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Oilman Magazine May/June 2019

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Transforming Fireproongin the Downstreamp. 44Virtual Reality as a Workforce Training Solutionp. 4Follow The Leader: Examining HowIndustry Giants Reduced OperationalCosts By Going Digital p. 22In Mineral Buying Innovation Winsp. 10THE MAGAZINE FOR LEADERS IN AMERICAN ENERGYMay / June 2019OilmanMagazine.comEXPLORATION AND PRODUCTION SOFTWARE

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Precision Mass Flow MeasurementAn ONICON BrandTHERMAL MASS FLOW METERMODEL • (831) 384-4300• Accuracy compliant BLM 3175 & API 14.10• Data Logger with 7-year history• Gas-SelectX® gas selection menus• Advanced DDC-Sensor™ technology• CAL-V™ in-situ Calibration Validation• No additional pressure or temperature compensation• Direct mass flow measurement• Low pressure dropGET A FREE

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IN THIS ISSUEFeatureOil and Gas Measurement Automationis Key in Optimizing ProductionBy Duane Harris - pages 20 & 21In Every IssueLetter from the Publisher – page 2OILMAN Contributors – page 2OILMAN Online // Retweets // Social Stream – page 3Downhole Data – page 3OILMAN ColumnsInvaluable Land Knowledge Software and AI: Sarah Skinner – page 15Downturn by Legislation: Jason Spiess – page 18Transitioning from an Outside Industry into the Oil Sector: Recent Graduates and Petroleum Engineering Education: Tonae’ Hamilton – page 23Waterless Oil Sands Extraction Process set to Improve Oil and Gas Industry Environmental Track Record: Eric Eissler – page 27Be Aware of the Modern Day Snake Oil: Jason Spiess – page 28Interview: Josh Robbins, CEO, Beachwood Marketing: Emmanuel Sullivan – page 30Improving Oil and Gas Storage and Operations Through Innovation: Tonae’ Hamilton – page 3650 Years Later: The Impact of Discovery: Mark A. Stansberry – page 43Transforming Fireproong in the Downstream: Sarah Skinner – page 44Guest ColumnsVirtual Reality as a Workforce Training Solution: Elliot Green – page 4IoT in The Oil and Gas Industry: Bill Ebanks and David Head – page 6Continuous “Hands Off ” Insulation Resistance Testing of Critical Motors: Jeff Elliott – page 8In Mineral Buying Innovation Wins: Matt Chamberlain and Ashley Gilmore – page 10Implementing Articial Gas Lift Earlier Can Improve Declining Wells: Andrew Poerschke, Teddy Mohle and Paul Ryza – page 12Digital Twin Technology Adds a New Dimension to Offshore Projects: Thornton Brewer – page 16Technological Advances Cushion Oil Crisis: Amandeep Kaur – page 19Follow The Leader: Examining How Industry Giants Reduced Operational Costs By Going Digital: Shallan Grisé – page 22Scale Sand Production with Modular Natural Gas Power: Mike Mayers and Josh Haugan – page 26Oil Markers: Useful Pricing Tools: Eugene M. Khartukov – page 32There Is More than One Way to Practice Hydraulic Fracturing: Andres Ocando – page 38DevOps Provides Digital Pipelines to Cloud Benets: Aater Suleman – page 42Oilman Magazine / May-June 2019 / OilmanMagazine.com1Precision Mass Flow MeasurementAn ONICON BrandTHERMAL MASS FLOW METERMODEL • (831) 384-4300• Accuracy compliant BLM 3175 & API 14.10• Data Logger with 7-year history• Gas-SelectX® gas selection menus• Advanced DDC-Sensor™ technology• CAL-V™ in-situ Calibration Validation• No additional pressure or temperature compensation• Direct mass flow measurement• Low pressure dropGET A FREE

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Gifford BriggsGifford Briggs joined LOGA in 2007 working closely with the Louisiana Legislature. After nearly a decade serving as LOGA’s Vice-President, Gifford was named President in 2018. Briggs rst joined LOGA (formerly LIOGA) in 1994 while attending college at LSU. He served as the Membership Coordinator and helped organize many rsts for LOGA, including the rst annual meeting, Gulf Coast Prospect & Shale Expo, and board meetings. He later moved to Atlanta to pursue a career in restaurant management. He returned to LOGA in 2007.Mark A. StansberryMark A. Stansberry, Chairman of The GTD Group, is an award-winning: author, columnist, lm and music producer, radio talk show host and 2009 Western Oklahoma Hall of Fame inductee. Stansberry has written ve energy-related books. He has been active in the oil and gas industry for over 41 years having served as CEO/President of Moore-Stansberry, Inc., and The Oklahoma Royalty Company. He is currently serving as Chairman of the Board of Regents of the Regional University System of Oklahoma, Chairman Emeritus of the Gaylord-(Boone) Pickens Museum/Oklahoma Hall of Fame Board of Directors, Lifetime Trustee of Oklahoma Christian University, and Board Emeritus of the Oklahoma Governor’s International Team. He has served on several private and public boards. He is currently Advisory Board Chairman of IngenuitE, Inc. and Advisor of Skyline Ink. Thomas G. Ciarlone, Jr.Tom is a litigation partner in the Houston ofce of Kane Russell Coleman Logan PC, where he serves as the head of the rm’s energy practice group. Tom is also the host of a weekly podcast on legal news and develop-ments in the oil-and-gas industry, available at, and a video series on effective legal writing, available at SpiessJason Spiess is an award winning journalist, talk show host, publisher and executive producer. Spiess has worked in both the radio and print industry for over 20 years. All but three years of his professional experience, Spiess was involved in the overall operations of the business as a principal partner. Spiess is a North Dakota native, Fargo North Alumni and graduate of North Dakota State University. Spiess moved to the oil patch in 2012 living and operating a food truck in the parking lot of Macís Hardware. In addition to running a food truck, Spiess hosted a daily energy lifestyle radio show from the Rolling Stove food truck. The show was one-of-a-kind in the Bakken oil elds with diverse guest ranging from U.S. Senator Mike Enzi (WY) to the traveling roadside merchant selling ags to the local high school football coach talking about this week’s big game.Joshua RobbinsJosh Robbins is currently the Chief Executive Ofcer of Beachwood Marketing. He has consulted and provided solutions for several industries, however the majority of his consulting solutions have been in manufacturing, energy and oil and gas. Mr. Robbins has over 15 years of excellent project leadership in business development and is experienced in all aspects of oil and gas acquisitions and divestitures. He has extensive business relationships with a demonstrated ability to conduct executive level negotiations. He has developed sustainable solutions, successfully marketing oil and natural gas properties cost effectively and efciently.Steve BurnettSteve Burnett has been working in the oil industry since the age of 16. He started out working construction on a pipeline crew and after retirement, nishes his career as a Pipeline Safety Compliance Inspector. He has a degree in art and watched oil and art collide in his career to form the “Crude Oil Calendars.” He also taught in the same two elds and believes that while technology has advanced, the valuable people at the core of the industry and the attributes they encompass, remain the same. Not many of us would have guessed the deal of the quarter that blasted the energy headlines last month. Chevron announced that it was acquiring Anadarko for $33 billion in cash and stock or $65 per share. The merger places Chevron in a signicant position with a wide corridor of acreage in the Permian. Since the blockbuster deal was announced, industry analyst believe more M&A activity is coming. More so with companies that are considered Permian pure-plays like Pioneer and Concho. According to oil and gas experts, companies that primarily operate in the Permian and then merge have the best potential to integrate their acreage position. Occidental also bid for Anadarko at $70 per share and was caught off guard that they struck a deal with Chevron. In the past 12 months there has also been a string of O&G software and technology acquisitions. First off, Drillinginfo went on a buying spree purchasing a long list of established software compa-nies to complement its existing suite of upstream products. To name a few, they purchased: Oildex, MineralSoft, Cortex, 1Derrick, Midland Map Co and PLS. Most of the acquisitions occurred after the private equity rm Genstar Capital completed the purchase of Drillinginfo Holdings. After Quorum Software was acquired by private equity rm Thoma Bravo, the fullstream software provider then acquired Coastal Flow Measurement and its subsidiary Flow-Cal, a producer of gas and liquid mea-surement software. Oil and gas accounting solutions company Wolfpack Software acquired LandPro Corp in March of this year. P2 Energy Solutions, another E&P software provider acquired iLand-Man, a SaaS-based land management platform. Watereld Energy Software, a Tulsa-based oil and gas software provider with a focus on the midstream and downstream markets, acquired NeoFirma, a cloud-based eld operations platform that is geared toward independent oil and gas companies.There has been a lot of M&A activity recently and it will be exciting to see in the months ahead as segments of the industry continue to consolidate and adapt to a digital oileld with a goal of improving operation, market share and personnel performance. MAY — JUNE 2019PUBLISHER Emmanuel SullivanMANAGING EDITOR Sarah SkinnerASSOCIATE EDITOR Tonae’ HamiltonFEATURES EDITOR Eric EisslerGRAPHIC DESIGNER Kim FischerCONTRIBUTING EDITORS Gifford Briggs Steve Burnett Thomas Ciarlone, Jr. Joshua Robbins Jason Spiess Mark StansberrySALES Eric FreerTo subscribe to Oilman Magazine, please visit our website, The contents of this publication are copyright 2019 by Oilman Magazine, LLC, with all rights restricted. Any reproduction or use of content without written consent of Oilman Magazine, LLC is strictly prohibited.All information in this publication is gathered from sources considered to be reliable, but the accuracy of the information cannot be guaranteed. Oilman Magazine reserves the right to edit all contributed articles. Editorial content does not necessarily reflect the opinions of the publisher. Any advice given in editorial content or advertisements should be considered information only.CHANGE OF ADDRESS Please send address change to Oilman Magazine P.O. Box 771872 Houston, TX 77215 (800) 562-2340LETTER FROM THE PUBLISHERCONTRIBUTORS — BiographiesOilman Magazine / May-June 2019 / OilmanMagazine.com2Emmanuel Sullivan, Publisher, OILMAN Magazine

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Oilman Magazine / May-June 2019 / OilmanMagazine.com33Week Ending April 26, 2019DIGITAL DOWNHOLE DATAColorado: 32Last month: 30Last year: 28 North Dakota: 58Last month: 60Last year: 55 Texas: 491Last month: 491Last year: 513 Louisiana: 62Last month: 65Last year: 60 Oklahoma: 102Last month: 108Last year: 129 U.S. Total: 991Last month: 1,006Last year: 1,021OIL RIG COUNTS*Source: Baker HughesBrent Crude: $70.71Last month: $67.51Last year: $68.81 WTI: $65.66Last month: $59.87Last year: $65.49CRUDE OIL PRICES*Source: U.S. Energy Information Association (EIA)Per BarrelColorado: 15,504,000Last month: 15,904,000Last year: 13,511,000 North Dakota: 42,668,000Last month: 42,391,000Last year: 35,902,000 Texas: 149,786,000Last month: 151,783,000Last year: 120,708,000Louisiana: 3,706,000Last month: 3,795,000Last year: 3,778,000Oklahoma: 17,968,000Last month: 18,113,000Last year: 16,434,000 U.S. Total: 367,993,000Last month: 370,792,000Last year: 309,831,000CRUDE OIL PRODUCTION*Source: U.S. Energy Information Association (EIA) – January 2019 Barrels Per MonthColorado: 165,265Last month: 166,118Last year: 150,695 North Dakota: 71,834Last month: 69,792Last year: 55,403 Texas: 715,337Last month: 716,176Last year: 609,451Louisiana: 254,571Last month: 248,381Last year: 210,425 Oklahoma: 261,193Last month: 265,546Last year: 227,286 U.S. Total: 2,950,748Last month: 2,955,447Last year: 2,586,405NATURAL GASMARKETED PRODUCTION*Source: U.S. Energy Information Association (EIA) – January 2019Million Cubic Feet Per MonthConnect with OILMAN anytime at and on social media RETWEETS@OilmanMagazine#OilmanNEWSStay updated between issues with weekly reports delivered online at SOCIAL

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Oilman Magazine / May-June 2019 / OilmanMagazine.com4Virtual Reality as a Workforce Training SolutionBy Elliot GreenVirtual Reality (VR) has been the most anticipated upcoming technology for the past three years. However, in these past three years it has been slow to deliver on the large promises made. VR was expected to revolutionize the way that industry worked from training to day-to-day operations. While it has taken longer than everyone expected, that promise is now becoming a new reality for many industries.History Virtual Reality burst into the mainstream lexicon in 2015. By March 28, 2016 Oculus Rift had launched their rst headset with the HTC-Vive arriving at developer’s front doors the following month. The Oculus Rift and HTC-Vive were being touted as the very next big step for the VR industry. By October of that same year, Sony PlayStation released their VR headset. With this, VR had ofcially hit mainstream commerce and was now readily available to both developers and consumers. Computers took a performance step forward and prices of hardware fell. Nvidia graphics cards became hugely powerful and, with this, VR was now everywhere. By 2017, VR was on every trade show booth, in every marketing pitch and presentation, and it looked like it was here to stay. But then nothing; the technology stagnated. Customers didn’t appear, the adoption and sales gures of VR headsets were notoriously buried and by early 2018 it looked like maybe we had all just repeated the 3D TV fade, but things were about to change. Present In early 2019 the tide has started to shift. Developers had been through a period of learning and customers had a moment to digest the technology. A new realm of partnerships between industry and developers is starting to form which included exciting, valuable, useful and cost saving solutions. One of those solutions is in pre-construction plant inspections. By taking the original CAD draft drawings and putting them into a VR environment, the plant team are, within minutes, able to be virtually in that plant, looking for colliding pipes and structures, adjusting valve positions, looking for efciencies and avoiding costly redraws and new component manufacture. This in itself is a new frontier for the industry. Shell has taken this approach with their Vito platform. For the rst time in history, while the platform is still in construction over one-thousand miles away in Singapore, the rig is being virtually explored by its future crews who are stationed in Louisiana. This process is not only saving the company time and money but ultimately the lives of their staff as they are now better equipped to manage their assigned rigs even before they rst step foot onto them. Training is a second application that has been quick to employ the virtues of VR. The fully immersive environment provides higher retention rates, as high as 90 percent when re-tested after OILMAN COLUMNA Real user ghting a Virtual reThe view from a supply vessel during VR Rigger training Internal, intelligent Riggers provide Articial Intelligence real time directional signals to VR Crane operators

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Oilman Magazine / May-June 2019 / OilmanMagazine.com5SEAL OF | 800.256.8977 | esales@oilcenter.comQUALITY THROUGH RESEARCHENVIRONMENTALLY FRIENDLY PRODUCTSSPECIALTY GREASES & OILSCLEANERS & DEGREASERSTHREAD COMPOUNDSWIRELINE PRODUCTSVALVE PRODUCTSPIPE COATINGSOIL CENTERRESEARCH LLCOILMAN COLUMNone month, compared to regular class teaching, and engages a new generation providing the training team with the ability to measure and score everyone on the same standard. Variables such as classroom location and experience of training staff are no longer factors for training success. South Louisiana Community Colleges’ Oil and Gas teaching department recently introduced their rst educational piece of VR specically designed to educate the future workforce on what a typical Permian basin rig may look like. The students are able to explore the entire rig from mud pits through to the crows nest in each area having to identify the different working elements of the noisy, dirty rig. VR Crane training simulators are now small enough and powerful enough to match and better the more traditional large-scale trailer or static systems. The VR simulators can be packed up, moved and set up with no more space than a desk and chair. The simulators have real world physics applications. They include sensors for measuring the trainee inputs and include scenarios that are either A) too dangerous to recreate in a traditional training or B) they are testing for situational awareness. All of this computer-based training is unbiased, measurable, portable and scalable. FutureThe industry will ultimately dictate where this technology is best utilized. But, in a period of time where every expenditure is being assessed and efciencies looked for, there are already discussion about placing VR systems on offshore platforms to provide refresher training during rotation. Com-panies are identifying opportunities to take mobile systems into the Permian Basin to provide multi program centers. The centers would be capable of acting as a VR Crane simulator in the morning and VR Incipient Fire training in the afternoon and VR Hazard awareness in the late afternoon. The exibility of this technology is unmatched and the boundaries are still being tested. Training companies, designers, HSE, and labor agencies are all going to have the ability to identify costs savings, improved worker engagement and practical applications where a VR solution would improve their business, performance and bottom line. Conclusion The future is bright - developers have overcome the initial challenges, hardware is accessible, the quality is excellent and the solutions being created have a strong demand across a wide variety of platforms. Virtual Reality is here now and is going to be used across the industries at every level. Elliot Green is the Founder of TANTRUM Lab a Virtual Reality software training company based in Lafayette, Louisiana. He has been creating VR experiences for clients since late 2015. His team has developed a unique approach to VR training incorporating wherever possible real-world physical objects. Elliot is a seasoned developer of cutting-edge technology, having previously worked for Nokia creating some of the very rst Aug-mented Reality experiences as well as multiple consumer-focused technology expos. The VR Fire ghters view while practicing the PASS technique

