Unconventional Projects Research Articles

A Few Lessons From Tight-Rock Producers That Have Made Big Investments in Fracture Diagnostics

_ Devon Energy may have unlocked why hydraulic fractures in some tight-rock plays grow faster than others. This appears to be strongly linked to the well-density potential of these plays. The operator is also working on a new way to measure how fractures squeeze steel pipe, which, in turn, might result in more-efficient completion designs. SM Energy recently studied the interactions between hydraulic fractures and faults in one of its tight-rock projects in Texas. When a fault slipped, the Denver-based producer had seen production slip too. Now, armed with enough data, SM Energy has adopted new completion designs that avoid overpressurizing the faults found all over the target formation. Shell’s search for light-tight oil in the Permian Basin ended about a year ago but what the company learned there will live on in its other unconventional projects. Not least of those learnings involves how to best deploy diagnostic technologies to answer big questions about the way fractures behave—no matter the formation. These glimpses into how each unconventional operator is relying on fracture diagnostics were shared at a recent technical conference organized by Calgary-based SAGA Wisdom which offers training for engineers on reservoir analysis. Here is more on the lessons they shared with the industry at the conference held this year in Fort Worth, Texas. Pick the Right Tools Som Mondal, an engineer with Shell’s shale business unit, joked that when he agreed to speak at the conference about the company’s diagnostics journey in the Permian, it still owned assets there. The London-based supermajor exited the largest US onshore play in a $9.5-billion sale to ConocoPhillips that closed in December 2021. But while it has moved on from the Permian, Shell still operates unconventional assets in Argentina’s Vaca Muerta and the Montney Shale in Alberta. It is in those places where the company’s years of integrated diagnostics research in the Permian will be carried forward. Mondal shared how that work shaped the way he now views the different diagnostics technologies and where they complement each other. On this, he subscribes to two overarching philosophies. “One, we need to aim for consilience—which is when different, independent approaches converge toward the same solution,” said Mondal. “And second, we need to weigh the different diagnostics so that we can combine them based on our confidence in them and the scope of its measurement.”

Unconventional Reservoirs: Australian Exploration Experts Weigh In on Rosy Reserves Estimates

The early days of a new shale play can be exciting, but they can also come with inflated expectations. This is a familiar theme in the unconventional sector which has delivered a myriad of discoveries over the past decade that have failed to achieve commerciality. It’s especially familiar for those involved in Australia’s unconventional projects where big hopes have been pinned on the tight-gas potential of places called the Beetaloo, Canning, and Cooper Basin. Instead, the only long-term success to be found on the Australian unconventional landscape is a mature coal-seam gas sector which, not to be discounted, helped the country claim the status of the world’s top exporter of liquefied natural gas in 2020. For Duncan Lockhart, one of the chief reasons that Australia’s tight-gas ambitions have yet to materialize likewise lies in the fact that tight-rock plays extend for vast areas compared with even the largest conventional systems. As a result, the general manager of exploration with Brisbane-based Central Petroleum said some of the estimates on unconventional prospective resources are “verging on fantasy.” Lockhart issued his critique as a co-chair of a resource valuation panel hosted by the Asia Pacific Unconventional Resources Technology Conference in November 2021 The discussion between several exploration experts tried to identify the biggest missteps in Australia’s tight-gas adventure thus far. At the highest level, the industry depended on the promising results of too few appraisal wells to formulate reserves estimates on areas covering hundreds and sometimes thousands of square kilometers. Lockhart emphasized in trying to evaluate such “massive areas,” operators and appraisers have been pushed into a corner. “We need to make a whole bunch of major assumptions about a whole bunch of inputs,” he said, adding that left out of the initial estimates all too often is “the amount of heterogeneity that we will be experiencing in these rocks over these large areas.” Lockhart was not alone in his concerns. With hindsight, it has become easier to see that the highest-performing wells tend to be drilled in isolated sweet spots and along narrow fairways—not across the entirety of a play’s geographic boundaries as shown on the map. The risk facing every operator in this situation is that it will burn through its capital on the wrong slivers of shale and, in turn, see its investors run for the exit. Martin Wilkes, a managing director with energy consulting firm RISC Advisory in Perth, took aim at what he characterized as the “sales message” approach that tends to ignore such facts of life during the early promotion of tight-gas plays. “[Operators] talk up total organic compound content and use it to develop these large numbers, which then get transferred into a continued resource using standard recovery factors,” he said.

