For an industry in which terms like “first ever,” “unparalleled,” “unprecedented,” and “novel” are often over-used to the point of losing their meaning, 2020 hit hard with the true meaning of those words as the COVID-19 pandemic exploded onto the world and disrupted almost everything about life as we knew it. The oil and gas industry, which had begun showing signs of recovery from a generational downturn, was hit particularly hard. Jobs were lost, companies shuttered, and supply chains upended. But the same combination of audacity and ingenuity that has driven the industry for over a century took hold quickly. Oil and gas people love - and need - to network, share ideas, transfer and apply technology, and gather intelligence. So, when in-person conferences, workshops, and tradeshows were suddenly canceled or indefinitely postponed, entities such as the Society of Petroleum Engineers scrambled to use digital technology to take those events online and make them virtual. While not a perfect replacement, virtual online events offer some unique advantages, as SPE technical directors pointed out in their annual roundup. Digitalization, long a controversial topic among many in the upstream sector, is now being called essential by the directors across the six SPE technical disciplines they lead. Automation is mentioned frequently in the directors’ comments as a growing contributor to efficiency and risk reduction. Capital discipline, balance sheet management, and cash flow are seen as crucial, as are collaboration (both internal and external) and value - ranging from core values to value-driven data, to provable, value-based outcomes. Agility and the ability to comply with environmental, social, and governance (ESG) criteria have taken on new importance. So has work - how and where we do it, and how we balance it with other aspects of life. Knowledge dissemination is considered more important than ever. Uncertainty continues to characterize the upstream sector, even more so than before the pandemic, but at least one thing is certain: The work of the industry, and the way in which people who comprise it work, is forever changed. The SPE technical disciplines and the directors who lead them are as follows. Completions - Terry Palisch, CARBO Ceramics Data Science and Engineering Analytics - Silviu Livescu, Baker Hughes Drilling - David Reid, NOV HSE and Sustainability - Annamaria Petrone, Eni Production and Facilities - Robert Pearson, Glynn Resources Reservoir - Erdal Ozkan, Colorado School of Mines Here, they reflect on a truly unprecedented year and share their outlooks for their disciplines going forward.

Do what you can, with what you have, where you are. - Theodore Roosevelt, 26th US President Getting Oriented - The Only Wrong Direction Is Backwards I begin this column by saying that after attending several recent SPE events filled with students and professionals, all virtual of course, that I have seen the very best of us as members of SPE. To a person, you all have been nothing short of inspiring. Our members know that there is a better tomorrow on the horizon and diligently prepare for the days when our industry begins to thrive again. On the other hand, the industry consolidations and workforce reductions continue, and frankly, I don’t know of anyone whose life and career has not been touched by this pandemic-induced crisis. It’s an axiom of life that if you cannot control it, then you must control how you deal with it. I believe operating under this axiom will serve us well collectively and individually as we push through the pandemic. I want to repeat a passage from my remarks at the President’s Session on Member Monday at ATCE in late October. “As an industry, we are as relevant as ever, even more so now. And further, our industry continues to provide economic growth, as well as access to cleaner water, better food, and affordable transportation. I am a believer, a true believer, I believe in what we do, in who we are, and how important our contributions are to society … I want to thank each of you for your time and effort in support of SPE. We are who we are because of what you have done, and we are who we will become because of your commitment to serve this industry and our global society. The world needs what we do - now, more than ever.” I want you to know that I believe in our mission and our future. As we “Get Oriented,” I want to assure you that as a discipline, we will become stronger, and as an organization, SPE will become more focused on content generation and delivery than at any time in its history. Most importantly, I want to assure you that SPE will continue to serve its members and its global community as the preeminent technical organization in upstream oil and gas. It is imperative that you “Get Oriented” with what you can do and will do in the future as SPE continues to evolve.

