened by the advice of experts

22 OXFORD ENERGY FORUM NOVEMBER 2011 from Hollywood, the Obama admin- processes have reached a very high The added challenge beyond the heavy istration recently ‘punted’ the decision level of maturity and sophistication, grade is the higher sulphur content whether to approve the Keystone and improvements are more likely which is considered ‘sour’ at and XL pipeline until after next year’s to emerge at the evolutionary level. above 1 percent. presidential election; the line would The most significant and innovative Traditional refineries have been provide access for Canadian bitumen refining-related improvements can be designed and built to process the light blend to the Gulf Coast refineries. In expected in the catalyst chemistry and sweet crude oil that in the past was response, Canada’s Prime Minister has application. abundantly available (and much easier declared that Canada’s oil will not be The degree of application of the many to extract than heavy crude). The held captive to the single US market. well-proven technologies, processes, metallurgy of the processing units and This political declaration comes just and concepts, however, will change pipes in those refineries is inadequate as the nation’s pipeline environmental significantly as a result of several to handle sour crude oil and they will and energy regulators start the public factors. These include the ever increas- rapidly corrode and suffer fundamen- review of a proposed pipeline to ing share of more difficult-to-process tal damage if exposed to crude oil Canada’s west coast, aimed at Asian crude oils, like heavy and extra-heavy with the much higher sulphur content. markets; already a record 4000 partici- higher sulphur, higher metals, more Therefore, the world’s refining indus- pants have registered to be heard. acidic, etc. crude oils, as well as try in general is long in sweet crude the environmental factors of global and short in sour crude capacity. warming and CO emissions, the need 2 The technology and the know-how for more efficient fuels, the ‘aging’ to convert refineries to heavy sour and the ‘rust factor’ of many refineries crude processing capability have been that have been in existence for fifty readily available for quite some time. and more years. Also important is the Thus, the determining factors for a shift of actual petroleum processing process upgrade are really outside the from consumer countries to crude actual technology and processes, and oil-producing countries, and countries are driven by economic and financial that promote, support, and facilitate Franz B. Ehrhardt considerations. Beyond that, even the construction of mostly export if all components are favourable, to discusses global oriented new mega-size refining obtain the essential permits for the industries. refining – game upgrades faces tremendous hurdles in changing trends, The two game changers to be most developed countries mainly due discussed here are the continuous to government red tape and especially response strategies, increase in the production of extra environmental concerns … whether heavy high sulphur crude oil and the justified or not! and the role of construction of more and more mega- technology size, high conversion, high complexity refineries. “Traditional refineries have The petroleum refining industry has Significant Increase in the Share of been designed and built never been without substantial chal- Extra Heavy Sour Crude Oil lenges, and it is appropriate from time to process the light sweet to time to review the latest trends It is a well known fact that over time crude oil that in the past and challenges that will impact the the production of heavy-sour crude was abundantly available” industry. oil has taken an ever increasing share of all crude produced, a trend that This article will address from a most certainly will continue. While a strategic impact point of view two of Another (extra) heavy crude oil number of new reserve finds contain several prevailing and emerging trends processing challenge for refiners is light sweet crudes, the presently that are of adequate significance to the fact that such crude oil in the first known reserves of (extra) heavy crude be considered game changers, and to thermal separation process step, the oil are slightly over twice that of light review how technology can and will distillation, generates a much larger crude oil. Actually, as per the most play a role in addressing effectively percentage of heavy ends or residual recent Annual Statistical Bulletin of the related issues. products (resids), products that usu- OPEC, Venezuela just surpassed Saudi ally are turned into asphalt, Bunker C, In general, it can be safely assumed Arabia as the country with the largest or other heavy fuel products. that revolutionary technology crude oil reserves in the world, most changes in fundamental thermal and of it being of the (extra) heavy sour Historically, there has always been hydro-treating processes in petroleum grade. Canada also weighs in at a top a surplus of these ‘heavy end’ prod- refining are not likely to emerge as position with the heavy grade crude ucts, which, naturally, caused a very game changers. All of these core oil reserves from Oil Sands. distressed price level that in reality