E&P Notes (August 2021)

E&P Notes (August 2021)

World’s Largest Gas-Producing Nations: Natural Gas Will Keep the Lights on for the Next Generation

Natural gas is almost certain to be the fastest-growing fossil fuel in the global energy mix for decades to come, comprising 28% of the global energy mix by 2050. Together with renewables, natural gas will likely fuel 60% of global electricity production, be it as pipeline gas, liquefied natural gas (LNG), or blue hydrogen. These are among the forecasts that appear in the 2020 edition of the GECF (Gas Exporting Countries Forum) Global Gas Outlook 2050 released in February 2021 and providing short-, medium-, and long-term energy projections based on assumptions regarding macroeconomic conditions, energy prices, and policies. The report is updated yearly and is the flagship publication of the organization, which represents countries that control 71% of global gas reserves. It is unique in that it focuses exclusively on the global gas industry, which today is providing for 23% of global energy needs. Headquartered in Doha, Qatar, the GECF is an intergovernmental organization comprising 11 member countries and nine observer states, established in 2001 by Russia and Iran. Moscow and Tehran had hoped that GECF would eventually morph into a “Gas OPEC” but that never happened. The organization’s analyses and forecasts do, however, present a worthwhile snapshot of how the world’s largest gas producers see the industry. Member states in GECF include Algeria, Bolivia, Egypt, Equatorial Guinea, Iran, Libya, Nigeria, Qatar, Russia, Trinidad and Tobago, and Venezuela. Observer countries are Angola, Azerbaijan, Iraq, Kazakhstan, Malaysia, Norway, Oman, Peru, and the UAE. Unconventional Gas To Play Growing Role In its report, the GECF noted that unconventional resources will be playing a growing role in the market and that gas producers will need to emphasize unconventional projects to satisfy growing demand, as well as to invest heavily into exploration to identify and tap into new gas reserves and develop greenfield projects. “It is also important to highlight the increasing interest in hydrogen as a lever to support the deep decarbonization of the world’s economies,” Yury P. Sentyurin, GECF’s Secretary General, wrote in his introduction to the annual outlook. In mentioning hydrogen, Sentyurin is speaking about “blue hydrogen” which is produced from natural gas, and which, when combined with CCUS (carbon capture, utilization, storage) can marry commercial and environmental interests, further positioning natural gas as a transition fuel to bridge the gap between fossil fuels and renewable sources of energy. Blue hydrogen is in fact expected to satisfy half of the hydrogen demand projected worldwide by 2050, Sentyurin points out. Policies being set by countries in the European Union have focused more on costly “green hydrogen” produced from renewable sources; but not in the policies of other nations in regions of the world where growth in energy demand is expected to be the highest. Growth in European energy demand is largely flat.

Technology Focus: Drilling Automation and Innovation (February 2021)