The oil and gas industry is facing unprecedented and brutal market conditions. While the industry was already in the midst of digitalization, the oil price crash has instilled a fresh impetus on its adoption to cut costs through innovation and new technologies. One such technology is predictive maintenance. When equipment on a rig breaks down, the resulting problem often is not that of replacement but the forced downtime in production or drilling. Therefore, predicting when equipment or a system is going to fail and determining the root cause of failure unlocks significant value. Predictive maintenance has rapidly gained in popularity, spurred by well publicized advances in high-performing computing and Internet of Things (IoT) technologies. Some companies are experiencing the benefits of predictive maintenance firsthand. For example, engineers at Baker Hughes implemented predictive maintenance on the company’s fleet of fracturing trucks. They collected nearly a terabyte of data from pumps on these trucks and then used signal-processing techniques to identify the relevant sensors. Finally, they applied machine-learning techniques to distinguish a healthy pump from an unhealthy one and reduced overall costs by $10 million (MathWorks 2019). This success story and others like it have made pursuing predictive maintenance projects a priority among both oilfield operators and services firms.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196566, “Mexico Pilot Project To Classify Oil and Gas Projects Using United Nations Framework Classification,” by Satinder Purewal, SPE, Imperial College, and Fidel Juárez Toquero, SPE, and Eduardo Simón Burgos, National Hydrocarbons Commission of Mexico, et al., prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. A pilot project was initiated to classify oil and gas projects in Mexico using the United Nations Framework Classification (UNFC). The UNFC assists in identifying key social and environmental factors that could impede the movement of oil and gas volumes higher up the value chain. To the authors’ knowledge, this is a unique project with significant value-adding outcomes that can be replicated in other countries. Mexico’s Perspective For proper assessment of discovered and undiscovered hydrocarbon volumes, Mexico adopted the Petroleum Resources Management System (PRMS) as its official classification framework. The country features a wide spectrum of cultures, indigenous identities, and social organizations, and in some cases, industry activities could represent a threat to these aspects of Mexican life. As an effect of the nation’s geographical location, a diversity of ecosystems exists, from deserts to regions rich in flora and fauna such as rainforests and wetlands. This reality emphasizes the need for robust legislation guaranteeing the protection of the environment. UNFC The UNFC is a system for classifying resources including petroleum, minerals, and renewables. Quantities are classified on the basis of a 3D, three-axis system (Fig. 1). Each axis assesses different factors on the basis of three fundamental criteria: economic and social viability (E), field project status and feasibility (F), and geological knowledge (G), using a numerical coding system. Categories and subcategories of each axis are the building blocks of the system and are combined in the form of classes. A class is defined by a combination of categories or subcategories sourced from each of the three criteria. A classification made according to the UNFC will be expressed with a three-digit code providing the location of the project in the 3D system, starting with the E, then the F, and finally the G axis. Additionally, the three-digit code can be expressed in terms of categories (E1, F1, G1) which will be read as classes, as well as in terms of subcategories that are read as subclasses. The three-digit code provides information on the maturity status of a project. When category level is used, projects can be classified as Commercial, Potentially Commercial, Noncommercial, Exploration, and Additional Quantities in Place associated with known and potential deposits. When the subcategory level is used, projects can be subclassified. The relationship between the PRMS and the UNFC can be explained better in terms of the linkage between the evaluation processes of the range of uncertainty and chance of commerciality in both systems. The PRMS categorizes the volumes to size the range of uncertainty present in the estimates, while the UNFC does the same through G-axis evaluation.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195271, “Constrained Least-Squares Multiwell Deconvolution,” by J. Cumming, Durham University; V. Jaffrezic, SPE, Total; and T. Whittle, Imperial College, et al., prepared for the 2019 SPE Western Regional Meeting, San Jose, California, 23-26 April. The paper has not been peer reviewed. In the complete paper, the authors reduce nonuniqueness and ensure physically feasible results in multiwell deconvolution by incorporating constraints and knowledge to methodology already established in the literature. The paper demonstrates that a combination of constraints on the shapes of the deconvolved derivatives and knowledge of the reservoir results in an improved level of quality and consistency in multiwell deconvolution solutions. The new constrained least-squares multiwell deconvolution approach is illustrated by synthetic examples with known solutions involving up to nine wells. Introduction To apply multiwell deconvolution to real data, confidence must exist in the validity of the solution it provides and the consequent interpretation that is inferred. Therefore, for practical multiwell deconvolution of field data, reducing the nonuniqueness in a solution, ensuring the results are physically feasible, and providing the desired consistency and quality of solutions are essential. With these goals in mind, the authors extend existing methodology to incorporate additional constraints and introduce additional knowledge. These constraints allow encoding of information about the behavior of the deconvolved derivatives to penalize and discourage nonphysical solutions and improve solution quality. Additionally, the approach encodes a priori knowledge, for instance that all pressure responses ultimately will show a closed reservoir by imposing a constraint that future derivative behaviors should tend toward a common unit slope. Through a combination of these techniques, an improved level of quality and consistency of deconvolution solutions can be achieved. Constrained Least-Squares Multiwell Deconvolution A key issue in any deconvolution, single-well or multiwell, is the lack of a unique solution, which results in sets or ranges of possible response functions that yield pressure matches of indistinguishable quality. When this space of possible solutions is large, then the associated response function could correspond to reservoir models with multiple differing (and potentially contradictory) interpretations. Clearly, reducing the range of possible solutions as much as possible, and assessing and quantifying the uncertainty surrounding those solutions, is critical to provide confidence in the accuracy of conclusions. One primary reason why the space of potential deconvolution solutions is so large is the choice of parameterization as a sequence of straight-line segments. In single-well deconvolution, such concerns motivated the introduction of the smoothness component to the error function in order to penalize potential deconvolution solutions with unfeasibly rough or oscillatory response functions. A second source of nonuniqueness in deconvolution is the error and uncertainty associated with the measured test data. The smoothness constraint also is particularly useful in addressing this problem.

Q Engineering sells a cloud-based program that statistically predicts future production. Using its Typecurve Studio, a user can forecast 500 decline curves a minute after the data are downloaded from a database, said Mark Bahorich, the cofounder of Q, which was recently acquired by Enervus. Doing that manually would take from 2–5 minutes per well, or about 16–42 hours, he said. The downside of having a machine do it is that engineers once earned good money doing those boring jobs. If one person can do what 10 to 20 people once did, “you are getting rid of 9 or 19 jobs, or they need to find new stuff to do,” said Nathan Meehan, president of Gaffney, Cline, and Associates and 2016 SPE president. Long-term careers in petroleum engineering in the future will depend on an engineer’s ability to find valuable things to do. It is not a new challenge. Exploration and production is a cyclical business where engineers are possible targets when business slumps and cost cutting is required. Survivors often have additional skills, such as project management, team leadership, digital knowledge, or specialized technical knowledge. During a presentation on lessons learned during a long career in the oil business, Hon-Chung Lau, a professor in the Department of Civil and Environment Engineering at the National University of Singapore, described the decades of effort required over a career, which he breaks into three, 12-year stages (SPE 196027). Those who successfully reach the last stage of their career may feel secure. But Lau warns, “That is the stage when your career may be at risk.” Those who see a hefty paycheck as a sign of their value to the organization need to consider that earning the same salary as two new hires could make them a layoff target, he said during a presentation at the 2019 SPE Annual Technical Conference and Exhibition.