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Oilman Magazine / May-June 2019 / OilmanMagazine.com6IoT in The Oil and Gas IndustryBy Bill Ebanks and David Head The oil and gas industry faces technical challenges unique to its business, with hundreds of thousands of onshore and offshore wells distributed over wide geographic areas and thousands of miles of pipelines requiring continuous monitoring, periodic maintenance, and constant connectivity to ensure safety and optimized performance. As new, Internet-enabled technologies emerge to help address the operating challenges in these environments, companies must consider carefully the emerging risk of signicant cybersecurity breaches in order to avoid or minimize the monetary, reputational, and operational damage from such intrusions. While additional computational and networking capabilities will drastically change how businesses operate in the future, the tradeoffs inherent in deploying such technology must also be kept in mind.The connectivity of all of our myriad devices, known as the IoT, has advanced dramatically for corporations and households alike. Micro-sized devices, heavily equipped with electronic and networking components, are increasingly becoming embedded into our working and personal lives. While the consumer implications are broad and increasingly visible, businesses are also improving their processes with increased automation and advanced analytics that take advantage of concepts such as predictive maintenance or near-real time monitoring of infrastructure. As we move from early adoption into general acceptance, the number of IoT devices continues to grow at an exponential rate. Only three years ago, there were 15.41 billion IoT devices connected worldwide; now however, according to Statista, the 23.14 billion devices installed in 2018 will grow to more than 75 billion by 2025. There is little debate over the benets that can be realized by using these devices. However, corporations often overlook critical security considerations when deploying new, cutting-edge technologies, and IoT devices are no exception. The importance of considering security implications may not always be clear in the initial deployment of such technologies, particularly when executives are focused on the opportunity to reduce costs and increase their bottom line.Growth in IoT DevicesLacking security-related analysis, a breach on a connected device could allow hackers to steal data, disrupt operations, and impact production. Seasoned adversaries will often seek entry on an unsecured connected device in order to expand their access to sensitive databases and le structures in other locations. Popular IoT device developers claim that the security protocols that their hardware utilizes are fully secure and, in some instances, “future proof.” In reality, without adequate security practices in place to support their use, these devices may actually be easy to compromise, as demonstrated by the SANS Institute1. As a result, it is likely that many organizations have not adequately quantied the risk resulting from their growing reliance on IoT devices. Data breaches are in the news far too often, and companies are suffering major impacts to their stock value, reputation, or operating earnings as a result. These impacts are particularly acute in industries that require an always-on, always-functioning infrastructure, where any disruption can cost hundreds of thousands, if not millions, of dollars per incident. In the news, we have seen examples of attacks focused on shutting down connected devices. TSMC (Taiwan Semiconductor Manufacturing Company), the world’s largest manufacturer of semiconductors, was forced to take multiple plants ofine in order to recover from an attack.2 Saudi Aramco, one of the world’s largest oil companies, suffered one of the largest hacks in history in 2012. The hack originated on a single computer that was connected to their larger IT infrastructure, wreaking havoc throughout the network. As a result of the breach, Saudi Aramco was forced to take a number of their operations ofine and had to resort to the manual handling of supplies, shipping and contracts with governments and business partners. Approximately 35,000 computers were affected, forcing the company to give oil away for free, in some cases, to avoid disruption in distribution.3 This leads to an interesting challenge in the oil and gas industry, where companies will be keen to harness the signicant benets that IoT devices bring but must simultaneously work to protect their infrastructure from the expanded attack surface presented by the same devices. For example, within the past few years, upstream and downstream oil and gas companies have seen an evolution in the technology available to monitor and automate operations. Companies are implementing this new technology to reduce NPT (non-productive time) by integrating information and operational technology to speed up processing time, to enable predictive maintenance, and to reduce frequency of disruptive incidents. Additionally, to prevent/minimize disruption, companies typically supplement manual inspections with PLCs (programmable logic controllers) to control valves and satellite connections to remotely monitor equipment – greatly improving overall operating efciency. While the operational benets from such initiatives are easy to measure and report, the risks of inadequately protecting this expanded attack surface are not often considered fully – raising the specter of operational disruption and loss of key assets. Operational disruption is not the only risk posed by insecure devices. As the energy industry is already heavily regulated, additional nes and repercussions are likely to be explored by OILMAN COLUMNSource: Statista

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Oilman Magazine / May-June 2019 / OilmanMagazine.com7OILMAN COLUMNregulators concerned about the systemic risk of a vulnerable infrastructure. The NERC CIP (North American Electric Reliability Corporation Critical Infrastructure Protection) protocol provides a set of requirements designed to better secure the assets that operate North America’s bulk electric system. The protocol also stipulates the need for robust cyber capabilities to protect, detect, and recover all critical systems. Similarly, purchasing cyber insurance, while somewhat benecial, is not a one-stop shop for mitigating nes and prot loss resulting from a cyber breach because residual mitigation and recovery efforts can continue to incur costs. And how do you quantify the potential, ongoing reputational and brand impact of such an incident?Now the question becomes, what can organizations do to mitigate the risk stemming from this growing reliance on IoT devices? As technological capabilities evolve to more fully automated monitoring of operating conditions and to more advanced analytics and machine learning capabilities, security programs must also mature and enforce the concept of “security by design.” That is, IoT devices supporting communication and storage should have appropriate security layers in place. Sensitive data must be segmented from less secure networks, and any transmission of data over any network should be end-to-end encrypted. Security can’t be locked into the rmware, future-proong requires upgradeable measures to address currently inconceivable new threats. Additionally, ongoing, real-time monitoring and automated incident alerting on IoT devices can enable timely response to any suspected compromise. Proper security testing, mimicking real-world scenarios, must include assurances that IoT devices and their supporting infrastructure are regularly scanned for vulnerabilities and upgraded when necessary. All these defensive measures need to be dened and documented, while driven by a security policy that aligns to both business and security objectives of the organization. What You Need to Know• While the use of IoT devices within industry are growing exponentially, for all the cost cutting and strategic benets they provide, these devices, and their connections to the internet, are not inherently secure.• A breach of a connected device has the potential for exponential damage as the impact traverses industrial and IT systems to which it connects.• The solution is to plan ahead, to consider security throughout the design, and to monitor in real time (security-by-design and defense-in-depth).• New cyber laws and regulations are being implemented on a continual basis. Bill Ebanks is a managing director in the Energy Practice and David Head is a managing director in the Digital Practice at AlixPartners, the global consulting rm. 1 – In order to demonstrate the importance of proper security testing and design, SANS developed a series of straightforward exercises to demonstrate the relative ease of compromising a device leveraging the Thread protocol, a common IoT me-dium. SANS []2 – ZDNet []3 – CNN []LONG-TIMERELIABLE A-T CONTROLSTRUNNIONMOUNTEDBALL VALVES9955 International Blvd. Cincinnati, OH 45246 (513) 247-5465 www.atcontrols.comin stock

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Virtual Reality as a Workforce Training Solution In Mineral Buying Innovation Wins p 4 p 10 Follow The Leader Examining How Industry Giants Reduced Operational Costs By Going Digital p 22 Transforming Fireproofing in the Downstream p 44 THE MAGAZINE FOR LEADERS IN AMERICAN ENERGY May June 2019 OilmanMagazine com EXPLORATION AND PRODUCTION SOFTWARE

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Precision Mass Flow Measurement An ONICON Brand MODEL FT4X THERMAL MASS FLOW METER Accuracy compliant BLM 3175 API 14 10 Data Logger with 7 year history Gas SelectX gas selection menus Advanced DDC Sensor technology CAL V in situ Calibration Validation No additional pressure or temperature compensation Direct mass flow measurement Low pressure drop GET A FREE QUOTE foxthermal com quote sales foxthermal com 831 384 4300

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Oilman Magazine / May-June 2019 / OilmanMagazine.com10In Mineral Buying Innovation WinsBy Matt Chamberlain and Ashley GilmoreMineral buyers want to be special. Unfortunately, most know that aside from the strength of their network there isn’t a lot to differentiate one group from the next. That, of course, doesn’t stop them from trying.Nearly every mineral buyer has an obligatory website offering “fast and fair offers” telling potential sellers that they will give them more for their minerals than the other guy. They battle for inbound leads, focus on creating sleeker websites, tweak keywords to perfection and spend on geo-targeted digital advertising. In the end, there is no denable special sauce separating one from the next.The more ambitious and well-funded invest heavily in hiring the most talented negotiators and researchers in an attempt to drum up leads in targeted AOI (areas of interest). Others focus on developing proprietary software solutions. Although very intelligent land professionals help create these, land professionals are not developers and the solutions are usually customized Excel spreadsheets.So, while mineral buyers want to be unique, most of them act on very similar principles - “fast, fair offers with a focus on integrity.” Are they better negotiators and researchers? Maybe. Does this provide a substantial advantage? Most likely not. Do they have access to public data that no one else does? Obviously no, most often leads come from tax rolls, lease records, forced pooling agreements, company reports or other similar publicly available data. In a market where everyone is selling themselves the same way and using the same data, the only way to gain a meaningful advantage is to innovate in ways others are not. Those who fail to adopt new technologies and reimagine processes will tread water and eventually fall behind. The mineral buyers that uncover and implement solutions to quickly and accurately process reams of mineral ownership data will win by a landslide.How Can a Mineral Buyer Truly Gain an Edge?A good option is “buying in front of the bit,” or attempting to buy in front of operators. E&Ps do this all the time to improve NRI (net revenue interest), diversify their portfolio and become more resilient to market swings. If a mineral buyer wants to buy in front of a drill bit they don’t own they have four options: 1. Partner with an operator and agree on cost + fee per acre2. Predict the future3. Get lucky4. Leverage inside informationPartnering is the only option proven to work consistently enough to bank on, while the others can be considered gambling, illegal or both. Getting lucky is only a plan for fools and we’ll leave inside information to the sharks. In order to partner, a mineral buyer must rst nd a company willing to trust them with their sensitive information. If they do, partnering is a safe, risk-averse bet for those who are content with small wins and limited upside. But the oil and gas industry, with its rich history of wildcatters and tycoons, has never been a place for those looking to win small. This leaves mineral buyers with a single option - predicting the future which, if you squint, looks very similar to getting lucky. Blanket Title as a Mineral Buying StrategyOver the last decade, data companies have started offering tools that make it possible to predict future production with impressive accuracy. For example, DrillingInfo gives clients access to leasing trends and rig movements to determine where an operator will drill next. When this data rst became easily accessible it gave users an edge, but today nearly everyone uses DrillingInfo and, as a result, everyone can make the same predictions. When everyone uses the same data services, custom spreadsheets, and CRMs, it is no longer an advantage, it is the minimum requirement to stay competitive. Predicting the future only has value if a company is able to execute on it before someone else. Answers make you smart, actions get things done, but neither hold much value without the other.The Need For “Actionable Intelligence”Prices can soar overnight when an operator takes a lease, beginning a rush to gain position. The rush forces buyers to cut corners by sacricing speed and accuracy to close transactions. In the end, success in this environment relies heavily on luck and brute force. Mineral buyers must nd a way to accurately value a mineral owner’s assets fast enough to take action while competition is limited. Running out title conventionally can cost thousands of dollars for a single owner. Current economics dictate that in order to invest capital into conrming ownership OILMAN COLUMN

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Oilman Magazine / May-June 2019 / OilmanMagazine.com11Automated Pile CuttersImproved Occupational Safety – IAI Cutters are excavator attachments that are operated from the cabin, so there are no risks of falling piles, dust or HAVS issues.Excellent Quality Cuts – Compared to manual cutting, IAI Cutters oer even ve times higher productivity. Cutting results are predictable and cut-os can be reused. IAI Concrete Pile Cutters & Steel Pile CutterIAI Pile Cutterfor concrete pilesIAI Plasma Cutterfor steel piles and pipesQ-350Up to 350mm (14”)Q-400Up to 400mm (16”)Q-350SFull cut up to 350mm (14”)Q-500SFull cut up to 500mm (20”)P-400Steel piles and pipes Up to 400mm (16”)1-877-219-1962 www.iai-usa.comOILMAN COLUMNmineral owners rst must commit to selling by signing a LOI (letter of intent). Without a commitment, it is cost prohibitive to prerun title. When capital is deployed to research a single lead, a company is essentially placing a binary bet with limited upside. The Agrarian Age for Mineral BuyersThe approach to date resembles a hunter/gatherer mentality. To survive requires being opportunistic, adaptable and expertly skilled. The best have been able to survive and even thrive, but even then, outdated tools and a resource intensive approach limit the size and stability of the opportunities. Just as early humans transitioned from “hunter/gatherers” to farmers in the Agrarian Age, mineral buyers need to evolve and begin “farming” opportunities. Systematically running blanket title is the way to accomplish this.Blanket title generates a list of all current mineral owners for an AOI with pre-conrmed interest calculations. Mineral buyers taking this approach acquire actionable intelligence that allows them to bypass the step of signing an LOI. Offers can be sent out en masse and close rates skyrocket when an owner is approached with a deed and a check they can sign and cash on the spot. There are two ways to run blanket title. The rst is reactively by waiting for a potential seller, getting an LOI signed and then running out all of the names and owners in the same tract, section, or AOI, rather than just the single signed owner. The second is to proactively run an area of interest (AOI) to identify all owners before having a potential seller. Using Title Management Platforms to WinToday, successful mineral buyers know “where” they want to buy, the winners of the next half decade will be the fastest to nd the “who.” Title Management Platforms (TMP) like Tracts, use common title to identify all leads surrounding the initial target. Features like automatic interest calculation eliminate math while document interpretation libraries store deed interpretations for repeated use. Hungry, young, PE backed mineral buyers are entering the space and building their processes using a technology rst strategy. By removing the most time-consuming steps involved in title research they are able to run entire sections for what it used to cost to run out a single name. As these companies continue to adjust, auto calculation of interest and interpretation libraries are turning one lead into 20 and cutting required investment into a fraction of what they have been historically. Leveraging TMPs is providing immediate returns, exponentially increasing upside while vastly reducing the opportunity for a complete loss. Today TMPs offer a massive competitive advantage for those early to adopt, soon they will be a requirement just to stay competitive. We’ve seen this story before.Matt Chamberlain is VP of Growth at Tracts having lead efforts in business development, client relations and strategic planning. He has a breadth of experience bringing new technology and processes to the energy sector and environmental industries. Ashley Gilmore is CEO and co-founder of Tracts where he applies an extensive background in launching and managing startup companies. Drawing on a deep knowledge of land title law and information technology, Gilmore pioneered a new approach to title processing in the oil & gas industry. Gilmore has been awarded numerous patents for title processing and visualization technologies. For more information, please visit