Drilling automation and innovation continue as dominant trends despite market downturns and unprecedented challenges in the past year. In many ways, the drive toward new efficiencies and step changes in well-construction performance has taken on an even greater sense of urgency. Further advancements in automation and innovation in well construction are recognized globally as keys to unlocking new opportunities in the ever-changing world in which we live. OTC Live sessions in late 2020 included a fascinating session titled “Opportunities and Challenges in Frontier Basins and Emerging Offshore Areas.” Despite pandemic-induced uncertainty, a significant number of high-impact exploration efforts, including projects in deepwater Gulf of Mexico, Brazil, west Africa, the Mediterranean, and Asia were ongoing. Panelists agreed, given world population and energy consumption being forecast to grow 20% by 2040, that increased hydrocarbon supplies, in addition to renewables, are essential to meeting future demand. The discussion also highlighted increased emphasis on carbon footprint reduction. Leaders from Shell, Expro, Wood Mackenzie, and others spoke to a CO2-intensity/barrel of oil equivalent chart comparing relative values for deep water, unconventionals, oil sands, and liquefied natural gas. It is noteworthy that deepwater production represents the lowest carbon footprint of all hydrocarbon sources by a significant margin. This advantage, combined with the potential for large resource size, high flow rates, and low well count, suggest that deepwater assets will compete in long-term portfolios for many operators. Referring to the current selection of SPE drilling-related manuscripts, automation of land rigs within onshore unconventional basins remains a widely published subject. More specifically, automation of the directional drilling process continues to yield improvements in performance and efficiency. It is often noted that well costs have been reduced by more than 50% with advancements related to horizontal technology, digitalization of well construction, and rig automation. These technologies were largely initiated within onshore, unconventional projects, but application is now wide-spread for offshore, complex wells. Selected papers in this feature are chosen to highlight the latest achievements and near-term opportunities across the full spectrum of upstream projects. A consistent message from paper SPE 203251 regarding drilling automation in the digital age reads, “industry has yet to benefit on a large scale from these advancements and…significant value remains untapped.” This reoccurring theme appears across operator and geographical boundaries, revealing significant opportunity and the need for ongoing emphasis. Software and hardware evolution progresses along with more- comprehensive integration of rig equipment and functionality. Industry now is more focused on moving from automation of individual tasks toward automation of the full well-construction process from plan to completed borehole. This idea is presented in paper SPE 201763. Change management remains a key issue within the process to ensure adequate control, early buy-in from stakeholders, and strong leadership. In summary, impressive examples of ongoing innovation span domestic unconventional plays, remote/international locations, geologically complex thrustbelt fields, and deep water with managed-pressure drilling in narrow pore pressure/fracture gradient environments. The few selections that appear here are a reflection of many more published by SPE in the past year and are a powerful testament to the ingenuity and perseverance of those involved.

How to Make Better Investment Decisions in Unconventional Projects

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper URTEC 198318, “How Not to Squander Billions on Your Next Unconventional Venture,” by Creties Jenkins, SPE, and Mark McLane, SPE, Rose and Associates, prepared for the 2019 SPE/AAPG/SEG Asia Pacific Unconventional Resources Technology Conference, Brisbane, Australia, 18-19 November. The paper has not been peer reviewed. During the past decade, hundreds of unconventional oil and gas projects have failed to deliver the value sought by shareholders. Two common mistakes have been focusing on production attainment instead of value creation, and incorrectly thinking that enough was understood about a given reservoir to proceed with development. Companies must implement a staged approach that exposes capital incrementally in a responsible fashion and an assurance process that provides a framework for conducting and reviewing work so that mistakes may be analyzed to influence future decisions. The complete paper provides a work flow for making better decisions about investing in unconventional projects. Introduction In 2019, an analysis of 16,000 unconventional wells operated by 29 of the largest producers in Texas and North Dakota revealed that these companies spent $112 billion more in cash over the past 10 years than they generated from operations. A primary contributor to this shortfall was optimistic production forecasts based on a small number of early wells. These types of projections lead companies to commit to development projects before they understand the true variability in well performance and, most importantly, whether the average well will be commercial (i.e., able to pay for the cost to drill, complete, and tie in). Commercial is defined here as attaining a present value greater than zero at the corporate discount rate. If this is 10%, a net present value (NPV) of zero equates to a 10% rate of return. The Challenge More than 50 shale plays across North America have been tested for their production potential. Of these, only a dozen or so (approximately 25%) have been commercially developed. Thus, the first order of business is to focus on the right play in the right basin. But even within a productive basin, operators need to be in the commercial fairway, which is commonly a fraction of the total basin area regardless of play type. The probability of commercializing a new unconventional play in a frontier basin is low. Although a well can be drilled practically anywhere in the basin and encounter mobile hydrocarbons, this does not reduce the commercial risk relative to conventional plays. Instead, it transfers the risk (threat of fiscal loss) to later stages, in which it must be shown that unconventional wells can produce at sufficient rates, costs can be reduced to make these wells commercially viable, and results are repeatable.