Technology Focus Summer jobs working on drilling rigs in western Oklahoma and California in 1980 and ’81 were great adventures. High oil and gas demand meant major and independent operators used some of the latest, state-of-the-art rigs to probe deep into high-pressure reservoirs. Planning and executing wells back then was a manual process with experience, horsepower, pencil, and calculator. My adventures continued after I graduated from college in 1982. Ever-evolving drilling, completion, and subsurface technology characterized the years that followed. Fast forward to February 2020. “The more things change, the more they stay the same,” the old-timers might say. In many field locations today, old-school machinery and processes remain in place. However, we see artificial intelligence (AI), data analytics, machine learning, and related advancements transforming our industry. These developments have been headlines for several years now but will take more time to reach full fruition. Experts agree this is just the beginning. Jensen Huang, chief executive officer and founder of Nvidia, highlighted this during a CNBC interview in November. “We are at the beginning of the AI revolution, one of the most powerful technological forces of all time,” he said. “We’ve created the ability for computers to understand the code of human knowledge. All industries will be transformed.” Huang, an AI visionary, showed a 4D simulation of an unmanned Mars landing craft on final approach going from 12,000 mph to zero in 6 minutes. Such visionaries are also working in upstream exploration and production to achieve remarkable advancements. A focus on drilling innovation reveals no shortage of SPE papers that exemplify these exciting trends. Without exception, the featured articles reflect increased volumes of surface and downhole data that are being captured and analyzed to enable deep learning, improved efficiency, safety, and value. As noted in paper OTC 29487, oil and gas companies are creating layers of digital knowledge enabling a new generation of AI-driven applications. New insights into mitigation of drillstring vibration, well-control events, and rate-of-penetration optimization follow. Managed-pressure drilling remains a persistent trend that continues to evolve across onshore, offshore, and geographical boundaries, opening new frontiers once seen as out of reach. One need not look to outer space to imagine the extent of breakthroughs to come in the not-too-distant future. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 194535 Nitrogen-Cap Drilling: A Managed-Pressure-Drilling Alternative for Highly Fractured Carbonate Reservoirs by Alexey Podust, Tengizchevroil, et al. SPE 196166 Standardization: Successful Implementation of Driving Consistency in Deepwater Operations by Daniel A. Durey, Shell, et al. SPE 197942 Innovative Digital Well-Construction-Planning Solution Enhances Coherency and Efficiency of the Drilling-Design Process by Waldemar Szemat-Vielma, Schlumberger, et al.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194351, “Real-Time Analysis of Formation-Face Pressures in Acid-Fracturing Treatments,” by Vibhas Pandey, SPE, and Robert Burton Jr., SPE, ConocoPhillips, and Kay Capps, Capsher Technology, prepared for the 2019 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 5–7 February. The paper has not been peer reviewed. Knowledge of formation-face pressures is critical to the success of hydraulic-fracturing treatments, especially in multistage and multiple-cluster-type horizontal-well completions. This knowledge can help in evaluating the effectiveness of acid-fracturing treatments in dynamic mode and also can enable and improve real-time decision-making during treatment execution. This paper contains a detailed discussion of methods and a software tool that has been developed to generate information that predicts formation-face pressures in real time with the help of live bottomhole-pressure data. Introduction Acid-fracturing treatments combine the basic principles of hydraulic fracturing and acid-reaction kinetics to stimulate acid-soluble formations. Unlike propped fracturing treatments, in which a viscous pad is followed by slurry-laden fluid that assists in keeping the fracture propped open to create a conductive flow path for formation fluids, the fracture conductivity in acid fracturing is generated by dissolving the formation face to create an uneven surface on the fracture walls. Multiple pad and acid stages are pumped during the course of the treatment to create a high-conductivity fracture. The acid stage then fingers through the pad and the open fracture to create differentially etched patterns on the fracture walls. The uneven, etched surfaces prevent the fracture from closing completely once the hydraulic pressure is removed, leading to a highly conductive pathway to enhance hydrocarbon flow. Once the acid contacts the formation, the bottomhole treating pressure recedes quickly, and, as acid spending continues, the effective bottomhole pressures can fall below fracture-closure stresses. Not all loss of pressure is a result of acid spending alone. The fluid fingering among fluids of highly contrasting viscosities also can result in such drops. However, the stress relief that results from acid spending dominates this behavior. Pumping additional acid in these cases only results in near-well acid or mineral reactions, which do not extend fracture penetration and may increase wellbore-integrity risks. Unfortunately, without a good estimation of effective fracture pressures, determination of when the fracture-treatment pressure dips from above closure stress to below closure stress is difficult. Determination of this critical transition was a primary driver of the study that led to the creation of a tool that can assist in determining the real-time treating pressures at the entry of the fracture during stimulation treatments. Several acid-fracturing treatments were analyzed using the tool, leading to important conclusions related to fracture-propagation modes, acid-exposure times, and effectiveness of given acid types.