23 OXFORD ENERGY FORUM NOVEMBER 2011 did not even pay for the cost of the and delayed coking pioneer among high-demand countries, rather effec- crude feed. The increasing share of the independent refiners, Valero of the tively renders the profitability of those the ‘heavy end’ products caused by USA, has reported that their invest- refineries unacceptable, especially processing more and heavier crude oil, ment of $350 MM for their Texas City when they try to compete with the contributes further to a deterioration Coker contributed about $200 MM favourable incremental economics of of the processing economics of heavy in 2004 alone, suggesting a pay-back the new mega refineries. This situation crude oil. The major benefactor of this period of less than two years. Many has resulted in the disposal of many situation, however, has been mainly existing refineries have added delayed older and smaller to mid-size refiner- the global shipping industry through cokers and many new refineries ies by the major oil companies, mainly the plentiful availability of very low- incorporate them in their basic design. in Europe and in the USA. cost Bunker C fuel. Established Independent Refiners, On the other hand, this challeng- New high Complexity, high like Valero in the USA, and independ- ing situation for the refiners can be Conversion Mega-size Export ent newcomers to the industry, like resolved with a very attractive tech- Refineries outside Traditional high Petroplus in Europe, have acquired nology – the Delayed Coking Process. Demand Countries – and will likely continue to acquire In this process the heavy ends, the – most of those refineries and convert The traditional oil industry strategy residual fuel, is ‘baked’ under high them to a business model of becoming has always favoured the construction pressure and high temperatures in a economically viable through more of refineries in or near high finished coke drum. The results are, depending cost-efficient operation and consider- product demand locations. This on the coking technology and proc- ably lower O&O expenses. concept was primarily based on the ess actually used, liquids of 40–50 fact that the transportation cost of The challenges to this business model, percent in the range of C5 and up, and crude oil to a refinery location in high however, will be the longer-term petroleum coke (pure carbon) for the demand countries was considerably investment needed to modernise the balance. lower than that of finished products facilities with existing technologies to be transported from the refinery to and processes to remain competitive the end-user. with the finished products imported from the before-mentioned mega “The technology and the Several factors have, however, initi- refineries. Furthermore, the envi- ated a trend to build mega-size, high know-how to convert ronmental challenges and the usual complexity, high flexibility export government red tape are likely to refineries to heavy sour refineries in crude oil-producing stall any upgrading attempt by these crude processing capability countries, i.e. Saudi Arabia, Kuwait, independent operators in the same and so on, as well as in countries that have been readily available way that they blocked the previous actually permit, and even encourage, for quite some time” owners, the major oil companies, from the construction of new refineries pro- that avenue. viding an attractive business model for strict business ventures by industry Conversely, for the crude oil- Further hydro-treating and de- newcomers like Reliance and Essar in producing nations (i.e. OPEC), the sulphurisation produce diesel products India. construction of mega refineries on that provide a rather attractive value their soil, and with the support of a These developments are unquestiona- upgrade over the feedstock. The highly facilitating government, not bly encouraged by the impossibility of petroleum coke can be used as a feed only provides local employment and securing the essential (mainly environ- for power plants, for cement kilns, a significant value upgrade for the mental) permits in the USA, Europe, and select further upgrades. For crude oil stream over the net export and other developed countries. For example, Conoco uses petroleum coke price, it also voids the need to count example, the last new refinery in the to feed a fluid bed combustion power the processed crude oil against their USA was built 35 years ago. If I recall plant at their Lake Charles refinery, a respective (OPEC) export quota, thus correctly, the last new refineries in technique that now has much wider permitting a higher level of crude oil Western Europe were built in the UK applications. production. in 1968 and in 1975 in Germany. In Refiners who have installed both general significant capacity expansions The pure size of these mega refiner- heavy sour crude oil processing at existing refineries do not materialise ies will provide highly attractive capability and substantial bottoms-up- either, due to the same permit and incremental economics that are grading capacity like hydro-crackers bureaucracy challenges. further enhanced by incorporating and especially delayed cokers are the latest conversion and upgrading The inability to expand the capac- currently enjoying, and will for quite technologies into the design, includ- ity to an economically viable and some time to come, a significant ing technologies that will enable the competitive size and to increase competitive advantage through very flexibility to shift the individual fuel conversion capabilities of older and favourable incremental earnings. For production among products following relatively small size refineries in the example, the heavy sour processing prevailing market price swings. This