Technology Focus: Reserves Management (December 2020)

“This, too, shall pass.” The exceptional year that has been 2020 highlights the fact that the world can change quickly, and a challenging macroenvironment brings into focus the need to maximize the use of our natural resources and the value that can be derived from them. Even without the black swan event of COVID-19, the industry must critically examine the technical, commercial, and operational bases of the projects it pro-poses and executes. A logical, reasonable, ethical, and philosophical approach is critical to underpin good decision making and value creation. Paper SPE 196252 delivers a comprehensive discussion of the issues to consider in the management of mature oil fields that are becoming increasingly important as older fields decline and approach abandonment. The discussion makes direct reference to assessing the late-life economic limit within the context of the Petroleum Resources Management System. Mitigations such as infield drilling, workovers, and facility management can extend production, improve the economics of the project, and increase reserves. Other considerations around minimizing the cost and optimal planning in respect to abandonment and decommissioning will be required to ensure environmental safeguards and minimize cost liabilities. Paper URTeC 198318 considers a timely look back on the delivery of unconventional projects, the failure of many to meet expectations, and likely causation. A disciplined and systematic approach is proposed to mature the project through four stages of success in discovery, deliverability, demonstration, and development. It is important to obtain sufficient information to underpin each decision point and provide confidence in the commercial evaluation. The paper also stresses the importance of clear guidelines and work flows, independent assurance, and thorough post-appraisal of activities and projects to ensure accountability and improve delivery of value. Paper SPE 196362 describes a philosophical approach to enhanced oil recovery (EOR) and provides an extensive review of the topic and projects, supported by a comprehensive reference list. As with the previous paper, a logical, reasoned, and systematic analysis is recom-mended when confirming the technical and commercial viability of EOR. A creative and innovative approach coupled with experience and expertise is critical to success. 2020 will be remembered as a particularly challenging year in many respects, but, as Tom Hanks’ character Chuck Nolan observes in the movie Cast Away, “I gotta keep breathing. Because tomorrow the sun will rise. Who knows what the tide could bring?” Recommended additional reading at OnePetro: www.onepetro.org. SPE 199522 A Global Push for Circular Economy Projects by Dawson Lindauere, Repsol, et al. SPE 201556 Appropriately Characterizing Uncertainty in Estimated Ultimate Recovery for Unconventional Type Wells by Patrick Miller, Petronas, et al.