Special Section: The Value and Future of Petroleum Engineering Short of choosing a life partner, deciding on a profession may be the most important decision any of us ever makes. And there are many who would debate which of these takes precedence. I consider myself amazingly fortunate in having made perfect choices in both categories. Anyone who has met my wife, Dina, can vouch for the first one. This is my opportunity to talk about the second. When people ask me what I think about petroleum engineering as a profession, I answer, “Petroleum engineering is not just a great profession; it’s the best profession.” Here is why. Name another profession that is fun, intellectually and physically challenging, personally and financially rewarding, and critical to true global sustainability on both a macro and micro scale. I can’t think of one. Beyond the basics of skills, aptitude, education, and interest, the way we choose our professions has changed dramatically over the past 50 to 60 years. The goal for many of our parents, and even some of us, depending on our age, was to join a company where we could make a good living, rise in the ranks, and work from graduation to retirement. That world no longer exists. Today the question of what to consider when choosing a profession consumes magazines, books, and the internet. A 2018 online Harvard Business Review (HBR) article reported on what motivates people at work, beyond obvious basics such as salary, time off, and benefits. To find answers, HBR ’s people analytics team collaborated with Facebook. Based on surveys conducted twice a year asking what employees value most, the team identified three big buckets of motivators: career, community, and cause. As the article said, “It turns out we’re all hoping to find a what, a who, and a why.” Career—The What According to HBR , career is about work. It’s about autonomy, about using your strengths, and promoting learning and development. It’s at the heart of intrinsic motivation. It’s what you do throughout your working life, and may span many jobs and many companies. Engineers share many traits, perhaps the most common of which is our love of solving problems. Petroleum engineering is the pinnacle of problem solving. For the 7.2 billion people on our planet, we have to solve the problem of how to deliver affordable energy from oil and gas, and how to do so safely and economically. We must solve the problem of operating in ways that don’t threaten our planet and its future generations. And, we must do all of this in a way that helps our employers achieve acceptable return on investment.

Special Section: The Value and Future of Petroleum Engineering In the JPT issue celebrating SPE’s 50th anniversary, John C. Calhoun addressed how distinctive petroleum engineering is from other engineering disciplines: “During the past several decades, consolidation and integration of four major elements of petroleum engineering have occupied the profession. The following lists these elements. Extending our capabilities to gain access to, to couple with, and to operate within a greater portion of the subsurface environment (e.g., offshore locations, over-pressured environments, marginal reservoirs, horizontal drilling, complex flow systems, acidizing, and hydrofracturing). Developing methods for detailed characterization of subsurface formations, their fluids, and their surroundings (e.g., geostatistics, well logging, indirect geophysical measurements, well-performance analysis, and basin analysis). Recovering a greater proportion of the petroleum within reservoirs that have been accessed and understanding the transfer operations that accompany the recovery (e.g., a broadened spectrum of injected fluids and fluid additives, phased fluid injection programs, extensions of reservoir flow paths, in-field drilling, and horizontal wellbores). Systematizing technological management and coupling it with business decision making (e.g., history matching, risk analysis, reservoir management, software packages, and team projects).” 1 Since that issue a little over a decade ago, petroleum engineering feats have expanded on the past and made towering breakthroughs in resource recovery. Those breakthroughs came about with added emphasis on decision and risk analysis as an essential project element; a step up from what was referred to as a coupling with business. Reviewing our technology history thus requires highlighting the tangible breakthroughs with the necessary intangibles that enabled faster transformations with commercial success (Fig. 1). Tangible Breakthroughs Arguably the biggest breakthrough during the past 50 years was Mitchell Energy’s approach to making shale production viable. Well stimulation began in the mid-1800s with torpedoes used on Pennsylvania wells. It was the subject of the first JPT technology article published in 1949, “A Hydraulic Process for Increasing the Productivity of Wells,” by J.B. Clark. 2 Mitchell’s approach was not so destructive as the torpedo approach and packed more energy per square nanometer to tip the scales of global supply sourcing. By leveraging the refinement of existing technologies, such as slickwater fracturing adopted from Union Pacific Resources Group, Mitchell’s engineering ushered in new sources of economic reserves, rebalancing top global supplier positions between North America and the Middle East. An equal contributor to shale success was horizontal drilling. While slant drilling was derisive in the 1920s, legal and more reliable horizontal drilling evolved with major advancement in the 1970s through the use of mud motors, “bent subs,” whipstocks, and measurement-while-drilling tools. The petroleum engineer’s ability to reduce trips, monitor, and course correct through tight lateral intervals advanced getting wells on production sooner, with lowered risks and better financial results. Direct public benefit from results such as this are exemplified by the number of sovereign wealth funds established using oil and gas proceeds: the Alaska Permanent Fund, Texas Permanent University Fund, and funds in Norway and the Middle East, to name a few.

Special Section: The Value and Future of Petroleum Engineering JPT asked several active SPE members about the appeal of petroleum engineering, the significance of the work they do, and what the future may hold. Here are some of their answers. What are the most positive aspects of being a petroleum engineer? I dreamed of being a petroleum engineer as early as middle school in the 1990s. Eventually, I studied petroleum engineering in college. After spending more than 20 years in the oil and gas industry, working in numerous countries and being involved in many megaprojects, I believe the most positive aspect of being a petroleum engineer is the fact that we deal with the world’s energy needs. The task of pro-duction alone faces many challenges, but at the same time, we as petroleum engineers are responsible for a proactive approach to safety and the environment in our operations. We are heavily involved in technology, which allows us to explore and produce resources safely and minimize environmental impact. Ardian Nengkoda, Group Lead, Saudi Aramco Being a petroleum engineer means that you follow one of the most influential career paths in our society because hydrocarbon resources will continue to be the dominant source of energy for the next 5 decades, and their use will be required for the next century and beyond. Luigi Saputelli, Petroleum Engineering Consultant, Frontender I have always felt that by being a petroleum engineer I am helping people to live a better life. We make transportation possible; we keep people warm; we provide medicine and material for plastics such as cell phones, computers, and many other things that are part of the modern lifestyle. I enjoy being a petroleum engineer because in a single day you can do a huge variety of things, and over the course of a career you can change your focus from production to reservoir or drilling and face new challenges and learn more with each passing year. Through SPE we can always be learning. I have also loved the fact that in every company I was encouraged to do volunteer work in the community, from giving talks to grade schools, judging science fairs, teaching children and adults to read, planting trees, picking up trash, mentoring, and serving on a board. The ways we are encouraged to serve is endless. Joyce Holtzclaw, Senior Vice President, E&B Natural Resources