24 OXFORD ENERGY FORUM NOVEMBER 2011 combination provides these mega India has a 14.0 index (now the high- Tara Shirvani and refineries with significant sustainable est in the world) and Essar is expected competitive advantages that will be to have a 12.8 rating after completion Oliver R. Inderwildi very challenging to overcome by the of the present upgrade. provide a futuristic remainder of the refining industry. There is little doubt that to stay com- It is easily conceivable that the petitive, the refining industry has to view of gas-to-liquid traditional international major oil rethink its prevailing business model technology companies have detected this trend on and generate innovative applications the radar screen and that, for instance, of existing technology, processes, and Marathon and Conoco have made it a know-how to compete effectively with The search for alternative fuels is factor in their decision to split Down- these benchmark performers. relentlessly under way with 90 percent stream from Upstream into separate of transport fuels being oil-derived companies, anticipating a return to and uncertainty around depletion Conclusion the decades of dismal financial returns levels of conventional oil reserves from the refining and marketing busi- There are adequate and economically mounting. Global vehicle ownership ness. Otherwise, one can also ask why attractive technologies and processes is forecast to reach two billion in the previously highly touted strategic available, especially delayed coking, to the near future and climate change benefit of full integration was ditched absorb and manage the increasing level concerns, induced by anthropogenic by these companies! of heavier and sour crude oil supplies. greenhouse gas (GHG) emissions, expected to rise. The central challenge While there is unquestionably a need involves the transformation of our for refineries in the high demand oil dependent transport industry, as locations, the NIMBY (Not In My we face the so-called input problem “to stay competitive, Back Yard) factor will continue to of dwindling conventional crude the refining industry has prevent such developments and hand oil reserves as well as the so-called the financial value upgrade and job to rethink its prevailing output problem of increasing GHG opportunities to entities and countries business model and emissions. Liquid fuels derived from outside Europe and the USA. generate innovative gas, coal or unconventional oil sources The new mega export refineries will may be able to offset the input prob- applications of existing be able to supply global markets with lem of diminishing oil supplies, but technology” the full range of products that meet will inevitably exacerbate the output the most stringent specifications at problem of rising GHG emissions. prices that will severely challenge the Biofuels can be a viable substitute It is also very interesting to note that economic viability of a large number for fossil fuels, most notably when with the ‘downsizing’ over the last of refineries, forcing more and more produced in a sustainable manner and two decades, the international oil shut downs. from feedstock that is not in direct majors have ‘outsourced’ most of the Until a highly innovative and revolu- competition with food or animal refining research and development, tionary refining process like chemical feed. The transition towards advanced which together with the resulting hydro-carbon separation and chain biofuels may contribute towards a new technologies is now in the hands manipulation at ambient temperatures low carbon, sustainable fuel mix, but of independent service companies is invented, the presently known and is unlikely to be sufficient to meet that are only too happy to provide applied thermal technologies and the current energy demand of our their services directly to the new processes can master quite capably the global transport system. Recently, the mega refinery clientele – so rendering most challenging tasks in refining with interest in synthetic fuel production obsolete their need to partner with the assistance of continually advanced from unconventional resources has international oil companies for refin- catalysts. been revived through the rise in crude ing ventures. oil prices. Global production from One more comment regarding the unconventional sources has been sustainable competitive advantage of a projected to increase by 2030 to 7.4 high level of conversion and flexibility million barrels per day or 10 percent capability in the design of the latest of global conventional oil supply. mega refineries – while a few years The industry’s expectation illustrates ago in the second edition of the book that there are other factors at play Petroleum Refinery Process Economics aside from the rise in global petrol (2000), author Robert Maples noted prices, which will facilitate the rapid that US refineries rank highest in the introduction of synthetic fuels into Nelson Complexity Index, averaging the market. 9.5, compared with Europe’s at 6.5, at Historically, in 1942 Germany present, the Reliance mega refinery in avoided the fatal economic damages