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Oilman Magazine / May-June 2019 / OilmanMagazine.com12OILMAN COLUMNImplementing Artificial Gas Lift Earlier Can Improve Declining Wells How an innovative approach regarding the optimum time to implement articial gas lift has signicantly improved production as wells decline – beginning on day oneBy Andrew Poerschke, Teddy Mohle and Paul RyzaEven after the prep work is nished and product recovery has been initiated, there is still no surere way for oileld exploration and production companies to condently know how much and for how long their wells will produce recoverable oil and natural gas. There’s a simple reason for that: no two wells, even if they are located yards from each other, possess the same production and life cycle characteristics. While this uncertainty can be frustrating for oileld operators who must show their investors what their capital investment is actually buying them, it does create some opportunities. Namely, the opportunity for oileld engineers to employ outside-the-box thinking when identifying ways to atten each well’s inevitable decline curve, which will result in predictable production rates and higher monetary returns over a longer period of time.Surveying the FieldA United States-based energy company operates wells in Texas’ Permian Basin, specically Pecos County in the Southern Delaware Basin’s Wolf-camp A and Wolfcamp B formations. Most of the drilling sites are horizontally fractured wells with depths between 9,500 and 10,500 feet with FBHP (owing bottom-hole pressures) from 5,000 to 6,000 psi. On average, each well has 50 fracking stages and requires 2,250-2,500 pounds of sand per foot and 60-80 barrels of water per foot. The wells generally have strong bottom-hole pressures, but fail to ow naturally for an extended period of time. This means that they will require some form of ow-optimizing articial lift earlier in their operational window. For example, the characteristics of Southern Delaware wells are such that they may only ow for 90 to 120 days before needing articial lift, while wells located a handful of miles away may ow for more than two years before requiring intervention.The most effective articial lift system in this area has been one that features an ESP (electrical submersible pump) installed in the well. However, this approach can be problematic for three reasons:• Remote areas of West Texas do not always have access to reliable electricity.o If power is not readily available, building out a power grid can cost millions of dollars.• Alternative high-volume lifts that require a natural gas generator to convert natural gas into electricity can be rented, but this adds signicant cost to the bottom line of the operator’s LOE (Lease Operating Expenses).• Other forms of articial lift can have upfront costs of 10 to 20 times more than a set of gas lift valves.For a potential solution, the producer reached out to Apergy, a leading provider of articial lift technologies, to help oil and gas production companies optimize their returns safely and efciently. The main request was a challenging one: Draw as much oil and natural gas out of the well as possible in the rst 90 days of operation, while reducing LOE over the well’s production life cycle.Seeing is BelievingThe client was not averse to using costly alternative lifts if reaching the goal of maximized production rates could be realized, but Apergy’s oileld engineers knew there had to be a more cost-effective way to attack the problem. So, they developed a four-pronged approach to introducing gas lift to a series of 10 Wolfcamp A and B wells.The trial involved introducing to the wells at four specic points during their lifetimes a gas lift system that featured annular gas injection:• Option A: Well ows for 90 days before Annular Gas Lift is installed.• Option B: Well ows for 15-45 days before Annular Gas Lift is installed.• Option C: Annular Gas Lift is installed on the rst day the well begins owing.• Option D: Annular Gas Lift is installed on the rst day the well begins owing, while injecting gas in the rst few days of production.Well No. 1 Well No. 2

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Oilman Magazine / May-June 2019 / OilmanMagazine.com13OILMAN COLUMNThe rst two options were not a radical departure from accepted norms. Options C and D, on the other hand, are solutions that few production companies will consciously choose to implement.Let’s take a look at the performance of the 10 individual wells that were tested, one well with Option A, the next three with Option B, three with Option C and the nal three with Option D (the production graphs for all wells are not shown because of space constraints):Well No. 1 began producing in February 2017, but by the end of April was beginning to experience daily production declines, though water-recovery rates remained steady. Staying on the existing course could mean an early death for the well, but when Annular Gas Lift was installed at the 90-day mark, the production curve bumped up and remained steady, save for some small peaks and valleys, through June 2018. Well Nos. 2 and 3 were a similar story to Well No. 1: strong early production that tapered off before the 90-day mark, when Annular Gas Lift was installed, which stabilized production. Annular No w Av A i l A b l e: Th e Cr u d e li f e Cl o T h i N gw w w.s h i r T s i C l e.C o m/T h e C r u d e l i f eWell No. 3Well No. 7Well No. 5Well No. 8Continued on next page...

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Oilman Magazine / May-June 2019 / OilmanMagazine.com14OILMAN COLUMNGas Lift valves were installed after only 15-45 days of operation. The result was a more gradual decline in production rates over the following months of operation. In fact, the wells’ returns beat the engineer’s forecast by such a wide margin that they were used as an example shown to investors of how ROI could improve with this well setup.The wells using Option C were the results the engineers were really anxious to see since the setup – the Annular Gas Lift application deployed from the rst day of the wells’ operation – was a departure from accepted norms. All three wells began operating in 2018 and the results have been similar – strong production rates from day one that have continued with only small valleys experienced. If there has been one standout performer, it has been Well No. 7, which showed an absolutely negligible decline curve over its rst three months of operation.The last wells had Annular Gas Lift valves installed with injected gas within the rst few days of owing. The return has been so impressive, the decline curve so negligible and the LOE so optimized that the operator has decided to treat all future wells in the Southern Delaware Basin in this fashion.Several takeaways can be analyzed when considering how these wells performed based on the four different gas lift setups:• Adding a velocity string during owback reduced slugging and outproduced casing ow.• Switching from Annular Gas Lift to Conventional Gas Lift did not improve production at 2,500 b/d total uids. • When the injection gas was turned off after the rst 90 days, the wells loaded up immediately.• Production results compared to other forms of high-volume lift were similar and, in some cases, surpassed due to lack of downtime, but at a fraction of the cost.ConclusionIn an industry like oil and gas exploration and production that features so many well-to-well variables that must be considered when deter-mining the best way to produce the well, there is simply no one-size-ts-all solution. While many companies continue to rely on alternative high-volume lifts – or wait to introduce articial lift systems until the last moment before the well loads up – forward-thinking companies are nd-ing that there are some noteworthy alternatives available. Based on the empirical information noted above, one of the more successful ap-proaches is intentionally installing an articial lift system earlier in the well’s life, up to and includ-ing the rst day of operation, with the results so far speaking for themselves.Andrew Poerschke is the Regional Operations Manager for Apergy, Houston, TX, and can be reached at, while Teddy Mohle is a Lead Completions Engineer and Paul Ryza a Senior Production Engineer. Apergy (formerly Dover Articial Lift) is a leading provider of highly engineered technologies that help companies drill for and produce oil and gas efciently and safely around the world. Apergy’s products include a full range of equipment essential to efcient functioning throughout the life cycle of a well – from drilling to completion to production. For more information, please visit SUBSCRIBE TODAY!Get the Oil & Gas news and data you need in a magazine you’ll be proud to read. To subscribe, complete a quick form Questions? Call or email • (800) 562-2340 Ex. 5

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Oilman Magazine / May-June 2019 / OilmanMagazine.com15Land management is a crucial link in the upstream management chain because the health of every exploration and production organization depends on it. Landmen must move quickly during lease-acquisition phases if they want to secure the best leases in prime exploration areas. Traditionally, this process was slow and tedious, but because of technological advances and AI, it no longer has to be that way. Time is money. The work of a traditional landman is extremely labor intensive – physically and mentally. The amount of time and work put into land acquisitions and everything that goes along with it is major time and man-hours are expensive. Just think if E&P companies could manage their assets and streamline the processes of the land life cycle, giving them the ability to use technology to maximize efciency and the advantage in an ever-evolving oil market.P2 Energy Solutions P2 is offering just that. They are the world’s largest software and technology company dedicated to the upstream oil and gas industry, with solutions spanning the entire value chain from exploration to decommissioning. More than 1,500 companies use P2 products and services daily to improve decision-making, gain clarity into complex workow scenarios, and optimize upstream efciency. History of TobinFounded in 1928 in San Antonio, Texas, by Edgar G. Tobin, the company began capturing and interpreting aerial photography to create detailed maps for the burgeoning Texas oil industry. By 1930 the company had already mapped over 3,000 miles of pipelines and numerous elds including projects in Mexico and Venezuela.Tobin quickly established itself as the industry leader in spatial information management in the United States and has set signicant milestones ever since. Acquired by P2 Energy Solutions in 2004, Tobin was and remains a trusted source for mapping and geo-spatial data services for oil and gas producers.With Tobin’s dedicated specialists, who have over 850 years of combined experience and a history of pinpoint accuracy, Tobin gives their customers the condence to make decisions that impact their company’s success. Fast, quality data delivery and user-friendly design lets oil and gas producers see well, lease, and land activity with complete clarity.“Tobin has established a solid foundation of trust over 90 years and as part of P2 we continue to build the future with our customers,” said J. Scott Lockhart, CEO of P2 Energy Solutions. “We are bringing new insights through machine learning, visualization, advanced analytics, and value-added solutions to meet the needs of the industry for the next century and beyond. We are just getting started.”Tobin Data LayersThrough Tobin Data, companies can obtain well, lease and land activity quickly and with pinpoint accuracy. Tobin data covers several layers. The Survey layer offers the most comprehensive, continuous survey coverage in the industry, covering 1.4 billion acres, 65,000 townships and 300,000 original Texas abstracts. Within the survey layer, there are two types of grids. The Jeffersonian Land Grid is used in 30 states across the U.S., including states in the Rocky Mountain region – home to many of today’s hottest shale plays like the Bakken and Niobrara.The Texas Land Survey Grid being the most accurate base available due to Tobin. It ensures that every line is veried digitally and visually. No matter where the work is taking place, every line of the map is remarkably accurate and aligned. The Ownership layer allows companies to see who owns the surface rights for each particular parcel of land, giving them the detail needed to position their lease outlines and manage property assets. This eliminates the need to go to the courthouse to obtain any of this information. More than 200 counties are tracked, including 180 counties throughout Texas, Louisiana, Mississippi, New Mexico, Pennsylvania and Ohio. It also provides ownership data in 42 Oklahoma counties, two Utah counties and two New York counties. The Polygons calculate totals, volume, acreage and distance geographically with Tobin Data sets. The Lease layer enables companies to see where competitors are leasing across the U.S. before leases expire. The interactive data shows critical insight into the mineral lease landscape enabling better business decisions. This ensures that companies can compete condently in the hottest shale plays. Information can be obtained on 750,000 leases in more than 250 counties across the U.S. with coverage being constantly expanded by the day. Lease activity points are published on a nightly basis. All of the data is collected in person from the courthouse daily so companies can have condence that they are receiving the most accurate and current data available. The Well layer provides all the access companies need on oil and gas permits, completions, and plugs. It uses purpose-built accuracy software and a multitude of data sources, including high-resolution imagery, to hand-verify each well location. The well locations are digitized using a variety of sources by their expert geospatial mapping specialists. Locations are veried and adjusted using an array of mapping platforms, such as satellite imagery, digital ortho-rectied aerial imagery, GPS coordinates, well plats, line-calls from survey or public land grid systems and USGS topographic quads. Each well is digitized to specic criteria and hierarchies, and specialist then determine which digitizing platform best suits locating and mapping the well. Each location is supplemented by including a number of critical well attributes, such as well operator, lease, and product.There are several risks associated with using free or low-cost location data. • Changing plans at the last minute for a well pad because your map data is off. Or worse: placing a well pad in the wrong spot.• Learning that the neighboring wells are closer or further than you expected.• Being forced to terminate a well on somebody else’s property.• Drilling or starting production even though neighboring wells are not producing.• Not drilling a new well when neighboring wells are producing.In addition to the information itself, one of the major benets Tobin offers is the way in which it’s delivered. Through their single le delivery, the data can be obtained within hours, instead of days. There is no stitching, joining or relating required. Employees can also monitor specic areas of interest and if anything changes, they would receive an email informing them of the change. This gives them the ability to constantly monitor and stay on top of anything that occurs, without having to always spend time checking on the status. P2 is raising the bar with their land management software and AI. They are progressing quickly and efciently while making positive growth changes. They are impacting one of the most critical parts of exploration and production, if not the most critical part – the land. Without the land and the plethora of information that surrounds the acquisition of it, there are no oil wells being built and no wells being built, means no oil is being produced. Land knowledge is absolutely vital to the success of this industry. What they are doing is a game-changer and hopefully they don’t intend to stop any time soon. Invaluable Land Knowledge Software and AIBy Sarah SkinnerOILMAN COLUMN

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Oilman Magazine / May-June 2019 / OilmanMagazine.com16OILMAN COLUMNDigital Twin Technology Adds a New Dimension to Offshore Projects By Thornton BrewerOffshore makes a comeback. Bloomberg reports that investors expect offshore investment in 2019 to increase for the rst time in ve years. The greater offshore investment has also led to higher demand for digital technology, in large part to gain greater transparency of workow processes and data. The digital twin creates a virtual replica of the offshore eld, allowing for smarter, more collaborative and efcient eld planning and operations.For many new projects, companies look to implement digital eld twins from day one to enable smarter business decisions from planning through development. Oil and gas operators and service providers already use digital software to plan and build new elds digitally in the cloud, see tremendous potential to introduce new, more transparent digital workow processes into their operations. Global Collaborative Environment Digital twin enables true workow collaboration and information transparency in offshore development. The digitized eld data moves teams away from a traditionally siloed work environment with a variety of owned, non-integrated tools, applications and data to a global collaborative environment. Operators can now collaborate cross-departmentally within the enterprise, as well as with outside contractors as everyone works from the same real-time data. Greater visibility and collaboration leads to better business decisions and greater safety procedures with reduced stafng requirements. Digital twin technology uses Open Web technology to access and view the data at any point no matter where you sit in the world. Additionally, big data signicantly transforms the bidding process for oil and gas engineering rms. Historically, the basic bidding process captured brainstormed ideas from engineers on ip charts and in PowerPoint and then converted them into visuals via Visio, Corel Draw and MS Paint. An outsourced engineering house would then transform them into Computer Aided Design, or CAD, les. This legacy engineering design process limited the EPC rms’ ability to meet tight design schedules and implement late changes quickly. Emerging technologies are proving they can generate many more eld concepts in a much shorter time while helping to eliminate inaccurate options. By uploading data to the cloud, digital twin technologies are able to visualize subsea elds and run computations from a single source of data. For instance, McDermott uses FutureOn®’s FieldAP™ – a FieldTwin™ platform application to respond far more rapidly and efciently to new project opportunities as well as develop multiple concept proposals – in just 20 percent of the time it took to develop a response in the past. The tool accelerates project timelines by up to 80 percent during the early concept and FEED (Front-End Engineering Design) phases.Data Transparency The data transparency via visualization enables teams to see more about their assets from every vantage point and every point in time via real-time 3D digital simulations. This allows engineers to explore more ideas, more rapidly, in collaboration with colleagues all around the world. Through the power of data visualization, engineers examine multiple possibilities in minutes rather than days, weeks or months required in years past. This speed results in 30 percent reduction in pre-feed eld design and signicantly more successful bids for EPC rms.Data Integration and Cost-effectiveness Internal resistance to technology happens because engineers fear the emerging tools will not integrate into legacy systems. These new technologies, however, are being designed with integration in mind. Through an API, these digital technologies are bringing expert engineering systems data directly into a single platform so engineers don’t have to close out of one system to open a ow simulation in another software. Companies may budget cost-effective digital platforms as an operational expense rather than CAPEX (capital expenditure) with a return seen immediately, i.e., $45,000 in cost savings associated with outsourced drafters. Traditional digitalization approaches can involve signicant upfront CAPEX. IoT devices, SMART sensors and robotic tools require costly new equipment investments, employee training and retrotting of existing systems. The return on investment is difcult to assess.As offshore investment increases, companies must adapt to gain competitive advantage initially – and to remain competitive as digital adoption rapidly progresses. Digital twin technology can play a big part in moving the industry forward for greater collaboration, smarter eld development and enhanced operations, all while reducing costs to retrieve the oil more quickly.Thornton Brewer is the digital experience and marketing lead at FutureOn, a 2019 OTC Spotlight on New Technology® Award recipient. For more on how we help maximize the value of new elds, please visit FutureOn®’s FieldAP™ and FieldTwin™ create new elds digitally in the cloud. FutureOn is the only digital solution provider to receive the 2019 OTC Spotlight on New Technology® Award.Digital twin generates a virtual eld in the cloud to offer greater transparency.