Guest editorial Thirty years after Piper Alpha and the subsequent Cullen Inquiry into the disaster, which made 106 recommendations accepted by the oil and gas industry, safety remains a priority and a concern. In recent years, operators and the supply chain have worked in a relatively constrained, low-cost environment. The dramatic shift to producing hydrocarbons at lower cost, with fewer people, while transitioning to a more environmentally friendly and sustainable energy future is well under way and will undoubtedly have impacts long into the future. Business leaders and workers must take responsibility for increased investment in healthy, safe working practices and work closely with regulators globally to manage risk. Regulators remain vigilant toward major accident hazard management (MAHM). They are watching for gaps in safety-related skills that may potentially arise and lead to a higher incidence of major accidents in an industry cautiously stabilizing after the downturn. Knowledge loss, from the enforced mass departure of an aging and skilled workforce within the industry, is a concern as highlighted by a recent report from an industry/government working group in Norway, which reviewed offshore health, safety, and environmental (HSE) performance. It commented that although the level of HSE offshore Norway was high, safety challenges have risen in the past few years. 1 Plugging the Skills and Knowledge Gap New research has revealed that recruitment is firmly back on the agenda after 4 years of consistent reductions, spurred by cost-efficiency measures. According to A Test of Resilience, DNV GL’s ninth annual report on the outlook for the oil and gas industry, more than a third (34%) of the 791 senior professionals surveyed expect to grow their workforce in 2019—more than three times as many respondents than 4 years ago (10%). Over a third (39%) also expect to increase the use of contractors this year. However, skills shortages and an aging workforce have resurfaced as a major concern. The issue takes joint second place as a perceived barrier to growth, alongside the oil price and the state of the global economy. Competitive pressure is viewed as the greatest challenge. The study also found a leap of 20 percentage points over the past 2 years in the number of respondents looking to increase or maintain investment in training and competence, up from 65% in 2017 to 88% for the year ahead.

Editor's column Slow uptake of innovation and new technology is an oft-repeated criticism of the oil and gas industry. The charge is that, despite the vast array of complex technology developed by service companies and put into play by operators over the past 2 decades, the industry is slower to adopt breakthroughs compared with other industries—from pharmaceuticals to aerospace—and that that has hurt its ability to move forward and attract talent. A new book examines whether that proposition is still valid today and what technology adoption in the future may look like. Extracting Innovations: Mining, Energy, and Technology Change in the Digital Age examines the nature, trends, drivers, and challenges of innovation in the extractive industries, such as oil and gas and mining, through a series of essays and vignettes. Among the issues addressed are why the extractive sectors are historically slow to adopt and use new technology; what strategies can improve innovation and uptake; what new technologies will shape the sector going forward; how digital technologies are changing the competitive landscape and industry architecture; and how new technologies could improve social performance and environmental stewardship. The chapter titled, “How Innovation and Research and Development Happen in the Oil and Gas Industry: Insights from a Global Survey” is based on a survey of SPE members and offers insight into where innovation is most likely to occur in oil and gas and in what types of companies. Robert K. Perrons, associate professor at Queensland University of Technology, surveyed primarily managers worldwide who play significant roles in R&D and technology deployment. The task was to see which entities in the oil and gas industry and which geographic locations are responsible for greater industry innovation and technology uptake. The survey found that the major source of knowledge about innovation came from suppliers and clients, followed by professional conferences and industry standards such as HSE guidelines. Less emphasis is placed on government research organizations, universities, and public sector organizations. There were nuances to the above findings. For instance, international oil companies relied heavy on service companies for innovation knowledge, but service companies relied little on their suppliers. The survey found that about 80% of patents were generated by the service sector, confirming the shift of R&D from operators to service providers that began in the 1990s. Also of note is a chapter examining a framework for a data-driven assessment of unconventional oil and gas resources. The plays in the study were the Bakken, Haynesville, Barnett, Marcellus, and Eagle Ford. Another discusses how industry can use social media to improve relations with stakeholders. Social media could allow companies to respond to concerns raised by communities or activists sooner, and improve communication among all groups. Because of the widespread changes caused by the oil price downturn and the rate of technological and methodical changes taking place in the unconventional sector, the above topics call for follow up and should be viewed as a snapshot of conditions at the time. Perrons is concluding a followup survey on innovation that will outlined in an upcoming issue of JPT.