25 OXFORD ENERGY FORUM NOVEMBER 2011 of a long-lasting oil embargo and a Overall, the GtL production process especially in urban environments. prolonged war by deriving almost 90 is estimated to produce 75 percent GtL fuel products therefore may help percent of its total energy consump- middle distillates and 25 percent non- to address energy security concerns tion from coal-based Fischer-Tropsch fuel chemical products. and drastically improve local air (FT) fuel production. Similarly, the Due to in part the success of the pollution levels, but are by no means Apartheid regime in South Africa was synthetic fuel production process, considered environmentally friendly responding to an oil boycott in 1950 FT-diesel is considered to be a strong fuels. In comparison to conventional by using their vast coal reserves to technical candidate for the substitu- petroleum-derived diesel, GtL fuel produce liquid fuels and meet their tion of conventional diesel. FT-fuel products result in increased GHG domestic transport fuel demand. products have received considerable emissions over their lifecycle, see Even today, the South African energy attention for their favourable char- Figure 1. industry still obtains 30 percent of its acteristics for use in compression This is partly due to the high energy road transport fuels from indigenous ignition engines as for instance the coal reserves. requirements of the FT process and Diesel. These high quality fuels benefit the conversion of a hydrocarbon from superior autoignition charac- feedstock such as methane which leads teristics and can replace conventional to significant CO emissions during fuels at any ratio (0 to 100 percent) 2 The search for alternative the production stage. On average as they are fully miscible. The energy the carbon footprint of GtL-fuels fuels is relentlessly under density is comparable to conventional is 10 percent higher than that of diesel, which qualifies them for use in way with 90 percent of conventional fossil fuels. However, unmodified diesel engines. Experimen- transport fuels being oil- compared to synthetic fuels from tal studies have further shown that the other unconventional resources such derived thermal efficiency of diesel engines is as coal or oil shale, Gtl fuels highlight improved when GtL blends are used. a lower carbon footprint (see Figure1). In addition, GtL fuel properties are Nevertheless, with a global consump- Synthetic fuels, made from natural gas also environmentally advantageous, tion of liquid transport fuels in 2009 are referred to as gas-to-liquid (GtL) outlining a high cetane number of 75, resulting in 11.3 billion metric tons of fuels. Analogously fuels manufac- virtually zero sulphur and aromatic CO , substituting 50 percent of this tured from biomass or from coal are hydrocarbon content. As a result, 2 conventional fuel supply with GtL referred to as biomass-to-liquid (BtL) combustion of GtL fuels yields 12 fuel products would have increased and coal-to-liquid (CtL), respectively. percent less nitrogen oxide (NOx) and emissions by 0.5 billion metric tons Through a fuel conversion process 30 percent less particulate matter (PM) of CO . The fuel synthesis process which includes FT technology, natural emissions making them superior fuels 2 gas is converted into longer chain may not even be economically feasible hydrocarbons which can be refined to yield gasoline, kerosene or diesel. In Figure1: Life cycle Fossil Fuel Use and GHG Emissions per MJ Fuel for the first step, sulphur components and Biofuels and Synthetic fuels in the USA other impurities are removed from the methane-rich natural gas feedstock, 200 which is later cooled down to separate Fischer-Tropsch diesel methane from other hydrocarbons. produced from coal Through a catalytic partial oxidation 150 – eq/MJ or steam reforming process, methane 2 is reacted with oxygen to produce 100 Corn ethanol Diesel Gasoline a mixture of carbon dioxide (CO2), carbon monoxide (CO), hydrogen Fischer-Tropsch Fischer-Tropsch diesel diesel produced produced from natural gas (H2) and water (H2O). In the second from forestry residue 50 stage, the gaseous mixture of H2 and CO is fed into the FT reactor which Soybean biodiesel yields long-chain, waxy hydrocarbons Switchgrass ethanol and considerable volumes of water 0 as by-product. In the presence of Corn stover ethanol Municipal solid waste ethanol zeolite catalysts and hydrogen the Well-to-Wheel GHG emissions – gCO waxy hydrocarbons are catalytically -50 cracked into shorter hydrocarbons as -0.2 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 part of the final upgrading phase. The Well-to-Wheel fossil fuel use – MUMJ synthetic crude is then distilled into a variety of fuel products ranging from Source: X. Yan, O. R. Inderwildi and D. A. King, Energy & Environmental kerosene to diesel, oils and naphtha. Science, 3, 190–7.