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Oilman Magazine / May-June 2019 / OilmanMagazine.com18Downturn by LegislationBy Jason SpiessOn April 16 of this year, Governor Jared Polis signed Senate Bill 181 into law after what many consider one of the most controversial pieces of legislation in oil and gas history, as it met opposition from almost every Republican in the state of Colorado and the energy industry.The law took effect immediately, and changes the Colorado Oil & Gas Conservation Commission’s mission to prioritize health and safety over industry development which at the time of deadline, the COGCC had not implemented nal changes.Destenie McMillen, third generation senior landman, is seeing the impact happen already, even before the new regulations are set in stone.“That bill was passed very quick,” McMillen said. “I along with thousands of landmen, eld workers, roughnecks, we all went and testied to the Senate to really explain there has not been an economic study to show what happens when say 60 percent of a county loses oil and gas revenues.”McMillen continued citing ripples of impact - local businesses, local governments, state governments, county employees, just to name a few. This is before she started citing the formation of committees, school budgets and other local government pontications.A study commissioned by the Colorado Oil & Gas Association (COGA) says the industry contributes $1 billion in tax revenue annually and employs 89,000 people in the state. Another study estimated that if the new regulations were to shut down half of new oil and gas production, the state would lose 120,000 jobs and $8 billion in tax revenue by 2030. The law also gives local governments more say to regulate the industry themselves.A joint statement released by COGA and the Colorado Petroleum Council after the bill passed the General Assembly, said, “While a few critical amendments were added that begin to address some of industry’s concerns and provide a degree of certainty to our member companies, our industry remains rmly opposed to this bill because it threatens one of the pillars of Colorado’s economy.”McMillen validated the energy organizations’ concerns, as she is heavily involved with industry events and is hearing the same story from county to county. And it is causing enough anxiety in companies to take action.“It’s kind of been a little bit of a runaround I guess for a lack of better term,” McMillen said. “Everyone is very nervous. I know of a company that left the Western Slope two weeks ago. They just packed up and moved their operations to Oklahoma.”This new environmental safety narrative and legislation is even bleeding into energy-rich Wyoming.“The most provocative thing for me was the district court judge who basically put a halt on something like 500,000 acres worth of Federal leases claiming that the environmental impact study has not been done to his satisfaction,” McMillen said.McMillen said this is a quick switch in positioning as she cannot recall a time in modern Wyoming history where the court stopped a “bought and paid for” mineral lease rather than validate them.“That’s a little alarming to me,” McMillen said.McMillen’s concern is well warranted. Back in Colorado, Governor Polis is beating the war drums against energy louder every day.“In all of the Senate Bill 181 it was about the environment, health and safety and regulation,” McMillen said. “Then last week he made an interesting comment that no one had said before. He called it the War on Oil and Gas.”This comment comes at an interesting time. America has reached a point where we can use words like “energy independence”, exporting oil and are building more pipelines to ow more energy. While the world is talking about the booming Permian Basin and Bakken, companies are experiencing quick impacts from the new law.“The third-party consultants and businesses will be the rst ones to go. It is the same as when a downturn happens,” McMillen said. “Only this downturn in Colorado is caused by legislation because the rest of the country is booming to the tune, we have oil exports.”McMillen continued to explain how a regular oil price downturn you have to adjust and see the signs as the industry trickles downward. She said in Colorado it is totally different because it is like “someone just dropped a hammer.”“It’s a sad thing when you see how the counties, state and federal governments were working together for this common goal and now with the stroke of a pen it completely changes everything,” McMillen said. “This was a huge accomplishment for our country, but some people do not see it that way.”And right now, those people are in power in Colorado. And they have the ear of a federal judge in Wyoming.Joe Dancy, Associate director, Maguire oil and gas institute, Southern Methodist University, believes the new red tape introduced to the industry will be bad for the oil and gas business.“The risk of additional controls on oil and gas development will certainly lessen the value of the minerals as well as any oil and gas leases that are granted,” Dancy said. “Additional costs, delays in development, and possibly lease expirations all have to be factored into the oil and gas transaction. This is not good for mineral owners, companies, or the state.”William Prentice, CEO, Meridian Energy Group, has felt the pinch of regulations and legislation too. After an unexpected two years of regulatory legal battles only to have their science and engineering validated in numerous times by the state health departments and even the federal Environmental Protection Agency.OILMAN COLUMNTop Women in Energy Award Ceremony Women’s Energy Network - Colorado Chapter Founding BoardWomen’s Energy Network - Colorado Chapter Board 2018Destenie McMillen and Colorado House of Representative Polly Lawrence at an energy industry meeting

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Oilman Magazine / May-June 2019 / OilmanMagazine.com19OILMAN COLUMN“It’s been very frustrating because we expect people to look at us and see people who are trying to do the right thing, which we are.” Prentice said. “We don’t think we get credit for that enough.”Prentice has always invited transparency and hasn’t faulted anyone for asking the question, however, after multiple victories and validations, the oversight organizations should take notice.“The latest set of court challenges, and I get lectured all the time for not commenting on legal stuff, well just reading through this recent appeal there are factual statements in there that are simply not true,” Prentice said. “They have proven to be untrue for the last several iterations. It’s like people do not give us credit or learn anything from the previous proceedings.”And unfortunately for the industry, as long as the elected ofcials can be controlled by fear-mongering health and safety iconoclasts, unnecessary revenue hemorrhaging may be the “new normal” for parts of the industry as the “war on oil” begins and states can now create quick downturns by legislation. Marked by intensied volatility due to continuous sharp oil price uctuations, the oil market experienced its longest and deepest slump in 2014-2016. However, following the oil production cut deal, the prices recovered for a brief time and reached an all-time high in 2019. The oil production cut deal between OPEC and allies, including Russia, coming to an end in June 2019 and the uncertainty about oil prices has spiked multi-fold. Achieving stability in the oil market is imperative; it does not come without challenges. Many practitioners, academicians, and policymakers conducted scalable studies to examine the underlying economic and geopolitical factors of oil price dynamics. The critical determinants of the cyclical behavior of oil markets are supply and demand, global real money stocks, inventories, activities of nancial investors in the oil futures market, developments in nancial markets, geopolitical crisis, and interest rates.The resilience of the oil-rich economies to the oil crisis varied with the economic fundamentals. Countries that have a more scal policy, higher foreign currency liquidity buffers, diversied export base, exible exchange rate regime respond better to oil shocks and have lowered exposure to oil price uctuations.Apart from these factors, technological advances emerged not less signicant than the economic fundamentals impacting the response to oil shocks. Shale oil technology, a combo of hydraulic fracturing and horizontal drilling technology coupled with large-scale viable commercial exploitation in crucial basins, such as the Permian and Appalachian, have propelled the overall unrivaled crude oil and LNG production in the United States to over 11 million barrels (bbls) per day and over 100 billion cubic feet per day, respectively.Using advanced exploration and extraction, the shale industry achieves higher efciency gains and are capable of break even at low crude prices. The recent bids of Chevron and Occidental to acquire Anadarko are driven by the potential of Shale to yield higher prots even at a lower price of crude oil. Such a phenomenon involving a giant corporation acquiring small companies using advanced technologies also generates signicant M&A deal opportunities in the upstream sector, and there can be a surge in transformative acquisitions in 2019. Moreover, shale oil has an enormous potential to drive a signicant increase in supply over the next decade owing to rapidly declining costs of extraction and potential for discovering new elds. Companies relying on more modern technologies such as microwave fracking, drilling pads coupled with Automatic Robotic Drilling can drive down costs of a barrel produced and boost prot margins amid an oil crisis.In addition to new oil and gas production technology, blockchain technology also has tremendous potential to mitigate the adverse effect of price uctuations. Blockchain, the foundation of cryptocurrency Bitcoin, is a ledger capability providing an indispensable solution to trade and settlement inefciencies and reduce the risk of fraud while enabling full end to end visibility in that business network.Blockchain has several use cases in the oil and gas industry, and many companies have viewed this as an opportunity to transform the business and navigate the complex landscape. Blockchain users including Chevron, BP, Equinor, Reliance an Indian oil and gas company, Total a French oil and gas company joined together to establish the Vakt, a digital transaction platform backed by JP Morgan’s quorum.The oil and gas supply chain is byzantine as it includes participants from different global locations and under complex regulations. As multiple suppliers participate in such a complex chain, various linkages in the supply chain become sources of origination and escalation of risks rendering most of the business transactions inefcient, costly and vulnerable to errors.The benet of this technology is unparalleled as it mitigates the risks and drives high business protability by reducing cash conversion cycle, overhead and a number of cost intermediaries. Using smart contracts, digital certications and digital compliance the blockchain technology brings about expeditious transactions in a trusted mode.These technological advances enabling low costs of production and drilling, as well as expeditious transactions with minimal errors and enhanced transparency will facilitate the companies to overcome any future oil price shocks, while maintaining high-prot margins and reducing the downward pressure on the economy.Amandeep Kaur works as a Financial Accounting professional at Scanoleum an oil and gas startup company focused on Oil and Gas trading, Drilling Services and Marketing Oil and Gas equipment. She dedicates a signicant time in monitoring Oil and Gas markets, identifying opportunities as well as managing risks and compliance. She has a keen interest in writing about Oil Markets, M&A activities in the Oil Industry, and Advanced Technologies to help oil and gas businesses. She has an MBA in Finance and Marketing from the University of Delaware. Technological Advances Cushion Oil Crisis By Amandeep KaurPhoto courtesy of everythingpossible –

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Oilman Magazine / May-June 2019 / OilmanMagazine.com20Oil and Gas Measurement Automation is Key in Optimizing ProductionBy Duane HarrisWith commodity prices in ux, the industry seeks to adopt new strategies to increase efciency and optimize existing assets. Producers are looking for new technologies to enhance their organizational agility and, ultimately, improve recovery rates in the high-decline rate wells. As the industry is putting the latest technology to work, measurement departments have found themselves directly in the center of the digital transformations that are sweeping the industry. They are supporting more agile and digitized organizations. That means the ability to provide instant access to up-to-date measurement information throughout the organization is required to stay competitive, all while maintaining one source of truth.Sophisticated measurement automation applications have been a critical enabler of the digitalization and business process transformations that production operations have put into practice. The wide variability in well and pad production necessitates accurate and timely measurement data as well as the ability to monitor and optimize production.How can measurement departments more effectively use the information on ow rates and well performance to balance their systems and optimize production?Measurement AutomationAs measurement processes have become more complicated, automation has become a key focus in the oil and gas industry. Understaffed measurement teams are looking for software solutions that help them work more effectively, utilizing automation to synthesize the vast domain expertise and complexities into manageable workows.Automation allows new measurement professionals to tackle the system balance process, which has become much more complicated with the numerous mergers, acquisitions, and divestitures over the years. Both the organic and aforementioned inorganic methods of company growth have led to diversied operations, where the measurement departments must track multiple uids such as natural gas, NGL (natural gas liquids), and heavier hydrocarbons.These systems will often have a variety of meters, ranging from the traditional orice, positive displacement, and turbine types to newer technologies including cone, Coriolis, and ultrasonic. Installed on top of those meters is a broad assortment of correctors, gas ow computers, and liquids ow computers.An operation that tracks multiple uids must consolidate all the information from the different technologies, verify the accuracy, apply required uid quality samples, and then recalculate as needed. Only when those steps are complete can the measurement department attempt a system-wide inventory balance. Automated system balancing is a powerful tool that can highlight anomalies in the database rapidly as well as in the oil and gas system. Unaccounted-for losses are exposed and pinpointed through techniques such as system segmentation, and issues are brought to light, for example, equipment failures, leaks, and deviations from standard operating procedures.Recent changes to the API Manual of MPMS (Manual of Petroleum Measurement Standards) include the introduction of three-dimensional, physical properties tables and a completely updated 2nd Edition to Chapter 21.1, Flow Measurement Using Electronic Metering Systems—Electronic Gas Measurement. A modern measurement application ensures all functionality stays current with all applicable standards.FEATUREWith FLOWCAL Enterprise measurement software, the user can view a multitude of ow data information. The Volume Editor allows the user to view hourly, daily, batch and monthly ow data as well as characteristic and analysis data.Photo courtesy of Quorum Software

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Oilman Magazine / May-June 2019 / OilmanMagazine.com21FEATUREMeasurement automation applications also provide editing, reporting, and data export capabilities that ensure compliance with audits, industry regulations, and standard operating procedures. Data validations and system balancing ag data anomalies, account for missing data, expose sources of unaccounted-for inventory, and maximize the integrity of the measurement information.Furthermore, the measurement applications integrate measurement ofce operations with eld technician tasks and allow everyone to work from a common database and reports. The integration signicantly reduces potential sources of error and increases efciency across all departments.Data IntegrityData validation is critical for today’s oil and gas companies to reduce their risk prole and ensure accuracy in reporting to both stakeholders and external authorities. This is possible because measurement automation applications employ sophisticated data validation capabilities. The result is an overall improvement to measurement information integrity that not only meets industry and regulatory audit requirements but directly impacts the bottom line.A data validation process ags potential anomalies and brings them to the attention of the measurement staff. Numerous checks and balances are applied to owing parameters, meter characteristics, quality information, and rolled-up historical averages and totals.For a measurement analyst, this can save signicant time that would otherwise be spent sorting through large amounts of data to locate problems long after they occur. Instead, the system ags the issues and analysts can work to solve them immediately.Information that fails a validation test creates an exception in the measurement system, which are reviewed by the measurement staff, typically daily. Through this review, the team identies and resolves most issues on the same day.Issues are tracked throughout the year to determine if equipment needs to be upgraded or replaced or if a new design is needed to resolve an ongoing problem. Before closing each month, all exceptions are either resolved or agged as process-pending.ConclusionIt is necessary to understand ow rates and individual well performance to optimize production, enhance production economics, and improve recovery rates in unconventional wells. The increase in variability and complexity in well and pad productions are driving companies towards automated systems and more accurate data for better operational monitoring and optimization.Modern measurement automation software encompasses the vast expertise that only the most accomplished professionals held. The applications process the considerable amount of data that is provided by measurement equipment at remote well sites and presents it to management in an effective manner. Also, users benet from improvements to compliance, enhanced production, increased asset efciency, and lower operating costs.Duane Harris, an experienced energy sector professional, has more than thirty years’ experience in gas measurement technology with a focus on data integrity and corporate measurement procedures. He gained much of his experience as a Measurement Manager for a major pipeline company. There, he was responsible for overseeing all measurement functions, ensuring data integrity from the eld to the corporate ofce. The Rollup Viewer shows accumulated hourly, daily and monthly period totals for meters and locations such as production well sites. The NGL Balance Viewer allows analysis of NGL balances. It has several options for data viewing including the daily and monthly time frames shown here.

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Oilman Magazine / May-June 2019 / OilmanMagazine.com22Last year’s tumultuous oil prices saw WTI and Brent both start the year at over $60 for the rst time since 2014, the benchmark year for pre-crash prices. Hopes of a true price rebound began to grow as both commodities hit four-year highs several times throughout 2018. For an online archive of how intense the hype became, simply search “will oil prices reach $100 again.” The result is pages upon pages of industry and nance headlines examining the possibility of $100 barrels — the overwhelming majority of which were published in 2018. While the consensus was split, optimists were about to learn a lesson in false hope. WTI and Brent closed the year well below $60 per barrel, prompting the U.S. Energy Information Administration (EIA) to reduce both its 2018 and 2019 forecasts in early December. To add insult to injury early this year, 2019 forecasts were further reduced, along with 2020 forecasted prices. If additional evidence was necessary to illustrate that low prices are the “new normal” for the O&G industry, Q1 of 2019 provided a solid case. How the Biggest E&P Projects Safeguard Prots Logically, cost discipline has been the dominant business strategy of O&G producers since 2014. Any hope of realizing prot in the face of dwindling revenues required signicant reductions in what was already one of the biggest upstream cost risks: operational costs. The upstream companies that were able to weather the latest price crash found ways to trim the fat and implement lean operating principles. However, this was not the case for the biggest ventures in oil and gas extraction: offshore rigs. Whether it was a response to the 2008 crash or simply the capitalist pursuit of prot, stakeholders in these mammoth projects had already identied, rened and implemented new ways to reduce operational costs. How did they manage? By embracing the next step in the evolution of industrialization: digitization.It was mid-2014 when McKinsey & Company published a whitepaper titled “Digitizing Oil and Gas Production.” Using North Sea offshore rigs as benchmarks, they observed that while production efciency had dropped in the past decade, the performance gap between industry leaders and all others had nearly doubled between 2010 and 2012. Looking for what sparked the differentiation, analysts examined the role of technology. Production was considered “digitally-capable” at this point, with any average offshore rig using upwards of 40,000 sensors to collect massive amounts of complex data. So how did the leaders manage to pull away from the pack? By successfully integrating all that data. The E&P companies that were able to use data effectively increased production efciency by ten percent and saw $220 million to $260 million dollar increases to their bottom line. And remember, this shift occurred before the 2014 crash in oil prices. The advantages gained through production efciency became exponentially more valuable in the face of shrinking revenues as global oil prices plummeted. What Does “Successful Integration of Data” Mean?Data can be used in a lot of ways, from reducing unplanned rig downtime by informing predictive maintenance schedules, to enabling the complete automation of complex, unconventional drilling maneuvers. In fact, automation (the conversion of manual processes to automatic ones) is presently the ultimate means of utilizing data to increase efciency. Where the Industrial Revolution was marked by the use of iron to enable mechanization, the digital revolution of the 21st century requires vast amounts of data to enable the next step in our tech evolution: automation. Five years ago, when McKinsey & Company identied automation as a “clear competitive imperative” for the O&G industry, prices were over $100 per barrel and the case for large capital investment in new tech was a hard sell. However, in the new normal of sub-sixty dollar barrels, the urgency of automation is clear.Avoid a Cart-Before-The-Horse Scenario: Automation Is Data-Driven As previously mentioned, automation requires data - and lots of it. Operations such as rigs and reneries are rife with data-capturing Follow The Leader: Examining How Industry Giants Reduced Operational Costs By Going Digital By Shallan GriséO&G producers and service companies don’t need to reinvent the wheel in order to reduce operational costs. The most capital-intensive projects in the industry have proven digitization as a model for reducing operational costs. In this article, we take a look at what analysts learned from the industry’s digital pioneers before examining how to scale the same principles to reduce costs and safeguard prot margins in the face of unpredictable market prices.OILMAN COLUMN