BP has invested more than $100 million into nine different startup companies in the past 2 years—but only one of them wants to turn your brain into a piece of its software. The international major is working with the ambitiously named firm Beyond Limits on a set of artificial intelligence (AI) programs that will absorb the learnings of geologists and petroleum engineers, and then imitate their decision-making processes as they work on subsurface challenges together. Before this partnership, Beyond Limits had never been involved in solving the complexities of oil and gas, which is something that might be counted against it by venture capital or prospective upstream clients. But after BP saw what the young company was working with in its office about 10 miles north of downtown Los Angeles, it decided to become both its largest client and its largest investor by injecting it with $20 million a year ago. The attraction for BP came down to getting its hands on a strain of AI known as cognitive computing, or what Paul Stone refers to as “the pinnacle of the artificial intelligence pyramid.” “We haven’t seen that elsewhere, so we wanted to be the first to engage and see where it might go in the oil and gas industry,” said Stone, who serves as a technology director in BP’s digital innovation group. And where it lacks a prior track record in oil and gas, Beyond Limits compensates with a technology team that helped design most of the same intelligent software it is licensing from the Jet Propulsion Laboratory ( JPL), an institution run by the influential California Institute of Technology in cooperation with NASA. Similar to oil and gas explorers, at JPL immense uncertainty is the perpetual driver for emerging technologies. AJ Abdallat has served as chief executive officer of Beyond Limits since its founding in 2014 and previously spear-headed several other startups that have been spun out of work first done at JPL. He believes that this firm’s pedigree gives it a big head start in pushing the envelope on cognitive computing because “the issues and challenges we are tackling today, JPL has been tackling for decades.” And though there remains a lively debate about where cognitive computing really stands today in terms of its human-like reasoning capabilities, Abdallat said, “People tend to judge AI based on the last 2 or 3 decades—you really need to look at what has happened in the past 5 to 6 years.” Some of the most notable recent advancements include the AI sector proving that intelligent programs can best human reasoning when it comes to complex games such as Go and Texas Hold’em Poker. Cognitive programs also demonstrate growing promise as a diagnostic tool in the healthcare industry—a vertical that Beyond Limits is positioning itself to break into along with oil and gas.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181216, “Proactive Rod-Pump Optimization: Leveraging Big Data To Accelerate and Improve Operations,” by Tyler Palmer, SPE, and Mark Turland, SPE, Denbury Resources, prepared for the 2016 SPE North American Artificial Lift Conference and Exhibition, The Woodlands, Texas, USA, 25–27 October. The paper has not been peer reviewed. This paper presents how a US onshore operator took a three-step approach to optimize more than 100 rod-pump wells. The approach involved data consolidation, automated work flows, and interactive data visualization. This approach led to increased unit run times, decreased unit cycling, improved production and equipment surveillance, and increased staff productivity. The ultimate goal was to increase profitability by decreasing lifting costs and increasing operating efficiency. Introduction The processes and tools described in this paper cover a subset of approximately 125 wells in eastern Montana and western North Dakota, but they have been designed to be applicable and scalable to any fields that use rod-pump artificial-lift systems with supervisory control and data acquisition (SCADA). Simple modifications can be made to the tools and processes for wells that do not have SCADA capabilities. While optimization efforts and best practices have been implemented for the subject rod-pump systems during the past 6 decades, many opportunities remain to create additional value. Empirical knowledge from field personnel serves as the basis for the analytical model. Categorizing and quantifying the observations made by the field personnel is critical to developing any analytical model involving oil and gas operations. On the basis of feedback from field personnel and engineers, the following areas had the most potential for improvement: data consolidation, automated work flows, and data visualization. The data-consolidation issue stems from data being located in multiple file locations, sometimes being stored in nontabular formats and initially lacking the necessary unique identifiers for mapping between databases. Automated work flows were essentially non-existent; wells were analyzed individually using deterministic, static data. Data were previously visualized in multiple locations but never integrated into a single, interactive visualization tool. The opportunities to maximize asset value led to the development and implementation of the rod-pump optimization tool (RPOT). The RPOT is a data-visualization tool that generates a single recommended optimization action (ROA) for each well being analyzed. The ROA logic calculates the optimal amount of fluid for a well to produce on the basis of its inflow, while accounting for surface and subsurface equipment constraints. General examples of ROAs include slowing wells down by making a specific sheave adjustment, speeding wells up by a specified strokes/minute (spm) amount, upsizing the downhole pump to a specific pump size, or upsizing or converting to a different artificial-lift system. If in accurate or incomplete data are brought into the database, the ROA specifies the data source that needs to be quality-checked.

President's column The value of senior professionals As the SPE 2018 President, I set a goal to revisit the SPE strategic plan, which was last updated in 2013. A lot has changed over those 5 years, and SPE has responded to those changes. Our mission remains unchanged, and our commitment to the One SPE guiding principles (adopted in September 2001) has endured. One of the products of the 2013 strategic plan was an impact review of the “Big Crew Change,” as the current generation of senior professionals with more than 30 years of industry experience retire and leave our ranks. The demographic representing those 55 and older was identified in the strategic plan as a vital and valuable segment of our membership, at risk of slipping away during the then-nascent oil price downturn. While the crew change has passed, our strategic response to this potential significant loss of membership, knowledge, experience, and human resource is critical to the future of SPE and our industry. These valued members carry with them the institutional memory of our trade, the competencies and technical knowledge we seek to disseminate, and the volunteer spirit on which SPE was built. The value of retaining and engaging these senior professional members cannot be overstated, and I personally wish to recruit these venerated members to assist in achieving my goals. I value these members as strategic thinkers, champions of community outreach, and supporters of corporate responsibility. They have so much to offer by mentoring less-experienced members as well as future SPE and industry leaders. These senior professional members can also mutually benefit from their continued engagement in our society. I believe it is imperative that SPE recognize the value these members represent by offering benefits tailored to their specific needs.