Technology Focus: Reserves Management

Technology Focus Benjamin Franklin once said, “When you are finished changing, you’re finished.” Our industry must continue to improve and evolve to face the challenges of economic and commercial viability, greater transparency, environmental responsibility, and social acceptance. The papers in this month’s Reserves Management feature explore new and novel ideas to maintain social and environmental relevance, maximize value from unconventional projects, and ensure that exploration and appraisal activity is designed to optimize decision-making in resource project management.• Paper SPE 195298 describes a methodical way to show resource project movement through the recently updated (2018) Petroleum Resources Management System (PRMS) and Canadian Oil and Gas Engineering Handbook (COGEH). Not only does this facilitate a consistent approach for entities to classify their resources, but also provides guidance about how to subclassify resources through a technical and commercial analysis. Subclassification on the basis of project maturity is now recommended by the PRMS 2018 to provide greater transparency of the chance of commerciality, particularly for contingent resources. Moreover, it is important to be able to describe the associated chance of commerciality and defend the reasonableness of development assumptions and resource assignment; otherwise, projects should be considered Unrecoverable. Each entity will need to develop the process to their own specific needs. Paper SPE 191455 is an excellent case study using data analysis to evaluate how the industry has evolved through continuous improvement over the last 12 years. The study was conducted using multivariate analysis tools to try and look objectively at the data, and with 12,000 wells to draw from, there was a significant amount of data to analyze. It is a lesson in what is required in determining the best completion technique for the right reservoir; one needs to drill a great many wells. While the study is related to improvements of projects already in the Reserves class, it illustrates the principles of the Technology Under Development process as it applies to Contingent•resources. Paper OTC 28312 is an excellent Australian example of the oil and gas industry collaborating with scientific research institutions to collect data that can be used not only to assess the integrity of subsea infrastructure to guide decommissioning strategies, but also to contribute to a broader understanding of our oceans and marine ecology. In an increasingly complex and uncertain global environment, it makes sense for oil and gas entities to look at ways of collaborating with scientific institutions and other industries for mutual benefit. This should facilitate greater community acceptance and can demonstrate that industry is undertaking responsible scientific, social, and environmental management. A win-win! Recommended additional reading at OnePetro: www.onepetro.org. SPE 193717 Economic Benefits of Implementing Alternative Energy:• A Heavy Oil Fields Case Study by Mohammad Al-Yatama, Kuwait Oil Company, et al. IPTC 19506 Total Well Management: Maximizing Well Life Cycle Value—A Regulator Perspective by Ryan Guillory, Petronas, et al.

Analysis of the Entrepreneurship Level and Attitude in the Aspect of Starting-Up and Running Micro-Enterprises Among Students of Lublin Universities of Majors in Economics, Management, and Finance

Abstract Entrepreneurship has been a functioning term in academic literature for a long time, however, the research and discussions concerning its importance among the youth take more place in modern science. In economics, this term denotes a tendency to take new risks or seek and realize unconventional projects. The direct approach is to start and run one’s own business. A one-person business activity is the dominant form of an idea realization about the entrepreneurship on a small range. From the moment the annex I to an ordinance 364/2004 came to life, the micro-enterprise stands out as the most common when it comes to the size of one-person business activities. The article concentrates on the measurement and analysis of the level of businesses among students of Lublin universities, related mainly to the desire and initiative of starting-up and running one’s own business. The aim of the article is to increase the level of perception of the knowledge about the youth’s entrepreneurial attitude, especially those possessing extended economic and financial knowledge. The research was possible thanks to a survey covering the representative sample of the population of students of economics, management, and finance at Lublin universities. The choice of this sample was random and focused on different majors. The results and conclusions were collected according to the majors, age, gender, and previous experience of the responders.

Does Russian unconventional oil have a future?

Russia is estimated to hold the world's largest technically recoverable shale-oil resources. The conventional oil resource base is still very large, but there are doubts about how much is economically recoverable. Increasing attention is given to unconventional oil. The purpose of the article is to assess whether fundamental conditions for sustainable, profitable production of unconventional oil are in place. Compared to the successful development of unconventional oil in the USA, Russia has several disadvantages. The Russian oil sector is dominated by big companies without the flexibility in methods and decision-making required in very heterogeneous unconventional projects. Infrastructure is less accessible in Russia than in most American projects. On a more fundamental level the relatively poor condition of geological data collections is a serious cost increasing factor, and the system for development and dispersion of new technologies has critical shortcomings. Russia lacks appreciation of risk taking and a corresponding regulatory framework, as well as relevant financial mechanisms. Nevertheless, government documents almost exclusively focus on technology as such as well as on taxation and tax benefits as preconditions for successful development. Without addressing the fundamental institutional problems, the potential for exploiting the resources base will be limited.