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Oilman Magazine / May-June 2019 / OilmanMagazine.com23opportunities: every sensor, gauge and meter can go from simply displaying information to storing it. However, indiscriminate data collection is unmanageable and will certainly not lead to production efciencies. Before the rigs examined by McKinsey & Company increased prots by $200 million through intelligent data integrations, stakeholders began with a vision for how the information would be used. This way, only digital outputs that furthered the end goal were selected for collection. Scaling Down: The Path to Automation for On-Shore Producers and Service CompaniesVarious automations are available to O&G production and service companies without the need for data collection or other R&D. These ready-made solutions reduce operational costs for some common standard processes such as executing a slide or scheduling tool maintenance. If you can purchase the tech, you are able to reduce operational costs. These products are good for your bottom line but they do not result in a true competitive advantage. Pulling away from the pack and creating the signicant production gap achieved by the leaders in our case study requires vision, creativity and asking the right questions. Where are the opportunities in your operations? Where is data not being captured? Or, which processes fail to leverage captured data? These kinds of questions produced a proven digital model that also performs at smaller scales. Careful examination of your processes will also lead to a well-informed digital roadmap for reducing operation costs. Consider what can be learned from the timing of the industry leaders in the McKinsey & Company whitepaper as well. Rather than reacting to market changes, these innovators made proactive capital investments before the need was even apparent. There’s another advantage to following in the footsteps of giants — you don’t need an in-house team of programmers to create bespoke software tools. Thanks to third party specialists, every step of digitization — from the overall vision to eld execution — is guided by experts. The management of eld crews is one of the biggest opportunities to capture data and improve processes through automation. Even as the digital revolution permeates all other aspects of E&P, eld operations remain heavily dependent on paper, leading to revenue leakage and high operational costs. The disconnect between the eld and the leadership team results in information lags and errors, making effective cost management impossible. At Aimsio, we’re familiar with the challenges you face when it comes to managing remote eld operations. We also happen to be specialists in creating digital solutions for O&G producers and service companies. To see how our platform makes real-time cost management possible by capturing data in the eld, head over to OILMAN COLUMNContinued on next page...Switching from one major to another while in college can be a difcult decision and process. However, switching from a more simple industry to a complex industry, like the oil and gas industry can prove to be even more difcult. The oil and gas industry, once known for its traditionalism and alignment to few demographics, has quickly been evolving and appealing more to a variety of demographics, including recent graduates. With technology, big data, and analytics playing a larger role in the industry, more individuals have been inclined to start career paths pertaining to oil and gas, such as petroleum engineering. Two individuals, Siddhartha “Sid” Sen and Alan Alexeyev have both launched successful careers in the oil and gas industry and currently mentor graduate students looking for ways to enter and transition into the oil and gas industry, as they once did. Both Sen and Alexeyev provided their perspectives on what the journey is like entering the oil and gas industry, what graduate students can expect to face upon entering the industry and how, with a rise of diverse individuals entering the oil sector, the industry is about to experience signicant change.When Sen was asked what inspired him to start a career in the oil and gas industry, he responded “The oil and gas industry is a global platform which brings together people from various educational backgrounds and skill sets to solve problems related to the overall energy mix for the world and it touches many aspects of our day to day lives. It was this fact that led me to start a career in the oil and gas industry.” Sen, originally from Mumbai, India, came to Houston, Texas, to pursue his MBA at Rice University. One of the reasons he selected Rice University for his MBA was its proximity to the oil and gas industry and the fact that it was based in the capital of the energy world.As for Alexeyev, he began his career in the oil and gas industry by attending the SPE (Society of Petroleum Engineer) events and conferences and talking to people and friends about the industry and the profession. “I liked it a lot – the way people worked, the importance of the profession, exibility and opportunities it can offer. I somehow felt connected to the industry and people in it and wanted to be a part of it too. Plus, I always had a general technical education, so I thought I could do engineering as well,” Alexeyev explained. Alexeyev originally majored in Mathematics, but decided to pursue a second bachelor’s degree in petroleum engineering at the University of Wyoming. He obtained a master’s degree in Petroleum Engineering from the University of North Dakota.With both individuals having established their own careers in the oil and gas industry, Transitioning from an Outside Industry into the Oil Sector: Recent Graduates and Petroleum Engineering Education By Tonae’ Hamilton

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Oilman Magazine / May-June 2019 / OilmanMagazine.com24OILMAN COLUMNthey now mentor and lecture graduate students looking to enter the industry, as they once did. When asked about the biggest challenges that students may face when trying to break into the oil and gas industry, Sen explained that the foremost challenge they [students] face is having clarity on what they want to do. “There are innumerable avenues to pursue and having a fairly good understanding should help students in the long run. I always advise students to spend time talking to people from the industry and understand their job roles,” Sen further explained. He also stated that having an idea of what you want to do will provide you the opportunity to develop a plan and work towards it. As for another challenge that students face, Sen shared that in his mind, the second challenge is meeting the right people. Extending on the conversation of students breaking into the oil and gas industry, Alexeyev was asked if he believed the industry had taken initiatives to smoothly transition young professionals into the oil sector. He expressed how the industry could provide more engineer-related jobs for students. “Even if internships are scarce, they could host weeklong job-shadow events, where students could observe what it takes to work either in the ofce or on a eld location even for a brief period of time,” Alexeyev expressed. He stated that such events would boost the understanding of petroleum engineering classes and the industry by a lot. “Maybe have some sort of weeklong boot camps set up on drilling rigs or in the ofce, make that part of the curriculum. I foresee that would be the next big step the industry can take to help the younger generation. This in turn will produce better quality students just because they will understand it much better upon graduating,” Alexeyev further explained.Alexeyev was also asked if and why it is important for more young adults to be in the oil and gas industry. “Yes, it is important and SPE is at the front of all of this,” stated Alexeyev. “There are local and university chapters everywhere that organize the learning and volunteering and social events, as well as sister organizations that are also closely related to oil, like the AADE, AAPG, AGU, ARMA, SEG, etc. It’s really all part of one big oil-related industry and points out how different disciplines can work together and help each other,” Alexeyev further explained. He described how during those organizations’ events, young people and students are exposed to those who have been in the industry longer and thus, can learn from them. “They can see the expectations of the industry and how they can t in. It’s great for networking, great to see what new technology and trends other companies are doing. There’s just so much interesting stuff out there,” Alexeyev expressed.Continuing the conversation on graduate students and young professionals entering the oil sector, Sen was asked whether he believed the incoming of graduate students and individuals from other industries into the oil and gas industry would have an effect. He was additionally asked if an inux of diverse demographics would be advantageous to the industry? Sen answered, “I am a rm believer that a diverse demographic community will be benecial to each and every one in the industry. I also believe that diversity already exists within this global industry.” He further explained how the oil and gas industry is in the process of implementing effective ways to harness data and information for operational efciencies. “The incoming batch of graduate students will bring valuable skill sets to achieve this and thus should be capable of impacting the future of the industry. Diversity will help bring varied thought processes, views and expertise together, which will be benecial to the oil and gas industry,” Sen expressed.On the topic of transition, Alexeyev was asked whether he believed an individual’s transition from another industry to the oil and gas industry would provide difculty or opportunity, such as a diverse perspective. He responded, “The oil industry has many people working with different but related STEM (science, technology, engineering, and math) programs. I think nowadays we’ll be seeing more computer scientists/engineers working in our industry too, because of the shift to digitization, data analytics, and automation.” He expressed how he would advise that the petroleum engineering curriculum add a few data analytics and computer programming courses as a requirement to reect the current industry changes.Continuing the conversation on industry transition, Sen was asked what advice he gives to individuals looking to transition into the oil industry from graduate programs or other industries. He stated “My advice to anyone trying to transition into the oil and gas industry would be to try and identify the challenges that the industry is facing currently. Then, develop skills which would help address or work on these challenges.” “The oil and gas industry is looking to better harness the data that is available and use it to increase efciencies, and anyone with the skills to enable or achieve it will be in demand,” Sen further explained.When asked what advice he gives to students who initially express interest in the oil and gas industry, Alexeyev stated that for those interested in an oil and gas career, “I’d say denitely choose a major in STEM, whether it is a general engineering (civil/mechanical/chemical) or science (math/CS/physics) major, just to have exibility in case you end up not pursuing oil so you can still apply yourself in other industries.” He expressed how students could take introductory petroleum classes which could serve as electives. “That way, they [the students] wouldn’t lose time and classes in case they decided not to pursue it; it’s all about being exible,” explained Alexeyev. Photo courtesy of khunaspix –

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Oilman Magazine / May-June 2019 / OilmanMagazine.com26OILMAN COLUMNScale Sand Production with Modular Natural Gas Power By Mike Mayers and Josh Haugan To continue to reduce costs, frac sand companies and oil companies have started to build their own frac sand mines in the Permian Basin, located mostly in the western part of Texas and in the southeastern part of New Mexico. While the quality of these in-basin frac sand mines is slightly lower than Wisconsin White Sand, operators cut millions from their capital budgets by supplying their own frac sand closer to their production sites in West Texas. This trend marks a signicant shift in the sand mines industry, as in-basin frac sand now accounts for a majority of the market, which has started rail shipments out of the Permian Basin and dissipated frac sand shortages. However, access to power grids remains limited. It can take a utility company anywhere from 12 to 24 months to set up the infrastructure re-quired to power a frac sand mine; however, after investing $100 million in a new mine, suppliers cannot afford to hold production until power becomes available from the utility company.Modular natural gas generators bridge the power gap, enabling mines to start production and enter the market before the installation of permanent utilities. Rental power companies and owners and contractors’ electrical engineers work closely to develop a sophisticated, cost-effective and environment-conscious power plan for each mine that delivers the following benets:Low-cost Natural Gas Mine operators seeking alternatives to diesel nd natural gas to be an attractive option. Natural gas cost 40 to 45 percent less than diesel and since they need to supply their sand dryers with natural gas the use of natural gas generators is a no brainer.However, the costs associated with natural gas generation, installation and operations, as well as the required maintenance of these complex installations, prove far less than the cost to hold production until permanent power is available, which can take years. In fact, multiple Permian sand mine developers are already using 83 megawatts of natural gas power in a market previously dominated by diesel. Reduce Environmental Footprint Over the years, many local governments and authorities have raised concerns about the long-term continuous use of diesel generation because of NOx pollutants. Tighter regulation means sand mine developers are expected to explore alternative options to minimize energy waste, reduce greenhouse gas emissions and improve air quality.Mine operators nd natural gas to be a good option for environmental reasons because natural gas emits roughly 30 percent less carbon dioxide than diesel fuel according to U.S. Energy Infor-mation Administration. With the emergence of lean-burn engine technology, natural gas power generators also meet the U.S. Environmental Protection Agency’s emissions regulations.One Size Does Not Fit All Projects vary greatly and so must power congurations to achieve each unique site’s needs and required redundancy levels. Thanks to a well-engineered power solution, the sand mine’s power capacity can ramp up or down, or the diesel can be swapped out for natural gas should it become available later.Also, gas-powered generation can install a redundancy of N+1 to achieve 100 percent uptime should a generator fail or to allow a generator to be serviced every 30 days for maintenance, as required. A sand mine operator certainly doesn’t want to shut down or reduce production due to routine maintenance on a generator. GroundingInadequate grounding and ground testing leaves personnel and equipment at risk and doesn’t meet Mine Safety and Health Administration requirements. The process of accurately measuring ground resistance is essential to verify proper grounding and ensure the protection of people and equipment. Proper grounding in highly resistive soil such as sand is much more difcult than in other materials like dirt or clay. Certication of correct grounding in large power grids such as these usually calls for a different method of testing.Remote Monitoring Given the off-grid locations of most mines, it is essential to have a remote monitoring system in place to monitor and verify the operation of the power system. Remote monitoring alerts engineers immediately of an issue and allows for swift and focused decision-making before a costly problem or worse, downtime can occur. Such an incident can cost a mine up to $15,000 an hour. The 24/7 monitoring of the installa-tion, operations and required maintenance of these complex power systems enable operators to devote a larger share of capital to other mine projects. Natural gas provides cost-effective, sustainable, exible and dependable power for frac sand mines waiting on permanent power. Mines can start up to almost a year ahead of schedule thanks to modular natural gas power, potentially generating $100 million of revenue in 11 months for the operator. Mike Mayers is a business development manager specializing in the frac sand industry for Aggreko, based in Houston, Texas, and Josh Haugan is a business development manager also based in Houston. Call Aggreko at 1-800-AGGREKO (1-800-244-7356) or visit whenever you need help. New frac sand mines speed to market with natural gas-powered generators

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Oilman Magazine / May-June 2019 / OilmanMagazine.com27In fracking, there is the initial capital investment, however, to keep production at a constant output, capital expenditures are needed every year for DCET (drilling, completions, equipment and tie-ins). This reduces the net prot, as the payout term is always present.Photo courtesy of 汤 石 宏 – www.123RF.comDavid Sealock, CEO of Petroteq Energy spoke with OILMAN’s editor, Eric Eissler, at length about the company’s innovative oil sands extraction technique which is environmentally friendly because it does not use water in the extraction process. Crunching the NumbersWhen you think about the costs of buying capital equipment, there are high associated costs with it that makes many executives reconsider purchasing new equipment until it has been fully depreciated and used—in most cases—well beyond their intended life. However, according to Sealock, “The capital cost to construct PQEs proprietary CORT (clean oil recovery technology) is the lowest in the oil sands mining sector at approximately $10,000 per owing barrel.” He continued, “Conventional oil sands mining extraction capital costs are four and ve times this amount per owing barrel. The reason for this is that our CORT does not use water in the process.” Whereas, the conventional oil sands mining operations spend a massive amount of capital on water handling and treatment, however, it does not alleviate the environmental issue of the tailing ponds that are created by this process.Drilling down further into the costs aspect, Sealock pointed out that Petroteq’s process is much more favorable than fracking cost on both levels: capital costs and operations costs. In terms of capital costs, “our facilities are ‘build once and produce for multi-decades’. For example, our 1000-barrel-per-day facility in Vernal, Utah has the resources available to produce for over 4 decades.” This is a one-time investment on capital equipment, with a massive ROI over a multi-decade term.Regarding operations costs, based on economies of scale of the daily production will be constant at $25-barrel-of-liquid-equivalent when we are producing more than 4,000 barrels of oil per day. Sealock further explains the multi-decade advantage, “as our operations are multi-decade, we can keep our costs constant as our operations stay the same. With fracking, in my view, there is uncertainty if a constant cost base can be achieved, as there are more elements that are needed – access to water, fracking sand, etc. I think that the industry will see more variability in fracking that our oil sands mining process provides.”Furthermore, while Petroteq cannot control oil commodity pricing, the company is focusing on what it can control and that is operations costs. As Petroteq heads into the 2nd half of 2019, the company will look at hedge options for production as needed through forward market sales. The First Operational Facility The rst CORT facility has been up and running in Vernal, Utah.With the success of the pilot plant and the current production at Vernal, Utah, Petroteq had the engineering data and the continuous operations experience to apply for an additional 3,000- barrels-of-oil-per-day expansion. Sealock highlights its production numbers by saying that “this will increase our production to 4,000-barrels-of-oil-per-day and as we expect State approval in the very near term, we hope to have this 3,000 barrels of oil per day expansion built and commissioned by Q1 2020 and in full operations by Q2 2020. This expansion will be the building block on how we will expand our production operations on our other assets as well as local and global potential licensing and or joint ventures we are in discussions with.”Growing Interest and Expanding Blockchain Technology General interest in the CORT system has been on an upward tread. This is due, in part, to the fact that there is an operational CORT facility. Technology has and will always be the catalyst that increases production at lower cost and in a much more environmentally favorable way. Petroteq’s CORT is this type of technology and it will change the way that oil sands mining is assessed in the future. Not only does Petroteq’s CORT reduce costs for oil sands extraction, both on a capital expenditure and operations costs basis, the key to the process is that it uses much less energy than many other methods of harvesting oil sands hydrocarbons. “Because it uses no water and has virtually no GHG emis-sions, our CORT has environmentally efcient environmental goals and is very synergistic for the industry,” Sealock summed up. Petroteq’s BlockchainWhile Petroteq has been using aspects of the PB (Petrobloq Blockchain) operations in our capital expenditures, the focus on Petrobloq Blockchain has been managed by Marcus Laun, our Business Development director. The development of PB has been more centric to our work with vendors, our work with the State and in the future, with potential business partners. Since it launched around this time last year, there have not been too many updates as to its progress. It can be assured that the blockchain development has been kept under wraps in order to keep competitors from gaining any inside information as to what the company is developing. Waterless Oil Sands Extraction Process set to Improve Oil and Gas Industry Environmental Track Record By Eric EisslerOILMAN COLUMN