Thousands gathered in Austin, Texas, in July to attend the 2017 Unconventional Resources Technology Conference which reflected several of the biggest themes shaping the shale sector and its emergence as an internationally discussed business. Several of the technical presentations highlighted the progress in Argentina’s Vaca Muerta shale play while international operators such as BHP Billiton and Statoil discussed development plans for their US assets. Technical discussions held during the 3-day event, which is sponsored by the SPE, AAPG, and SEG, focused on emerging approaches to improving oil and gas recovery from tight rocks and exploring where the risks still lie with induced seismicity. Other important themes such as applied data analytics solutions, improving refracturing techniques, and how to deal with interwell communication were also highlighted. Will Shale Oil Ever Make Money? Quite Possibly Next Decade Stephen Rassenfoss, JPT Emerging Technology Senior Editor The biggest unconventional oil producers have revolutionized global oil markets and driven down prices. Still on the list of things to do: Consistently turn in strong profits. By the next decade, that is likely to change according to a report by Wood Mackenzie, which predicts margins will grow for the biggest, most efficient independents around 2020. The actual prediction is “the five leading tight-oil specialists will start to deliver significant positive free cash flow in three years’ time, based on our USD 66/bbl Brent oil price assumption for 2020.” Which would mean that five companies whose business depends on producing liquids and gas from ultratight formations—Continental, Devon, EOG, Newfield, and Pioneer—would begin generating considerably more cash than they are spending to produce far more barrels of oil per day than they are now. “They will be transitioning out of the capital-intensive phase and moving into the harvest phase” as these enormous, long-term developments reach critical mass, said Benjamin Shattuck, principal upstream analyst for Wood Mackenzie, who was part of the team that produced the recent report: When Will Tight Oil Make Money? Three Alternative Paths To Maximizing Unconventional Resources Stephen Whitfield, Senior Staff Writer As pioneering shale gas plays and tight oil formations mature and decline in production, operators are trying to find emerging formations and resources to replace them, enabling continued growth in US production. While the industry will continue identifying new domestic unconventional shale and tight sand resources, an expert said that the methods of discovery may differ from traditional approaches. At the 2017 Unconventional Resources Technology Conference, Vello Kuuskraa discussed the alternative pathways companies may take to discover unconventional resources while maximizing existing plays in the near future. Kuuskraa is president of Advanced Resources International. Kuuskraa’s presentation focused on three such pathways. He defined the first, “Looking in Your Own Backyard,” as the search for additional productive horizons in existing basins, either above or below already developed target formations. An example of such a strategy is the Meramec formation, located approximately 1,000 ft above the Cana-Woodford Shale in the northern portion of the Anadarko Basin. A Typical Well is Hard To Define Stephen Rassenfoss, JPT Emerging Technology Senior Editor A type curve is a quick way to answer a critical question—what does a typical well produce over time in a given place? On the plus side this simple calculation can be done using only basic math skills. “The conventional approach is to determine the arithmetic average of production during a given month from different wells in a reservoir of interest to create a type well,” according to SPE 178525. On the downside, the next sentence is: “This method is deeply flawed.” The flaws include “different results by different evaluators” that are “overestimates or underestimates (usually overestimates” of future production, according to the paper, whose authors include John Lee, a professor at Texas A&M University who is well known for his work on reservoir production analysis. The negatives have become all the more pronounced by the rise of unconventional oil and gas developments, where the output varies, and is unpredictable from well to well, with decline curves that do not fit conventional norms. “The problems are simply different (and usually harder to solve) in unconventionals,” Lee said. Validating the Smooth Success of HEAL System Trent Jacobs, JPT Digital Editor It has apparently taken one emerging technology to help validate another. HEAL Systems is a joint-venture with Schlumberger which manufactures a downhole flow-regulating device by the same name. The innovation promises to remedy one of the unconventional sector’s most common problems: slug flow. PipeFractionalFlow is a spinoff startup from the University of Texas at Austin that is using new theories and equations to make modeling complex multiphase more affordable. Together, the two technology developers completed a simulation and history matching study on four horizontal wells in the US and Canada that shed light on how the HEAL system works. The research is detailed in an SPE paper published at the Unconventional Resources Technology Conference (URTeC 2670789). Study Provides Guidelines for Community Input in Unconventional Development Stephen Whitfield, Senior Staff Writer A lack of community input can have a destructive impact on new unconventional energy projects, particularly in environmentally sensitive areas. However, a recent study conducted by Texas A&M University and the Houston Advanced Research Center (HARC) showed that while negative community opinion can be difficult for owners and operators to overcome, engaging in a dialogue with communities pre-development could have significant economic, social, and environmental benefits and should be a factor in any evaluation of a new project. Speaking on the second day of the Unconventional Resources Technology Conference, Clark Adams, a professor emeritus in the Wildlife and Fisheries Sciences department at Texas A&M, outlined some of the steps companies could take to address community anxieties over new energy development. These steps were explained in a paper (URTeC 2664652) written by Marian Higgins, David Burnett, Urs Kreuter, and Richard Haut.