Geophysical data processing, rock property inversion, and geomechanical model building in a Midland Basin development project, Midland/Ector counties, Texas

The current state of the art for development of unconventional projects integrates geology, geophysics, and engineering into a comprehensive reservoir description. To that end, we have designed a comprehensive geophysical workflow to define the structure, stratigraphy, and rock mechanics of a stacked reservoir sequence in the west-central Midland Basin. The purpose of this paper is to describe the workflow. Portions of three seismic data sets were merged and processed anisotropically, preserving the full range of azimuths. Well control consisted of 35 compressional sonic logs, eight shear sonic logs, three sonic scanners, two lateral formation microimaging tools, and three cores. Nine newly drilled laterals are on production along with a large number of vertical legacy wells. Prestack inversion produced acoustic impedance, shear impedance, and density with good accuracy, although the compressional-to-shear-velocity ratio (VP/VS) was not stable. This volume was successfully recreated via neural net, which was also used to calculate total porosity and total water saturation volumes. Poisson's ratio, Young's modulus, and brittleness were created using standard equations and the neural net VP/VS volume. Structural attributes consisted of ant track, coherence, semblance, fault probability, and Kmin and Kmax curvature. The final step in this portion of the workflow was to create a high-resolution depth conversion velocity volume. A geocellular grid was built and populated with petrophysical volumes, lithology facies, and structural attributes. Principal stresses were incorporated by first establishing 1D mechanical earth models (MEMs) where appropriate log suites were available. These 1D MEMs were extended to a 3D MEM, although confidence in this volume is not high due to known pore pressure and closure stress reductions as a result of legacy vertical well production. Calibration incorporating new data as it becomes available is an ongoing task. An informative simulation using the MEM is frac models, which define the most optimal landing points for laterals. This MEM and the simulations it can perform have easily demonstrated the value of this integrated workflow.

Double vision: Insights about the origin and interpretation of multiple IRRs

ABSTRACTThe ability of a project's internal rate of return (IRR) to quantify its economic return has been questioned by many scholars over the past 60 years, most recently by Magni (2010, 2013). Although IRR is a plausible—albeit imperfect—measure of a project's economic return when the cash flow stream is conventional, IRR can be an untenable measure of an unconventional project's economic return. The goal of this article is to identify a simple, intuitive explanation of IRR, one that can be applied to any cash flow pattern. To do this, the article shows how a project's IRR systematically changes when it first crosses from the conventional into the unconventional realm (i.e., a small cash outflow is appended to a conventional cash flow stream) and then as it becomes progressively more unconventional. This process reveals that the most robust economic interpretation of IRR—for both conventional and unconventional projects—is that a project's IRRs are external benchmarks that divide the set of all plausible discount rates into positive and negative net present value (NPV) ranges, rather than internally generated returns. Because it can be difficult to estimate a project's cost of capital with precision, this information can help guide the sensitivity analysis of a project.

Unconventional Resources Technology Conference Highlights Shale as an International Business

Unconventional Resources Technology Conference Highlights Shale as an International Business

Transformative city branding for policy change: The case of Seoul’s participatory branding

City branding has been widely adopted by entrepreneurial local governments to strengthen city identities and to attract global attention amid intensified intercity competition. Asian global cities, in particular, have competitively branded themselves to signal that they belong to the group of advanced global cities. This paper illustrates the transformative role of city branding in the making of a global city’s local identity, which has been hitherto underexplored in the literature. Specifically, it examines Seoul’s branding exercises, focusing on its unconventional projects that reflect the city’s recent efforts to become a “human-centered,” progressive city. We suggest adding a “transformative-enhancing” dimension to the existing “external–internal” city-branding framework, and argue that Seoul’s transformative city branding is, in fact, communicating the mayor’s new signature policies with citizens. When combined with a strong mayor’s efforts to cater to changing societal pressures, city branding is no longer solely a neoliberal marketing exercise, but a political project of policy change.