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Oilman Magazine / May-June 2019 / OilmanMagazine.com28OILMAN COLUMNBe Aware of the Modern Day Snake OilBy Jason SpiessThe founder and CEO of BMA Biotech, Mark Bullock is no stranger to the oil and gas industry. Both Bullock’s step-father and father-in-law have both worked in the industry for over 40-years. So, it is little wonder how a small-town boy from the United Kingdom is now living in Sugar Land, Texas and providing highly effective products and sustainable services to the O&G industry.“BMA Biotech is a family owned company, with long and established ties in the oil and gas industry,” Bullock said. To aid Bullock in the development of his rst range of oileld chemicals, he built up a team of scientists and petroleum engineers who all had considerable experience within the industry. This would ensure that not only were BMA Biotech’s oileld chemicals highly-effective in their application, but also, it would make sure that the products were sustainable and reduced risks to health, safety, and the environment while being 100 percent biodegradable within 75-days.Bullock said within a few short weeks of the release of their newly developed oileld chemicals in early 2017, their professional network and new clients within the industry begun to voice concerns regarding a number of oil spill cleanup products used in the industry, which was akin to snake oil. “Our clients continually chose BMA Biotech to undertake eld assessments and the implementation and execution of treatment plans, as all of our eld personnel have extensive site evaluation and both soil and water remediation treatment experience, in the continental United States, United Kingdom, Europe, and certain regions in the Mid-East,” Bullock said. “I know it is different in every state and country, but in Texas it is called the Responsible Party. Basically the company that causes the spill, for lack of better words, is the one legally on the hook for the clean-up.”Bullock listed off a few PT Barnum-esque claims he was aware of, which ranged from turning crude oil into non-harmful sand to other spurious claims which were scientically impossible. “Look at what they are telling you about their products and actually just Google it,” Bullock said. “You’ll nd more than enough academic research out there to prove or disprove their theory.”To ensure that BMA Biotech was able to develop a more effective range of spill remediation products, they added new members to their research and development team which had over 40-years of experience in oileld remediation sector. By early 2018, BMA Biotech had released their rst ex-situ soil wash chemical and in-situ/ex-situ microbial based spill remediation products. Bullock said, their bioremediation product differs from conventional products as they don’t use bulking agents – such a vitamins and their bioremediation product contains a wider spectrum of microorganisms than any other microbial based remediation product. “We developed a microbial remediation product and we proved our formulation by adding more microorganisms than any other product on the planet,” Bullock said. “Which is far more sustainable and effective.”He then went on to say how their ex-situ chemical treatment differs is that it can be separated from oil/petrochemicals and then re-used. In addition, the oil/petrochemicals can be recovered and sold as a commercial commodity. “We pride ourselves on setting the standards, for others to follow. We only resort to ‘dig and haul’ as a very last resort, or if state agencies prefer this method of oileld contamination cleanup. We stand behind all of our remediation products, and only deploy the most effective types of treatment methods. We do not mis-sell our products, nor do we make false or inammatory claims about our services and capabilities of our products,” Bullock said.Initially, it seemed that the PT Barnum-esque companies were being countered by BMA Biotech’s new remediation products, to some degree. But Bullock knew he had to step up to the next level when a company basically told him to assist them in a clean up mess from one of the snake oil companies operating in the oileld. “We have over 40-years of hands-on experience in providing Phase I and Phase II environmental site assessments and delivering effective soil and water remediation programs to a diverse range of oil and gas companies around the world,” Bullock said. “We believe our oileld environmental services are world-class and provide a true ‘cradle to grave’ approach to the cleanup and successful remediation of oileld contamination.” Micrograph showing how SWS encapsulates crude oil petrochemicals E&P wastewater - produced waterMicrograph comparing conventional microbial product spore count to BMA 400

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Oilman Magazine / May-June 2019 / OilmanMagazine.com30OILMAN COLUMNInterview: Josh Robbins, CEO, Beachwood Marketing By Emmanuel SullivanEmmanuel Sullivan: When did you start Beachwood Marketing and what is the business pain point you solve?Josh Robbins: It was a side hustle from 2010 until 2014, then I “ofcially” opened the doors of Beachwood. Beachwood is celebrating our ve-year anniversary this July.Beachwood started because I accidently uncovered a deal during my nine to ve gig; discovering that an oil company was going to sell all of their assets. I left the oil company and made a call to a good friend (who happened to operate in the same area) and told him the information. Two months later, we were having beers celebrating the acquisition of those assets.I had no idea that there was an opportunity like this. When I asked that Oilman how he would have normally gone about buying additional wells, he said he would check in once a year with that operator over breakfast, but that there wasn’t a real outlet for people to purchase wells outside of the online auction houses. Beachwood is actively solving a signicant pain point in today’s oil and gas industry: transacting – actually buying wells off-market in this pricing environment. ES: What services does Beachwood Marketing provide for the oil and gas industry?JR: Beachwood is a contract business development service that uncovers oil and gas deals by calling oil and gas operators (over 4,000 calls monthly).ES: How has the oil and gas property buy/sell activity been the past year?JR: The last ve years in the oil and gas industry have been lled with ups and downs. It wasn’t until the summer of 2018 that the acquisitions and divestiture segment nally recovered. Everyone was excited to see $70 oil, then the market crashed again in October of 2018, sending the industry back to square one: full recovery mode in the last quarter. Since the start of 2019, and especially in Q2, the A & D market has really picked up; the Chevron acquisition of Anadarko helping to encourage the market movement.ES: What technology platforms do you rely on to conduct business?JR: The primary technology platform that I use is LinkedIn; I’ve been an active user since 2012 and I push my team to utilize its reach. This year LinkedIn has grown into a personal branding platform, and I’m now a Micro-Inuencer for the oil and gas industry. I’m actively building a network of followers that are interested in my travel, sales, oil and gas and traditional networking opportunities.ES: Do you have any changes planned for the services you offer?JR: Beachwood doesn’t have any changes planned for our services; we will continue to track down off-market deals for the foreseeable future. ES: Do you see growth in the oil and gas segment you serve?JR: The oil and gas market we serve is actively looking for assets to purchase and any additional assets we can uncover, expands their reach. I think there is an enormous growth opportunity for buy side deal sourcing.ES: What is a typical day for you like?JR: As a business owner, I’m not sure there is such a thing as a “typical day.” Normally I’m up around 5:30 am, whether here in Oklahoma City (where the Beachwood ofce is located) or on the road (I travel about 43 weeks a year). In the ofce by 6:30 am, I enjoy the quietness of the ofce. I always start with a cup of coffee and mapping out the calls for the day. Any meetings in Oklahoma City are done at Stella Nova; the best coffee in all of Oklahoma City – because #coffeeisforclosers. That hashtag is always on my LinkedIn posts, which has helped to grow my Inuencer base. The rest of the day is lled with calls. I’m on the phone at the ofce, cell and in the conference room. On any given day, I probably make or receive 120 phone calls – but I’m in the Outbound Call business! I’m not a fan of formal, sit down meetings. We meet Monday’s and Friday’s and the rst day of the month. Other than that, we accomplish what we need via email or phone. The Monday / Friday meetings are always to celebrate the victories. There is an epidemic in our culture about eighth-place trophies. I am a big proponent of encouragement and celebrating the small wins. It’s not an eighth-place trophy, it’s a high ve and a pizza slice. It’s taking an interest in your team and knowing when they hit the small goals. Because if you hit 12 small goals – one every month – you are denitely hitting your year goal!The workday usually continues late, as I try to dene the tasks for the following day and to plan travel if needed. I look at owning my own company as being on the clock non-stop. My Grandfather owned his own business for many, many years, and it was his advice I asked for prior to starting Beachwood. He asked me one question: Are you okay with working every second of your life? Gramp said that even when you turn the lights off and lock the door to go home, your business is in every thought. On the elevator, in your car, in your dreams. And if I can handle that, then I’m an entrepreneur and I should open my business.On the road I’m constantly checking in on the family – using SnapChat and Instagram to send the kids messages and get jokes/pictures back from them. It’s 2019. Your kids are using social, so communicate like they communicate! We share music. I know what books they are into. They ask for food recommendations for places they are at with friends. I honestly think that social has me more connected to my kids than I could ever hope to be without it. Taking off from work I usually check LinkedIn and Soundcloud for new music to listen to for all the road trips. It’s mostly inspirational, instrumental music and podcasts.ES: How is your service different from competitors? JR: Our competitors are sell-side auction houses that broker deals. At Beachwood we don’t broker. We don’t have land, legal, geo or engineering, we have salespeople that can nd deals that aren’t on the market. We are buy-side deal nders, which is considerably different from our competitors.ES: What methods do you use to market your business?JR: Beachwood’s core business model uses outbound marketing; primarily through targeted outbound phone calls. “We take inbound calls, make outbound calls, send emails, LinkedIn mes-sages and pull leads from our website trafc”.

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Oilman Magazine / May-June 2019 / OilmanMagazine.com32Oil Markers: Useful Pricing ToolsBy Eugene M. KhartukovBenchmark crude (oil marker) is the petroleum that serves as a pricing reference for other types of oil and oil-based securities. The benchmark makes it easier for traders, investors, analysts, and others to determine the prices of multitudes of grades of crude oil varieties and blends. Using benchmarks makes referencing types of oil easier for sellers and buyers.There is always a spread between WTI, Brent and other blends due to the relative volatility (high API gravity is more valuable), sweetness/sourness (low sulfur is more valuable) and transportation cost – the price that controls world oil market price.Brent blend is a light (38.06° API), sweet crude (0.37% sulfur by weight). Some 15 U.K. elds in the Brent-Ninian area in the northern North Sea contribute to the blend, although very little production comes from the once-prolic Brent eld, after which the stream was named. The Brent blend is transported to the Sullom Voe terminal via pipelines. This terminal, representing an inlet between North Mainland and Northmavine on Scotland’s Shetland Islands, is operated by Enquest, which acquired a three percent stake and the operatorship of the terminal from BP in 2017. Despite the declining physical volumes associated with the Brent blend (a peak of 1.3 mln b/d in 1985, less than 0.5 mln b/d in 2000, 75.5 kb/d in 2018 and forecast 58.1 kb/d in 2020), its importance as a nancial oil benchmark is increasing (though seriously questioned now). Therefore, between 2002 and 2015 a series of changes were made to Dated Brent in an effort to maintain its liquidity and status – by increasing the available volume (some crudes were added and its delivery window was repeatedly widened). Generally speaking, three major markers used in pricing of crude oil across the globe are WTI (Western Texas Intermediate) for the American markets, Brent for the European/West African Markets and Dubai or OD (Oman/Dubai) crude oil grades used for Persian Gulf and the Asian markets. Crude oil benchmarks are reference points for the various types of oil that are available in the market. Also known as oil markers, crude oil benchmarks were rst introduced in the 1980s, with the aim of establishing a standard for the world’s most actively-traded product. At present, there are dozens of different oil benchmarks, with each one representing crude oil from a particular part of the globe. However, the price of most of them are pegged to one of the following three primary benchmarks: Brent, WTI or OD. Roughly two-thirds of all crude contracts around the world reference Brent Blend, making it the most widely used marker of all. Other well-known oil markers include the OPEC Reference Basket used by OPEC, Tapis Crude which is traded in Singapore, Bonny Light used in Nigeria, Urals oil used in Russia and Mexico’s Isthmus as well as Canada’s Western Canadian Select (WCS) and Edmonton Par crude. WTI, known also as Texas Light Sweet crude, is referred to as the oil extracted from oil elds and wells in the U.S. and is landlocked. The crude is transported via pipelines and hence one of the drawbacks as it is fairly expensive to distribute and sell to other parts of the globe. This crude is light and ‘very sweet’ (API gravity 39.6°, sulfur content 0.4-0.5 % by weight). WTI is pumped to Cushing hub in Oklahoma and is a benchmark for crude mainly in the United States. Historically, price differences between Brent and other index crudes have been based on physical differences in crude oil specications OILMAN COLUMNThe Geographical Range of WTI and Brent Brent is the reference price for roughly 66% of all globally traded oil, while WTI is the dominant price marker in the United States. Dubai crude – which is mainly delivered to Asian countries – is the main reference for oil traded in Middle Eastern markets.Sources: Intercontinental Exchange (ICE), Investopedia, Money Morning Staff ResearchChart 2. Global Coverage of the Main Oil Markers / Source: Peak Oil

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Oilman Magazine / May-June 2019 / OilmanMagazine.com33OILMAN COLUMNand short-term variations in supply and demand. Prior to September 2010, there existed a typical price difference per barrel of between ±3 USD/bbl compared to WTI and OPEC Basket; however, since the autumn of 2010 Brent has been priced much higher than WTI, reaching a difference of more than $11/b a barrel by the end of February 2011 (WTI: 104 USD/bbl). In February 2011 the divergence reached $16/b during a supply glut, record stockpiles, at Cushing, Oklahoma before peaking at above $23/b in August 2012. It has since (September 2012) decreased signicantly to around $18/b after renery maintenance settled down and supply issues eased. In 2018, on the average, this price premium in relation to WTI stood at over US$6.1/b (Chart 1). Dubai/Oman refers to the crude oil produced in Middle Eastern countries and is lower grade than Brent or WTI. It has high sulfur content and is procured in Dubai, Oman and Abu Dhabi. This is the benchmark for the Persian Gulf production and is mainly sent to Asia (Chart 2).Tapis Crude: It is the benchmark for light sweet Malaysian crude. The sulfur content is as low as 0.03% and the API gravity is around 45.5. Although this oil marker is not as widely traded as WTI, it is used as a benchmark in Asia.Bonny Light: It is a benchmark for high grade Nigerian crude, with an API of around 36. Due to its very low sulfur content, it corrodes the renery infrastructure minimally.Isthmus: This is the crude oil benchmark for light crude produced in Mexico. The sulfur content is around 1.45% and the API gravity is 33.74º.The OPEC Reference Basket (ORB), also referred to as the OPEC Basket, was initially introduced at the start of 1987 and was originally the pricing data formed by collecting seven crude oils from the OPEC nations (except Mexico). These included, on an arithmetic basis, the spot prices of Saudi Arabia’s Arab Light, Algeria’s Saharan Blend, Indonesia’s Minas, Nigeria’s Bonny Light, Venezuela’s Tia Juana Light, Dubai’s Fateh and Mexico’s Isthmus. This information was used by OPEC to monitor the global conditions of the oil market. Since June 16, 2005 (decided by the 136th OPEC Conference), the OPEC Reference Basket of Crudes (ORB) was the production-weighted average of 14 (since June 2018) it composed of the following 15 crudes: Saharan Blend (Algeria), Girassol (Angola), Djeno (Republic of Congo), Oriente (Ecuador), Zaro (Equatorial Guinea), Rabi Light (Gabon), Iran Heavy (Islamic Republic of Iran), Basra Light (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), Qatar Marine (Qatar), Arab Light (Saudi Arabia), Murban (UAE) and Merey (Venezuela). As of June 2005, ORB’s API gravity was 32.7° and its sulfur content – 1.77% by weight.In 2007-2018 the following changes have happened to composition of ORB:• As of January 2007: The basket price includes the Angolan crude “Girassol” • As of 19 October 2007: it includes the Ecuadorean crude “Oriente”• As of January 2009: excludes the Indonesian crude “Minas”• As of January 2009: the Venezuelan crude “BCF-17” was replaced by the crude “Merey”• As of January 2016: the basket includes the Indonesian crude “Minas”• As of July 2016: it includes the Gabonese crude “Rabi Light”Chart 1. Monthly Dynamics of WTI and European Brent Spot Prices in 2018, in US$/ bbl Source: Eugene M. Khartukov Chart 3. Annual Dynamics of ORB Price in 1994-2018, in US$/b Source: Eugene M. Khartukov Continued on next page...