President's column In early April, the shipping lanes along the coastlines of Newfoundland and Labrador, Canada, were quite congested, but not with tankers. This area of Canada—often called “Iceberg Alley”—was filled with 450 icebergs, floating south. This overabundance appeared suddenly; the US Coast Guard reported the increase from 37 to 450 icebergs in a week. What is the cause? Scientists disagree. Some state that rising temperatures caused by global warming triggered this massive iceberg jam. Others say that it could have been caused by a violent windstorm in St. John’s, Canada, a few weeks earlier. In either case, the “bergy water”—the term used by the Canadian Coast Guard in its ice bulletin—has officials believing that the number of icebergs this year will eclipse last year’s total of 687. Opinions regarding climate change—is it real or not—are polar opposite. There are just as many people who passionately believe it exists and needs to be slowed as those who do not believe it exists. Typically, SPE does not take positions on political or controversial matters. We are a society that disseminates technical knowledge for the upstream segment of the oil and gas industry. But this concern is so prevalent globally that last year, the SPE Board of Directors formed a climate change task force to identify “key aspects of climate change and public perceptions of climate change.” This group also was charged with developing a strategy for SPE’s response and recommending any actions that the society should take. The board also requested that recommendations developed by the task force avoid any approach that could be construed as lobbying or political advocacy, as neither is consistent with SPE’s role and status as a not-for-profit organization. The task force worked diligently for nearly a year studying climate change policies such as the Paris Agreement, which was developed at the 21st annual Conference of Parties. Population growth and economic development are driving increased need for and access to energy, so the Paris Agreement is expected to bring change over the course of this century. It has the potential to usher in new opportunities for SPE members through deploying carbon dioxide capture, use, and storage (CCUS), further accelerating natural gas as an option to coal, changing the infrastructural load as natural gas becomes an essential component of a more flexible power generation system, and pushing oil into new markets as it is displaced from some of its current uses (such as transportation).

President's column SPE presidents are asked a lot of questions, and I suppose that’s true of anyone who stands in front of an audience as an authority figure. I have learned to expect many of the same questions, no matter the audience: What will the price of oil do? When will the industry turn around? How is the industry managing post-Big Crew Change? What are you going to do to “fix” the situation of women in the industry? What is your view on climate change? But my favorite question is: What’s the Next Big Thing? As I travel around as SPE President, I see a lot of new and different technologies, operators, and ideas. But my view on the Next Big Thing has been consistent for the last few years: I believe that we are not only entering the era of universal big data, but also the era of more intelligent software to help us make better decisions. The software will help us be better engineers by preserving knowledge and improving decision making. I believe the Next Big Thing will be infinite big data and intelligent machines to interpret it. Cheaper and more robust sensors will allow us to collect data not only on expensive deepwater completions and big compressors, but also on every isolated onshore well. Cheaper computing power, universal communications, and learning algorithms will allow engineers to use and interpret those large amounts of data to manage assets more efficiently. I believe operators and service providers will be able to reduce risk by using the full value of knowledge and experience to optimize asset management. I learned to be an engineer in the analog world of the late 1970s and early 1980s. Ours was a world of hand-drawn maps and handwritten columns of figures on green engineering paper. Programmable handheld calculators replaced the slide rule. Data capture was infrequent, monthly at best, and analysis was slow and tedious. Enter the PC. I vividly remember first getting a PC at work in 1985 after I made the pitch to our district engineer to purchase an IBM PC Model XT for our six-person team. Before then, only special programs could be run on the mainframe at the faraway research center. Our group managed several Permian Basin waterfloods, and we had been doing very tedious calculations by hand. When I was pitching to the district engineer, his first question to me was “how many engineers will this PC replace?” What he didn’t see was that computational power would help the same number of engineers create better analysis and help drive better decisions. Since those ancient days of more than 30 years ago, better, faster, cheaper computing power is everywhere. We haven’t replaced engineers with PCs, but we have created new opportunities for better technical and economic evaluations. Enter the Internet. When I left ARCO in June 1994, engineers did not have email or Internet access. Three years later, I was emailing work across the Atlantic every day so that teams in Houston and London could collaborate. Now, especially for those of us in global companies, our workflows are completely dependent on instant global communications. But I believe we are only beginning to take advantage of the full potential of the globally connected computing world. The Internet, or Cloud, of Things is coming for all of us. Another question I’m often asked when I speak is: How will we manage the Big Crew Change? What will the industry do when all these people retire? How are we retaining the knowledge of all those experienced practitioners? I believe that many of my peers who are retiring or have retired as part of the Big Crew Change will continue to consult or work part-time on their own terms. But I think the greatest value will be for these experienced practitioners to help teach not just the next generation of human staff, but also the next generation of intelligent software. Their knowledge can be preserved forever in software that has learned how to duplicate, and eventually improve, their decisions.

Management Decision making in uncertain environments is key to the successful delivery of oil and gas projects. By definition, however, uncertainty is ambiguous and unpredictable. Uncertainty does not necessarily imply risk; the two are separate concepts. Economist Frank Knight made a clear distinction between the two as far back as 1921. Risk can be measured and quantified and is well suited to the analytical techniques used in project risk management; uncertainty defies quantitative expression. Items with the quality of uncertainty often surface during risk-assessment exercises but tend to be categorized as “issues” and are neither captured nor addressed by traditional risk-management processes. Donald Rumsfeld’s infamous quote highlights the difficulty of articulating uncertainty. However, the statement is rooted in sound cognitive and sociological theory and makes an important point about the perils of taking our individual and shared perceptions for reality. The philosopher Slavoj Žižek (2006) suggests that there may also be a fourth category of “unknown knowns”—those things that we intentionally refuse to acknowledge due to, for example, the social stigma around dissent. While we may feel confident dealing with “known knowns” and “known unknowns,” how can we hope to discover the “unknown unknowns” and uncover the “unknown knowns”? These problems can be effectively addressed using a Delphi-based workshop methodology. The process presented in this article discusses how to work collaboratively to develop a common understanding of a project and achieve alignment on issues and uncertainties. This allows managers to gain a better understanding of the critical uncertainties running through the project and implement appropriate strategies. Delphi Methods Delphi is a structured communication technique that was developed as part of the United States’ response to global uncertainty during the Cold War. Since then, the process has been used across many different industries worldwide (Linstone and Turoff 2002). Delphi-based methods are able to draw out the tacit knowledge held by project members and assess it in a structured manner.