26 OXFORD ENERGY FORUM NOVEMBER 2011 when carbon capture and storage of Enterprise and the Environment, fuel products to become economically (CCS) facilities are considered, since at Oxford University, estimates that unfeasible compared to petroleum- the improved environmental balance under a high oil price scenario the based fuels. will result in lower efficiency levels share of global GtL fuel products will To conclude, GtL fuels are high qual- and reduced energy gains. increase to 1.2 million b/d by 2030. ity fuel products which are virtually Compared to the projected increase in zero in sulphur and aromatics and global fuel demand to 107 million b/d consequently emit significantly less by 2030, the share of GtL fuels will local pollutants. The supply of GtL “On average the carbon remain marginally low at a maximum fuels in urban areas can therefore footprint of GtL-fuels is 10 of 1.14 percent of global crude drastically improve local air quality. percent higher than that of demand. However, given the energy-intensive Availability of large volumes of nature of the FT fuel production conventional fossil fuels” low-priced and stranded natural gas process and the use of a fossil energy feedstock is critical to the economics source, the transition from petroleum- of GTL plants. We refer to stranded based fuels to synthetic fuels from When it comes to the availability of gas as cheap gas that is uneconomic natural gas would lead to a consider- natural gas reserves required to satisfy to develop due to transport distances able rise in GHG emissions from the rise in liquid fuel demand, fuel or lack of infrastructure. Feedstock transport. As part of a larger mission consumption is not expected to be costs may not remain low enough to to diversify the source of transport limited by a resource constraint per se. make GTL economically attractive in fuels, GtL technology will need to Geographically, natural gas reserves the mid-term future. Another option complement our current fuel mix are disproportionately distributed for the monetisation of stranded gas alongside unconventional fuel supplies globally, with three countries, Iran, would be liquefied natural gas (LNG) from tar sands as well as biofuels. GtL Qatar and Russia holding more than production for which the cost of fuel production may not be limited 50 percent of global conventional LNG liquefaction terminals is declin- by feedstock availability and could reserves. In particular, the North- ing and demand from South East Asia theoretically mitigate future oil supply Dome-South-Pars complex within is increasing. This trend will increase shocks; however, due to significant the Persian Gulf accounts on its own the opportunity costs of stranded gas lead times for additional capacity for 50 thousand cubic metres (tcm) of and negatively influence the economic of GtL fuels and the high upfront natural gas, an amount that equals 23 viability of GTL plants. At present, investment needed, it is unlikely that percent of proven natural gas reserves. assuming an average natural gas price a substantial volume will go on-line The IEA estimates the remaining of $180/tcm, GtL fuel products would in time to absorb future oil supply volume of recoverable natural gas enter the market at a corresponding shocks. Analysis of earlier studies on reserves at 405 tcm. With a projected oil price of 70 $/b, see Table 1. the economics of GtL plants leads rise in annual natural gas demand us to the conclusion that when large around 71 to 77 tcm p.a. by 2030 Table 1: Market Entrance Crude Oil stranded gas reserves and cheap gas and the current level of technology, Prices for Liquid Fuel Production are available, GtL is profitable and a surplus reserve of 333 to 327 tcm from Different Resources allows international oil companies a of conventional gas resources can be certain degree of independence from estimated. The additional on-line ca- Resources Market entrance OPEC oil. These endeavours are pacity could be used to produce more oil price ($/barrel) consequently part of a larger strategy than 1 trillion barrels of GtL syncrude Tar sands 38 that would allow energy companies to and Liquefied Petroleum Gas (LPG) Extra-heavy oil 30 strengthen their supply security and products which would be enough to Oil shale 70 (short run) be more independent from national replace the demand for crude oil with 30 (long run) energy security undertakings. syncrude for the next two decades. CTL 86 However, the geopolitical turmoil GTL 70 within most of the producing nations, Corn ethanol 40 the exorbitant capital requirements for the development of GtL production GtL fuels are economically unfeasible plants and the significant lead-times when prices are below 40 $/b. This for additional on-stream capacity, pre- figure would be higher, where carbon- vent GtL fuels from being produced intensive energy sources are used on a sufficiently large scale. Currently, throughout the production process global GtL production capacity is and a high carbon tax is applied. Even, limited to 151,500 barrels a day (b/d), under a high oil price scenario of 120 a volume that merely replaces 0.2 per- $/b combined with a low carbon tax, cent of global transport fuel demand. natural gas prices would only have to In-house research at the Smith School reach $15/thousand cubic feet for GtL

27 OXFORD ENERGY FORUM NOVEMBER 2011 Asinus Muses