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Oilman Magazine / May-June 2019 / OilmanMagazine.com34• As of January 2017: excludes the Indonesian crude “Minas”• As of June 2017: includes the Equatorial Guinean crude “Zaro” • And as of June 2018: includes the Congolese crude “Djeno”In 1994-2018 annual average price of ORB has increased 4.5-fold: from $15.53 per barrel on the average of 1994 up to $69.78/b in 2018 (Chart 3). At the very end of 2018 ORB average price stood at $51.55/b and was growing.Edmonton Par and Western Canadian Select (WCS) are benchmarks crude oils for the Canadian market. Both Edmonton Par and West Texas Intermediate are high-quality low-sulfur crude oils with API gravity of around 40°. In particular, Par crude, delivered at Edmonton, Alberta, has 40.02° API gravity and 0.3% sulfur. In contrast, WCS, blended at a storage terminal in Hardisty, Alberta, is a heavy and sour crude oil with an API gravity of 20.5 to 21.5° (925 to 935 kg/m³) and sulfur content of 3.0 to 3.5% by weight.Western Canadian Select (WCS) trades at a considerable discount to WTI (up to US$30/b at the end of 2017). But the gap started to widen in 2018 as U.S. renery capacity was rising (Chart 4). For Edmonton Light, the discount jumped to U.S. $7.32 per barrel in January, after averaging U.S. $3.93 in Q4 2017, and this discount was expected to narrow to around US$3.50 by 2019.The Canadian Crude Index (CCI) serves as a benchmark for oil produced in Canada. It allows in-vestors to track the price, risk and volatility of the Canadian commodity. The CCI provides a xed price reference for Canadian crude oil and provides an accessible and transparent index to serve as a benchmark to build investable products upon, and could ultimately increase its demand to global markets. The CCI was launched by Auspice Capital Advisors in 2014 and can be used to identify opportunities to speculate outright on the price of Canadian crude oil or in conjunction with WTI to put on a spread trade which could represent the differential between the two. Currently, Canadian oil trades at a discount to WTI. The landlocked location and transportation constraints of crude oil in Western Canadian provinces contribute to this discount. Also, until 1986, Arab Light (or shortly AL) price (32. 8° API (0, 8602 г/см3; OPEC sources insist on 34° API; sulfur content – 1. 97 %) was a leading oil marker and a technical reference, to which all OPEC’s other oil prices were linked. In early 1986 Saudi Arabia adopted net-back pricing and AL price was replaced as the world oil czar by Brent blend spot prices (Chart 5). Furthermore, until 2009 Indonesia’s Minas crude (also referred to as Sumatran Light) and comes from the island of Sumatra. Its API gravity is approximately 35° and the specic gravity is 0.8498; sulfur content of only 0.08%) was an oil marker for up to 1 million b/d of Indonesian, Vietnamese and Sudanese crude, a legacy from an era when Minas, which began commercial production in the 1950s, was the largest oileld in Southeast Asia. However, its output, once above 400,000 b/d, has fallen by mid-2008 below 200,000 b/d (and, perhaps, as low as 150,000 b/d due to the ageing eld’s natural decline) and less than 50 kb/d of Minas oil was available for exports.Malaysian Tapis crude with an API gravity of 42.7° and with only about 0.04% sulfur is also under the question as a Pacic/Asia oil marker OILMAN COLUMNChart 4. Daily Movements of WCS, Maya and WTI Spot Prices in 2013-2018, in US$/bbl Source: BloombergChart 5. API Density and Sulfur Contents of Some Crude Oils / Source: Energy and Capital

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Oilman Magazine / May-June 2019 / OilmanMagazine.com35OILMAN COLUMNas its production currently naturally declines (from a maximum of 360,000 b/d to around 280,000 b/d now). While it is not traded on a market like Brent or WTI, still it is often used as an oil marker for Asia and Australia. Tapis oil has previously lled the role of regional light sweet benchmark, powering the APPI index system that was widely used in In-donesia, Australia and Vietnam.The price of Tapis in Singapore is often considerably higher than the price of benchmark crude oils such as Brent or WTI. This is because its greater aromaticity (i.e., higher °API) allows for greater production of higher-value products, such as petrol (gasoline), than from Brent or WTI. Its high price is also due to the purity of the blend. Because it contains less sulfur, it requires less renery processing than sourer crude oils such as Brent crude and WTI.Alaskan North Slope (ANS) crude blend (a relatively high viscous – 23.9cSt @50°F –- and quite heavy – 29.6° API) is also considered as a Pacic oil marker but its production (over 2,000 kb/d in the second half of the 1980s) is falling (down to below 500 kb/d in 2020, according to forecasts).Urals blend, which is a mixture of crudes produced in Volga-Urals and Western Siberia with its sulphur content of 1.3-1.8% and specic gravity at 20°C – 850.1-870.0 kg/m3 and at 60°F – 853.7-873.5 kg/m3 (≈ 30.5-34.5°API) pretends to become a global oil marker, although the bulk of this crude is known to be sold within term contracts with a few European buyers. Urals trade has been fanfare-ously launched in Moscow on SPIMEX commodity exchange in late November 2016 as a long-awaited genuine benchmark crude. But, with the known inertia and limitations, it is actually a forcebly introduced local and invalid oil marker, which is unlikely to become most widely (globally) used in any foreseeable future. Interesting to note that 2006 already saw the rst attempt to create a tradeble futures contract for the Russian export crude – under the name of REBCO (Russian Export Blend Crude Oil), which started to be traded on the NYMEX. However, the contract did not gain popularity among oil traders (number of trades was extremely limited) and was eliminated in 2012.Also, ESPO blend, which is sold from Kozmino terminal in the Russian Far East and has, according to Platt’s, sulfur content of 0.54% and gravity of 34.7°API, may become a Pacic oil marker in the future but it is not traded yet on any commodity exchange that provides the needed liquidity and the price’s transperancy.In response to accusations that Brent price was manipulated by some oil traders (Platt’s was ready and eager to take a killing legal action against those who publicly disseminated such accusations). The leading oil-price agency has developed an InterContinental Exchange (ICE) introduced in early July 2015. The so-called BFOE Index, which is the volume-weighted average price of trading in the 21-day Brent Blend and Forties (UK), Oseberg and Ekosk (Norway) (and since 2018 also Norway’s Troll crude) ‘cash’ or forward market in the relevant delivery month as reported and conrmed by industry media and is an average of second month cargo trades in the 21-day BFOE market plus or minus a straight average of the spread trades between the rst and second months.In the same vein, Argus Media launched in May 2009 and publishes daily now Argus Sour Crude Index (or shortly ASCI), which is based on sour oil production in U.S. Gulf of Mexico (offshore Lousiana), and is a useful pricing tool used by buyers, sellers and traders of imported crude oil for use in long-term contracts and has been adopted as the benchmark price for sales of crude oil by Saudi Aramco (in 2009), Kuwait (in 2009) and Iraq (in 2010). Contracts based upon ASCI are listed on the world’s two largest oil exchanges, the New York Mercantile Exchange (NYMEX) and the Intercontinental Exchange (ICE).Oil markers’ price dynamics are well correlated but not to a full extent – reecting oil balances of their own markets (Chart 6).Talking about the prerequisites (preconditions) of oil markers, it would be useful to look at the table, showing the compliance with them of Brent and Urals oil blends (Table 1).Eugene Khartukov is a Professor at Moscow State University for International Relations (MGIMO), Head of Center for Petroleum Business Studies (CPBS) and World Energy Analyses & Forecasting Group (GAPMER) and Vice President (for the FSU) of Geneva-based Petro-Logistics S.A. Table 1. Compliance with the Main Prerequisites of an Oil Marker for Brent and Urals Blends Source: ICIS complied from Liz Bossley, 2018

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Oilman Magazine / May-June 2019 / OilmanMagazine.com36OILMAN COLUMNImproving Oil and Gas Storage and Operations Through Innovation By Tonae’ HamiltonThe topic of oil conservation, protection, and storage has become a prevalent area of interest in the oil and gas industry. With more companies looking for ways to store oil properly and safely and avoid the ever-present risk of tank explosions, the demand for oil and gas technology and solutions has increased. As such, oil and gas software companies have been on the forefront of this demand, developing new ways to help clients store gas, improve their operations, and save on expenses associated with poor storage and protection. Abshier Energy, a woman-led oileld and lightning protection company, provides innovative software and equipment to companies looking to improve the safety of their operations and efciently protect their biggest assets. Through their innovative solutions and diverse range of equipment, Abshier is striving to not only improve the state of oil and gas companies, but also the state of the industry and the environment. Susan Snyder, President of Abshier Energy, shared her thoughts on how innovative thinking and solutions can go a long way in a traditional industry that is ready for change. Speaking on Abshier’s mission and goals for the oil and gas industry, Snyder stated how they want to change the conversation from cost-driven justication of safety-related installations and focus the conversation on the application, quality control, and quality assurance of the installations that limit the risk of an unplanned discharge of static or lightning on or at a hydrocarbon generating site. She further explained that an unplanned discharge could create catastrophic environmental issues or loss of human life and thus, safety is the primary goal.Snyder shared how Abshier’s technology and solutions so far have helped improve the operations of oil and gas companies. She explained that through their reliability-focused installations and industry-consensus standards, they consistently challenge the market. Snyder explained the key differences that make Abshier and their products stand out from other oil and gas competitors saying, “We strive to be unique, quality centric and not focused on the dollar, but focused on the customer and our employee’s needs.” Being the president of a diverse, women-owned company, Snyder reected on the difculties she faced marketing Abshier’s oil and gas solutions and equipment in a generally traditional industry. She expressed “we’ve generally faced the same issues that other [minority] companies face, although it is a little disappointing to see that companies don’t take full advantage of diverse spending.”When asked what technologies or solutions Abshier is currently working on, Snyder explained that they are currently taking steps to educate customers on the application, use, and employment of their unique protection systems. In regards to oil protection and spill prevention, Snyder gave her perspective on the oil storage tank explosion that occurred in the Houston area. Asked what the oil and gas industry can do to minimize such risks, she expressed the importance of having procedures in place. “Documenting what you do, how you do it and qualifying those who interact with hazardous substances and processes are a must,” stated Snyder.In addition, Snyder described the type of solutions Abshier provides to clients to prevent such oil tank explosions. She stated that they provide static grounding, equipment grounding, system bonding as well as full testing to make sure that the installations are safe to operate and suitable for long term operation. “Maintenance is also a key factor that has to be added for an overall effective safety program,” Snyder further explained.Snyder was asked about future innovations and developments she’d like to see created in the future within the company itself or the industry overall. “Abshier Energy would like to see an industry evolution where justication of costs are squarely focused on safety and reliability from day to day operations of oil facilities,” Snyder shared. Per their own future goals, she stated how they would like to lead the industry to understand the impacts that static/lightning protection can have to the long-term survivability of oil and gas related process systems/equipment. “We understand life cycle costs of oil and gas related equipment and can help justify the longevity of these systems/components with a qualied maintenance plan/program,” Snyder further explained.Snyder expressed how there must be a mentality shift about how we install, operate and maintain our equipment and systems. “Equipment costs are increasing signicantly by the day, disasters aren’t cheap, bad PR is not good, and qualied manpower is not getting cheaper. Planning, documenting, and qualifying is a must,” stated Snyder. Photo courtesy of Samart Boonyang –

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Oilman Magazine / May-June 2019 / OilmanMagazine.com38There Is More than One Way to Practice Hydraulic FracturingBy Andres OcandoHydraulic fracturing is a highly practiced branch of the production discipline that is commonly used in sands with low permeability. Sometimes it is used for sand control operations and, in other cases, to increase production when it goes down.The functional principle of fracturing consists on using uid at a higher pressure than the breaking strength of the rock, and later lling this opening with proppant material (the one that sustains the fracture) to avoid its closure. The simplicity of the process does not reect the difculties that could appear in the way, because when talking about rocks, we also talk about a natural material that is not homogenous.The rst recorded fracturing was carried out in Kansas, in 1947. After the positive results were obtained, it became the perfect option to increase production quickly. Over time, improvements in the fracturing process began to appear, so did larger pumps, deeper depths reached, the fracturing uid ceases to be only water and the proppant stops being only sand.In addition to this, the fracture plans are coordinated by specialists with the creation of software that predicts the possible behavior of the rock. In turn, with the introduction of more technologies and professionals, the costs to fracture reach gures from $800,000, in simple cases, and $3,000,000 in more complicated cases with multiple stages.In spite of all this effort, it becomes impossible to completely correct the fractures, since currently there isn’t any mathematical complete software that can iterate the necessary times to predict the behavior of the rock before the pressure.However, there is more than one way to practice hydraulic fracturing. As a case study, here is an analysis for fracture optimization using geomechanics as spearhead. It takes place in west Venezuela, specically in an important eld that carries oil with 24 API° quality. The target deposit has petrophysical characteristics that do not allow the natural ow of crude oil.Its porosity is near 15 percent but with a permeability of approximately 8 cps, which makes it a perfect candidate for fracturing. Despite having more than 30 wells fractured in the past, you cannot nd one whose fracture lasts more than 1 month open.In addition to the aforementioned conditions, this particular reservoir has a geological feature known as migration, a process in which the target sand rises. In this case the migrated sands are eocenic, being originally in the past to depths between 12,000 ft to 15,000 ft; and they’re today at 4,000 ft, maintaining part of its characteristics as hardness, resistance, among others.Using the Marcelo Frydman methodol-ogy, the progress goes in the acquisition of data where a post-mor-tem analysis of fractures previously practiced was constructed, detailing what type of uid, proppant and pres-sure were used.With this information it was possible to know that the uid commonly used was water and the proppant was sand, due to the age of the fractures.From the structural model and analysis of drilling events, it was possible to identify important quantities of events that were repeated when drilling. It was also detailed how the formations were arranged layer by layer, understanding the migration effect suffered by the deposit.With the stratigraphic mechanics, thin sections were practiced, which is the microscopic analysis made directly to the core extracted from key wells in the deposit, noting the grain arrangement, the size of grains, and how the formation was supported, resulting in supported grain.It can be inferred from the size and type of grain what type of proppant should be used. With an average size of 15 microns, it makes reference to a ne sand type, therefore the proppant size should be close to 15 microns to avoid plugging in the pore throats built with fracturing.For the overburden pressure analysis, we used the available petrophysical records. In the following image (Chart 1) you notice how the reading of the density record (left) has a signicant change in behavior when entering the target area Eocene, due to the migration phenomenon mentioned above.With the result of the OBG (overburden gradient), the impact of the sands formation OILMAN COLUMNFlowchart to build an oil geomechanical model (Marcelo Frydman)Fine sections. Source: Ocando, Osorio 2015.

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Oilman Magazine / May-June 2019 / OilmanMagazine.com39OILMAN COLUMNmigration is noted because the density is greater, so there is an overload pressure much higher than expected at this depth.For the pore pressure analysis, different available records were used together with the operational events that they demarcate when the pore pressure infers, such as gas inux or circulation losses. In addition to pressure tests, these were used to calibrate the pore pressure in the target area, which allows predicting the pressure needed to reach the formation rupture in case of fracturing.Above (Chart 2), you can see the compaction train calculated with the available sonic registers (left), and the nal result of the pore pressure.Since there was a signicant number of well cores in the deposit area, geomechanical tests were carried out in the rock mechanics laboratory Miguel Castillejo at the Central University of Venezuela, with the support of Dr. Castillejo.To the different samples already cut, analyses were carried out as the following:Brazilian test: This is practiced to know the resistance to stress the rock has, an important value at the time of hydraulic fracturing, since it allows to know how the rock will behave after breaking.Unconned Compressive Strength (UCS): The exercise of submitting the core to a charge without connement in order to know the resistance to the axial pressure the rock has, by contributing the values of the Poisson coefcient. This helped to know if the anomalous overload pressure where the target formation exposed was affected. The result was negative, since being an Eocene rock, the Poisson coefcient obtained was 0.33.Triaxial tests (TRX): This test is practiced to simulate the reservoir pressure. The sample is conned and receives both vertical and horizontal pressure to obtain the value of the Young’s coefcient. In this case, it was used in an axial pressure close to the overburden to which the rock is subjected in the subsoil; which progressively increased the horizontal pressure to simulate the reservoir pressure and, subsequently, the amount of pressure necessary to propagate a hydraulic fracturing of the rock and the Young coefcient 0.63 x10 (6) psi.These results allow us to know what type of rock it is. The logic indicates that, since it is a rock belonging to the Eocene, it must be consolidated; but the results showed that it isn’t.Since there is an unconsolidated rock, fracturing processes change drastically. Another non-standardized test was carried out and, when rubbing the rock with the ngers in the broken sectors after the tests, an easy detachment of Chart 1: Density log vs OBG. Source: Ocando, Osorio (2015).Brazilian Test. Source: Ocando, Osorio (2015). UCS Test. Source: Ocando, Osorio (2015). TRX Test. Source: Ocando, Osorio (2015).Chart 2 Compactation train vs preassure. Source: Ocando, Osorio (2015).Continued on next page...