A practical workflow for performance prediction of low permeability reservoirs

The Society of Petroleum Evaluation Engineers (SPEE) recently released ‘Monograph 4 – estimating ultimate recovery of developed wells in low-permeability reservoirs’ (hereafter called ‘Monograph 4’; SPEE 2016). This paper outlines a practical engineering workflow enabling companies to evaluate unconventional plays developed with horizontal multi-stage fractured wells consistent with the principles summarised in Monograph 4. This workflow has many applications including assessing potential acquisitions, defining new plays, evaluating competitor results, corporate budget processes, long-term business planning, portfolio management and reserves certification. The workflow, developed and refined over several years, has proven effective in large-scale applications. It enables engineers to readily identify and assess flow regimes, estimate the time to boundary dominated flow and estimate the flow patterns of boundary dominated flow for large groups of wells. The workflow also allows the engineer to deal with changing well designs and completion techniques. Throughout the workflow, the geological, engineering and statistical methods described in Monograph 4 are used. This provides the foundation to define and create representative type curves, yielding statistically reliable estimates of expected ultimate recovery (EUR) and production forecasts for asset evaluation with an accompanying characterisation of the confidence of these estimates. A case study demonstrating application of this workflow and a summary of results are presented. Potential sources of error in the technical analysis and application of type curves are identified; the technical and commercial impacts of these errors are highlighted. By allowing the evaluator to focus time and attention on the details of the technical analyses, companies can achieve a quicker, more in-depth analysis of the development of these large-scale unconventional resource projects.

The small academic press in the land of giants

Mergers and acquisitions, for example the merger of Macmillan Science and Education with Springer Science+Business Media, might suggest that large is the future for academic publishing. It might seem that giant players will dominate the future of scholarly publishing, but, at the same time, this year has seen the launch of UCL Press, the University’s in-house publishing arm. Goldsmiths, University of London, has also announced it is preparing to launch Goldsmiths Press, a new university press built on digital-first publishing, especially around unconventional projects traditionally excluded by publishers. Some of the more established university presses also seem to be increasing their scope. For example, Stanford University Press launched a new trade imprint and Manchester University Press has announced it has acquired forward titles from Bloomsbury Publishing. Insights asked two experts if there really is scope for the small academic press in the modern scholarly publishing environment. Frances Pinter has provided the perspective of the small university press. She is realistic about the challenges small academic publishers face, but concludes that there is space and opportunity for them to coexist with the giants. Michael Magoulias is equally realistic about the challenges of small, but sees the university press as a necessary, not to say, vital, alternative to commercial publishing.

Unconventional Risk Allocation: Managing the Life Cycle of Shale Projects

Model contracts play a principal role in reducing transaction costs. They offer parties a series of rules, which allocates risk so that delays, disagreements, over-expenditures, and under-capitalizations can be managed (or avoided altogether). The best model contracts are highly responsive, quickly adapting to new realities. Accordingly, top drafters are pressed to doggedly re-evaluate whether or not their model rules are optimal in light of the ever-changing nature of law and technology. Modern hydraulic fracturing is a disruptive technology that shifts the incentives within oil and gas joint venture projects. Drafters are adjusting their contracts to adapt. Experimentation with model rules is presently occurring in jurisdictions such as the United States, Canada and Australia, where unconventional resources abound. This adaptation of model contracts (e.g. the third industry draft of the proposed updates to the 2007 CAPL Operating Procedure) has created a debate as to which model rules will be best for unconventional shale projects. As a contribution, this article first introduces how modern hydraulic fracturing has changed risk allocation in joint ventures, and then considers a couple of the central debates over what changes might need to be made so that model contracts can successfully adjust to this new reality.