Caveat lector and spare the precious biodiversity. One While global economic gloom suggests study presented the scheme as a radical further oil price rises are unlikely, those Having been elevated from the pack new way to ‘leverage’ hydrocarbons to of us who watch these prices are neces- to become a commentator on global protect the environment. To Asinus the sarily Socratic: we know that the one affairs, Asinus no longer considers oil looks not so much like a lever as a thing we know about energy prices is himself a mere beast of burden. Yet as gun held to the head of a hostage – ‘pay that we don’t know what they will be he writes these words he has a small up or the tree frog gets it.’ But this in a year’s time. infant strapped to him, directing his is too cynical even for Asinus. Since movements no less rigorously than the most countries have paid no attention Dire straits sternest of pack drivers. Unlike the whatever to the biodiversity destroyed honest reward one expects after a day’s by their extractive industries, Ecuador Apropos of which, sabre rattling by menial labour, however, baby boot can hardly be criticised for offering Iran in response to threatened sanctions camp allows no more than three hours an alternative. Indeed, the economics have been spooking the oil market of sleep at a time. are impeccable: a global public good lately. While most analysts are some- like biodiversity should be paid for what sceptical of the vice-president’s Late-night tantrums globally. And pay up they have, or at promise that ‘If they impose sanctions least partially: so far US$116m has been on Iran’s oil exports, then not even Asinus’s ongoing sleeplessness gives raised from various friendly govern- one drop of oil can flow through the him a new insight into the antics of ments plus an array of celebs including Strait of Hormuz,’ it usually pays to our politicians in their late-night ne- Leonardo DiCaprio, Edward Norton be nervous. An important reason for gotiations. David Cameron’s dramatic and Al Gore. The Belgian region of scepticism is the fact that neither the wielding of the UK veto to prevent the Wallonia paid US$2m, worth mention- vice-president nor the president himself use of EU institutions in Germany’s ing more for the comic value of its name has the power in Iran to initiate hostili- proposed fiscal union was probably a than any substantive reason. ties. Apparently it is only the Supreme low point of mutual understanding and Leader and his ironically-titled Revo- sympathy, and many think it has left the What goes up might stay there lutionary Guard that have that honour. UK isolated. But Asinus has himself Further confusion is sown, at least in recently had reason to wish he had such While the tree frogs will be happy, those Asinus’s mind, by the fact that Iran’s a veto, and not just another nursery of us languishing from high energy chief nuclear negotiator, Saeed Jalili, rhyme, to wield at four in the morning. prices have less reason to celebrate oil recently announced that ‘We formally staying in the ground. Those prices declared to them to return to the path Save the tree frog are particularly upsetting when in- of dialogue for cooperation.’ The coun- comes are remaining flat and people try’s bafflingly complex political system The most impressive feat of diplomacy are continuing to lose their jobs, as is a model of the division of powers. observed by Asinus recently was per- witnessed throughout the non-recovery It brings to mind an observation once formed by Ecuador. Beneath its Yasuní of 2011. The raised cost of energy made by Newt Gingrich of the United national park, part of the Amazon rain- imports contributed to our inflationary States government: that their founding forest, lie an estimated 900m barrels of misery, compounded by the deprecia- fathers deliberately created a system so oil, worth US$7.6bn in revenues to the tion of the pound in your pocket. But inefficient that no dictator would ever Ecuadorean government. Yet the park Asinus hastens to point out that much be able to bend it to his will. is also home to two still-uncontacted of our shocking 5.2% inflation was indigenous tribes and possibly more va- due to the government’s decision, in its Happy New Year rieties of flora and fauna than any other infinitesimal wisdom, to increase most place on Earth. Noting that these natu- prices by 2.5% with its VAT rise. Yet According to the FT, US$6.3 trillion ral wonders are probably worth more voices clamouring for a rise in interest was wiped off the value of global stock to the rich world than to Ecuadoreans rates to slow that inflation, despite the markets in 2011. Since some market themselves, the government decided to UK economy idling far below potential participants recorded healthy profits, offer the world the chance to buy out output, were always suffering from a the question, as so often, is: who was its oil option at a bargain half price. failure to understand the differential left holding the baby? In Asinus’s For a mere US$3.8bn, it declared itself calculus: remaining high is different household, there is little doubt. willing to leave the oil in the ground from continuing to rise.

Oxford Energy Forum. ISSN 0959-7727. Published by Oxford Institute for Energy Studies, 57 Woodstock Road, Oxford OX2 6FA, United Kingdom. Registered Charity 286084. Tel: (0)1865 311377. Fax: (0)1865 310527. E-Mail: [email protected] EDITOR: Bassam Fattouh CO-EDITOR: Ivan Sandrea. Annual Subscription (four issues) £45/$85/a65. © Oxford Institute for Energy Studies, 2011. Indexing/Abstracting: The Oxford Energy Forum is indexed and/or abstracted in PAIS International, ABI/IN- FORM, Fuel and Energy Abstracts, Environment Abstracts, ETDE and CSA Human Population and the Environment 28