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Oilman Magazine / May-June 2019 / OilmanMagazine.com40OILMAN COLUMNthe grains was observed, which points at a low cohesion of the rock. This answers why, despite being Eoceanic, it is an unconsolidated rock.In the following steps the geomechanical model is concluded, obtaining the effort directions that allow to choose in which direction fracturing should be practiced. The theory orders that it fracture in the maximum direction. The value of the minimum effort (Sh) was also obtained, and the value of the maximum (SH) was estimated, and with the failure analysis using the Mohr Coulomb theory it was shown that the rock has a low cohesion.With the results obtained at the end of the geomechanical model, it can be seen how several questions around the fracturing were answered.In reference to the deposit geological conditions, it is noted that, in spite of migrating the formation and changing depth, it kept its main characteristics. The key formation efforts obey a normal regime, so the best way to practice the fracture is in a vertical well.To select the fracture uid, it is necessary to take into account the formation low cohesion, since a very invasive uid can cause sandblasting after fracturing. This sandblasting process was observed in the post-mortem analysis that took place in the beginning.A foam uid of low density stands out as the best option, in addition to a proppant with high resistance as a ceramic type, because the formation has a signicant overload effort added to the minimum effort. The aim is to avoid a Crushing effect (the pulverization of the proppant due to pressure conditions).With all of this it is possible to demonstrate that, although fracture simulators do not work properly in this case due to the abnormal conditions that this deposit presented, other disciplines such as geomechanics can provide a safer way for successful fracturing, and thus take care of the investment that the oil and gas industry undertakes in this method of stimulation.Andres Ocando is a petro-leum engineer who gradu-ated from Santiago Mariño University in Venezuela. His geomechanical-oriented thesis received an honorable academic mention. He currently has 4 years of experience working as a geomechanical and reservoir engineer at PDVSA. ADVERTISE WITH US!Are you looking to expand your reach in the oil and gas marketplace? Do you have a product or service that would benefit the industry? If so, we would like to speak with you!CALL US (800) 562-2340 EX. 1 We have a creative team that can design your ad! • Advertising@OilmanMagazine.comClassication of the type of rock according to the Young’s Model and Poisson’s Ratio. Source: Geomecánica aplicada a la Industria Petrolera (2013).Result of Mohr circle. Source: Ocando, Osorio (2015).

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Oilman Magazine / May-June 2019 / OilmanMagazine.com42DevOps Provides Digital Pipelines to Cloud BenefitsBy Aater SulemanAccording to the World Economic Forum, digital transformation could unlock approximately $1.6 trillion of value for the Oil and Gas industry, its customers and society. This value is derived from greater productivity, better system efciency, savings from reduced resource usage, and fewer spills and emissions. Yet, the journey to these digital transformation benets begins with a proverbial rst step which can be elusive for large oil and gas enterprises who have vast legacy technologies and complicated organizational structures to navigate. DevOps has emerged as a key process improvement that combines cultural philosophies, practices, and technologies that can help oil and gas companies address a spectrum of business initiatives by delivering services at a higher velocity. By innovating faster, oil and gas companies can more quickly achieve digital transformation benets, whether it be sending drilling platform IoT data to the cloud for predictive maintenance or creating new services to meet evolving customer expectations. Cloud technologies coupled with DevOps practices continue to dominate priorities for operators across the oil and gas sectors as they recognize their role in facilitating digital transformation to provide competitive and economic advantages. IDC Energy Insights predicts that by 2020, 25 percent of large oil and gas companies will have implemented a platform to develop, analyze, model, and simulate best practices in a cognitive-based continuous learning environment. Cloud-enabled technology, alignment between an organizations’ IT and business leaders, and DevOps practices are key enablers to transform IT service delivery. Let’s explore a few industry examples of how using DevOps to enable the cloud journey has helped organizations achieve enterprise agility, as well as ve tips to build a roadmap to success. Reduce Time to MarketDeeper data insights that can expedite resource exploration, drilling and production can be gained from cloud-enabled machine learning. Big data tools coupled with the cloud’s elastic resources and DevOps automation can speed processes – like reservoir simulations – to reduce time-to-decision and reach production faster. For example, Fugro, which collects and provides highly specialized interpretation of oceanic geological data, is able to keep skilled staff onshore using an IoT platform model. Referred to as OARS, its cloud-based project provides faster interpretation of data and decisions. In addition, new environments which previously took weeks to build, now launch in a matter of hours, providing better access to information across global regions. Lower Costs Through AutomationThe automation of IT operations and development practices help reduce costs by optimizing processes and greatly decreasing the potential for costly human error. With customized delivery pipelines, companies like Halliburton have been able to streamline complex workows, allowing it to obtain increasingly reliable real-time data to steer drilling operations, accelerate digital transformation and enable rapid entry into new markets. Operational workows can be optimized across the value stream – from pipeline monitoring to gaining a 360-degree view of the customer that allows you to better engage with them at the pump. Automation can help oil and gas companies prosper despite constantly changing market conditions. Take GE Oil & Gas, for example. The service provider moved 350 of its applications to Amazon’s cloud offering, AWS, over the course of two and a half years, which resulted in 52 percent reduction in IT costs. This savings, coupled with greater agility and speed to market, enables the company to compete even better in an industry experiencing immense market challenges. Obtain Security and ComplianceSecuring business-critical data while meeting compliance objectives set forth by NIST, ISO and others is foundational for every company, but especially for brokers and trading information organizations. For companies like OTC Global Holdings, balancing security with agility through cloud automation and security best practices enables these types of rms to remove errors, lower costs, increase speed, and better drive compliance. Getting Started with Cloud-Based DevOpsBy combining DevOps processes and cloud technology, oil and gas companies can innovate faster, and more quickly achieve digital transformation benets. Here are ve quick tips on where and how to start: Tip One: Begin with a pilot project. It’ll allow you to begin in a contained environment, testing change in a limited way. Find a small, impactful project that can be completed in eight to 12 weeks and will deliver measurable business impact. OILMAN COLUMNPhoto courtesy of Busakorn Pongparnit –

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Oilman Magazine / May-June 2019 / OilmanMagazine.com43Fifty years ago, in 1969, natural gas was found in tremendous commercial volumes at the GHK Company #1 Green well, completed at a depth of 24,147 feet in the Anadarko Basin. This is approximately a mile southeast of Elk City, Oklahoma, my hometown. In those fty years, thanks to the beginning of exploration in the Anadarko Basin, natural gas has become a much needed fuel for power generation and transportation. The total depth was 24,454 feet. GHK began drilling the well in 1967.As described in the book entitled The Grand Energy Transition, “the #1 Green broke virtually every technological record of its time. It was by far the highest-pressure well ever drilled in the world, the second deepest. Cameron Iron Works specially built the largest and highest-pressured gas wellhead ever constructed to contain the highest pressured gas well in the world (15,130 pounds per square inch at the surface). Because we had encountered such a high world record pressure, there was no pressure gauge in the world to measure it. Luckily, one of our partner companies, Amerada, had a research and development facility in Tulsa that worked with high pressure gas. It constructed the rst-ever 20,000-psi gauge” – “The #1 Green well became the rst well to establish the prolic gas-producing capability of the Deep Anadarko Basin, thereby opening the province to billions of dollars of subsequent deep gas development.” Six years later, 1975, after the #1 Green well discovery, I rst recognized what a strong force OPEC was while working for then U.S. Senator Dewey F. Bartlett. Senator Bartlett had asked several of his staff members including myself to review remarks he was going to make in Norway before OPEC ofcials. Only a year before, the energy industry had been deeply impacted by the 1973-74 oil embargo. It was obvious that the energy industry and our nation’s petroleum security would be dealing with major issues during my lifetime. Because of my interest in energy development, two years later, in 1977, I began working as a petroleum landman in the Anadarko Basin, purchasing oil and gas leases in locations where some of the deepest natural gas wells were drilled. Natural gas and all forms of energy was necessary then and will denitely be necessary in the future. A strong natural gas industry means more jobs, and a more secure economy. It is extremely important that the U.S. be in a strong position of securing energy reserves within its own boundaries. National Energy Talk (NET) - National Energy Talk, an Energy Advocate Initiative, was launched July 31st, 2017 in Elk City, Oklahoma and meetings have been held in Tulsa, Edmond and Oklahoma City along with presentations in Houston, Denver and other cities. In 2019, NET will continue its efforts as a platform engaging a national energy dialogue. Go to Facebook: National Energy Talk to support/learn more about NET. 50 Years Later: The Impact of Discovery By Mark A. StansberryMark A. StansberryOILMAN COLUMNTip Two: Identify people within the organization who will form your CoE (Center of Excellence). Experience tells us they are people who work effectively with ambiguity, have a bias toward action, are technically skilled, and embrace mitigated risk-taking. The team should be DevOps advocates, cross-functional, and empowered to capture best practices from the pilot project. Tip Three: Following a successful pilot project, you can begin the process of scaling DevOps. Conduct a thorough portfolio assessment; DevOps efforts should focus on applications that contribute to revenue and should be invested in and therefore migrated to the cloud. Tip Four: With several migration options - lift and shift, replatform and refactor - it’s important to understand the pros and cons of each approach per application. Analyze cost in terms of development resources and business interruptions that may be required from a signicant rewrite. Tip Five: Establish automation with technology pipelines that allow for easy repeatability. Your DevOps platform should feature technologies and processes for continuous testing and delivery, a landing zone, and security.DevOps is equal parts people, process and technology. With a CoE in place to help train teams, a solid cloud-based DevOps platform, and automation to streamline processes and ensure they are followed, oil and gas enterprises have a roadmap to digital transformation success with DevOps.For example, TechnipFMC, a renewable energy leader, assessed that it had two parallel goals: It wanted to use an AWS cloud migration strategy as an opportunity to overhaul its business systems and in the process, the company wanted to build standardization. Moreover, TechnipFMC aimed to increase developer agility, grow global access for its workers and decrease capital expenses. Based on its application portfolio TCO analysis, a lift-and-shift migration approach was pursued. With 80 percent of its applications now dened by a small number of templates, the company has standardized its software builds, ensuring security best practices are followed by default. The enterprise has increased its time to innovation, speed to market and operational efciencies.With continued market volatility, and growth in competition to meet evolving customer expecta-tions with new services, the time to fuel growth through enhanced productivity and efciency has never been more at hand. While the oil and gas industry has traditionally focused on operational efciency, digital transformation offers the ability to more closely tie data inputs, and business intel-ligence, allowing the industry to further enhance efciency, making smarter decisions, faster. Aater Suleman is CEO and co-founder of Flux7, an IT consultancy providing DevOps consulting, cloud architecture, and migration services. For more information, please visit www.

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Oilman Magazine / May-June 2019 / OilmanMagazine.com44OILMAN COLUMNTransforming Fireproofing in the Downstream By Sarah SkinnerIn the event of a hydrocarbon plant re, unprotected structural steel will only last a few minutes before it collapses. Whether it is a pipe rack or vessels, heat could lead to the catastrophic collapse of the structure, making it crucial to protect it. Various reproong systems have been utilized over many years to protect these steel structures. Surprisingly, there are currently no laws making it mandatory that petrochemical companies reproof their steel, but for the most part, they all do it for practical purposes. Because it just makes sense to protect your assets. Alfred Miller Contracting (AMC), headquartered in Lake Charles, Louisiana has been in business over 70 years and they reproof more steel than anyone in North America. At their yard, they boast a highly efcient, climate-controlled reproong shop featuring two, 6,000 square-foot, moving buildings—rather than move the steelwork, they move the process over the steel. Their Toyota-esque Lean Production System enables them to process over 1,000 tons worth of steel at any given time and continue working in any conditions.The idea of the moving buildings was born in 2006 with the Motiva project. At the time, it was the rst mega-project and the largest in the gulf coast region. AMC had to gure out a way to supply that volume of reproong because it had never been done before in such a tight schedule. They followed the lean manufacturing principles modeled after Toyota, which provides the best quality, lowest cost and shortest lead time through the elimination of waste. They have several patents relating to reproong including a patented, UL certied corner bead which increases accuracy and productivity at the same time. There are three different ways to reproof steel and the one used depends on the preference of the client and the requirements of the project. There are concrete, light-weight cementitious and epoxy intumescent applications.• Concrete: 2-inches thick, heavy, no UL certication.• Lightweight Cementitious: ~1-inch thick, lighter weight, less durable, economical.• Epoxy Intumescent: ~3/8-inch thick, reacts with heat to create a foam, which protects steel from heat source, durable but expensive.As previously stated, there are no standards and/or regulations on reproong making it mandatory that certain guidelines are put in place and followed to avoid potentially hazardous and expensive mistakes. There is a network of people that are passionate about maintaining the integrity of reproong standards and in 2016 they formed an organization called PFPNet. PFPNet is a non-prot, subscription-funded body that was established to increase understanding and raise competency across the whole hydrocarbon passive re protection industry. They do this by bringing in industry experts to consolidate their experiences to determine the best practice for application methods and the appropriate resources to use.Simon Thurlbeck, one of the Founders of PFPNet and now Director, explains, “Having worked in the eld of re and explosion risk management in major hazard facilities for many years, it was obvious that those involved with hydrocarbon PFP needed a collective technical organization to identify and capture good practice, and produce guidance and training that the whole industry could endorse. The idea was born from a realization that the industry was asking the same questions that have always been asked, and often making the same mistakes, and that this experience was being lost as people moved on or retired, In setting up PFPNet we wanted to rectify this situation, and have industry identify the issues and provide the expertise that we could then capture through work programs voted for by the Members.”Bob Pool, AMC’s Executive Vice-President is on the steering committee for PFPNet and was recently elected to the board of directors for the National Fireproong Contracting Association. Because of Bob’s experience and associations within the industry, AMC has a resident reproong expert on hand and available to them at all times. “Fireproong is a permanent part of the structure and you only get one chance to do it right, so we’ve invented and tested several innovative systems which all help improve the accuracy and efciency of the reproong. The consequences of getting it wrong are extremely high, so you want to make sure it is applied by applicators who understand the right reproong system for the situation and know how to do it correctly,” says Pool.The reproong effectiveness is tested at UL (Underwriters Laboratories) in Northbrook, Illi-nois. In a protected facility, reproong products with different thicknesses are applied to mimic what is applied to the structural steel on real world projects. They run re tests to establish the exact time before structural failure occurs. This provides the industry a realistic expectation of protection that they can offer their clients. AMC is a company that never rests and sees itself as a solutions provider. By no means will you ever catch their president, Philip Miller, letting the grass grow under his feet. Whether it’s precast buildings, pipe racks or reproong, Miller believes that there is always a way to make something more efcient and more cost effective. The innovation truly never stops and Alfred Miller Contracting is revolutionizing, not just the re proong industry, but the entire petrochemical industry as a whole. Left: AMC Fireproong Yard / Right: Heater Legs – Photos courtesy of Alfred Miller Contracting

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ALFREDMILLER.COMTHINK PRODUCTIVITYWE DO MORE WITH FEWER MAN-HOURS TOIMPROVE PRODUCTIVITY USING OUR INNOVATIONS RIGHT HEREIN AMERICABorn and bred in the Downstream Oil and Chemical Construction industry, Alfred Miller Contracting shreds the trend of building petrochem plants with a massive amount of manpower. Our automation, technology, and lean construction management principles are the better solution for labor shortages.FIREPROOFINGBUILDINGSPRECAST

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November 5-6, 2019OILMAN CONNECT is a two-day virtual trade show dedicated to connecting businesses in the Oil and Gas Industry.Feature your products, services, and technologies while you network with other industry experts, attend educational seminars, and track all your leads and data.Visit for more information800-562-2340 Ext 4 • info@OilmanConnect.comEARLY BIRD SPECIAL Book a Virtual Booth by May 31 and receive 10% OFF!