Navigating in Deep Water: Greater Rewards Through Narrower Focus

Management The deepwater oil sector is at a crossroads. Deepwater production (defined as oil produced in water depths of greater than 450 m) has had a spectacular run over the past decade as major oil companies broadened their portfolios worldwide. Global investment soared from USD 16 billion in 2003 to more than USD 70 billion in 2013, and production has more than doubled over the past 10 years to almost 6 million B/D, or 7% of the world’s total oil supply. The major oil companies have seen deep water as an attractive business that can deliver large volumes at high margins, more than offsetting its handicap of tying up immense amounts of capital and technical challenges. They have doubled down, betting on deep water across the globe: the average number of countries in which the supermajors participate, including investments made by BP, Chevron, ExxonMobil, Shell, Statoil, and Total, in deepwater projects has increased from three to seven over the past decade. In the past 12 months, however, deep water has come under new scrutiny. Even before the recent drop in oil prices, many big oil companies have been coming under pressure from investors to rein in their capital investment. Deepwater projects typically cost billions of dollars—the average cost of the 10 most recent deepwater projects in the US Gulf of Mexico (GOM) is USD 12 billion— and have been seeing sharp cost inflation in recent years, prompting companies to review them more critically, as onshore unconventional oil and other projects now appear to offer more capital efficiency. The heightened scrutiny is coming at a bad time for deepwater operations. Setting aside the inherent volatility of oil prices, a number of well-recognized trends are now in place that could seriously affect the value-creation potential of deep water over the next decade compared to its historical performance. First, costs have been increasing rapidly, and project delays are recurrent. Not only are shortages endemic for certain types of equipment, but also supply-chain constraints in certain basins are causing steep cost inflation. Second, deepwater players know from experience that pushing the frontiers of exploration into more challenging geological areas at evergreater depths farther from shore slows development and incurs higher costs: rigs need to be hired for more days to drill each well and require more support vessels. Third, oil companies also know that government requirements across the major basins are increasing and these requirements will be determining factors in the financial prospects of future projects. While the precise nature of the government requirements varies in different basins—whether it be degrees of operatorship control, local content requirements, new environmental regulations, or the share of revenue taken by governments—they all tend to reduce margins.

Encouraging traditional owner participation in onshore unconventional projects

Australia has significant unconventional energy resources that can be tapped to bolster energy security needs and increase contributions to the global energy supply mix—fuelling both domestic and international economic growth. A key factor underpinning the success of developing onshore unconventional resources is the security of land and tenure access, which allows project proponents to sustainably engage in the exploration, appraisal and development of unconventional gas deposits spread across extensive geographical areas. These activities occur in areas that are vested in traditional landowners and indigenous native title holders, and have the potential to significantly impact their cultural heritage and their quality and way of life. It is, therefore, critical, on a number of levels, for project proponents to have the support of this key stakeholder group in ensuring the long-term viability of developing onshore gas resources. Alignment between the project’s proponents and the diverse range of traditional/indigenous landowners who influence—and are influenced by—their operations, however, is not easy to achieve due to competing interests and motivations. This extended abstract explores: alternative participation models for traditional land owners in onshore unconventional gas projects, including production payment and equity-based ownership models; examples of co-existence arrangements between project proponents and traditional owners; the impact of fiscal policy on the economic viability of alternative traditional owner participation and co-existence models; and, the role of state and federal governments in giving incentives to and fostering greater collaboration between project proponents and traditional owner groups.

Using innovation to lower gas gathering costs for unconventional projects

Moving from conventional to unconventional gas project development requires a significant shift in approach. This presents challenges for operators making this transition, including standards and specifications being mis-matched to functional requirements, the need for robust surface and subsurface field development planning, lack of infrastructure, high construction and procurement costs and the scarcity of supply chain and logistics support. In their need to prove up sufficient reserves in time for downstream LNG plant operations, coal seam gas (CSG) players have neglected the development of appropriate standards, specifications and contracting and procurement strategies that consider how upstream costs can be minimised. This can impact project viability in a high-cost, low-productivity environment. The requirement of shale gas development for continual expansion also presents challenges compared to conventional project development. Adopting a factory approach can ensure a smooth and economic transition through the phase of continual shale gas production across the life of individual wells and through field expansion. Using case studies, this extended abstract describes how innovation can be applied across the gas-gathering development phase of unconventional projects to achieve significant cost savings. Key innovative opportunities include: Maximising modularise construction and operation to reduce the construction schedule and maximise onsite productivity Relocatable, interchangeable, standardised skid designs (design kit approach). Standard modules sized to maximise container volumes (and they minimise freight costs) Low-cost design Asian and Australian fabrication. Fit-for-purpose technology and packages to lower operating costs. Design and fabrication to minimise environmental impacts.