Oilman Magazine Nov/Dec 2019 : simplebooklet.com

Oilman Magazine / November-December 2019 / OilmanMagazine.com1IN THIS ISSUEFeatureProgressive Strides in Unconventional Oil and Gas RecoveryBy Sarah Skinner - pages 22–24In Every IssueLetter from the Publisher – page 2OILMAN Contributors – page 2OILMAN Online // Retweets // Social Stream – page 3Downhole Data – page 3OILMAN ColumnsBoone’s Impact and Vision!: Mark A. Stansberry – page 9Automation and Economy: Driving Principles of the Modern Oil and Gas Industry: Eric R. Eissler – page 16Pipeline Technology: Data’s Role in Midstream Pipeline Segmentation: Tonae’ Hamilton – page 28From Gemini Corporation to Gemini Fabrication: Recovery after Receivership: Tonae’ Hamilton – page 36Most Common Oil and Gas Cybersecurity Threats: Emmanuel Sullivan – page 45Pipelines as Critical Infrastructure: Jason Spiess – page 46 Guest ColumnsDriving Offshore Growth with Satellite Communications: Morten Hansen – page 4A Closer Look at Remote Operations Centers: John Evans and Matthew Routh – page 6Drilling for IoT Data Insight: Michael Skurla – page 6Four Steps to Advanced Data Science in the Oil and Gas Industry: Stuart Robertson, Nilesh Dayal, Franco Ciulla and Amar Gujral – page 10Five Essential Mobile Device Management Features for Oil and Gas Personnel: Anson Shiong – page 12Machine as a Service Will Be the Star of Industry 4.0: Petteri Vainikka – page 14What Safety Measures Should You Take for Lone Workers: John Carvalho – page 17The Case for AI in Planning and Forecasting – page 18Revolutionary Evaporation System Cuts Costs To $.006 Per Barrel And Protects Environment From Particulate Contamination: Robert Ballantyne – page 20The Plaza Group Dening and Embracing the Core Values: Lillian Espinoza-Gala – page 25Conductor Supported Platforms: Demystifying the Industry’s Best Kept Secret: Rob Gill – page 26Coarse Filtration: The “First Line of Defense” In Protecting Oil and Gas Processes: Del Williams – page 29Virtual Reality is Not Just a Game, but Training: Andres Ocando – page 30The State of Water 2019: How to Sustain the Oil and Gas Industry’s Lifeblood: Blythe Lyons, John Tintera and Kylie Wright – page 32Whose Milkshake is Whose?: Pennsylvania Supreme Court Considers Whether the Rule of Capture Applies to Hydraulic Fracturing: Tony Guerino and Liz Klingensmith – page 34Robotic Process Automation: Four Key Considerations for Oil & Gas: By Steven Bradford and Kent Landrum – page 38Why bbl? Energy Units in the USA and Other Countries: Eugene M. Khartukov – page 40

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Oilman Magazine / November-December 2019 / OilmanMagazine.com2Gifford 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 www.energylawroundup.com, and a video series on effective legal writing, available at www.theartofthebrief.com.Jason 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. The oil and gas industry is experiencing signs of a slowdown with reduced drilling rigs, E&P nancial distress, reduced headcount and a pull back from investors. Industry experts agree that this is part of a normal cycle in the course of oil and gas business. However, the overall theme is that business activity in the industry will slow down in Q4 and as we head into 2020. Let’s unpack some of this gloom. From a recent Baker Hughes rig report, the U.S. rig count fell for 7 weeks in a row from 898 down to 855 as of this writing. A handful of exploration and production companies led for chapter 11 bankruptcies during Q3. Some notable independent E&P companies ling bankruptcy include Sanchez, Halcon and Alta Mesa. It has been reported that a few could lead to liquidation and not recapitalization with creditors. The U.S. unemployment rate fell to 3.5 percent in September and employers continued to add jobs. Although, in the oil and gas sector, the industry shed about 5,000 jobs in Texas alone over the past three months. Finally, numerous reports indicate that investors are nervous about investing more into shale properties and would rather see operators control capital expenditures, produce more product and increase cash ow. There are positive signs out there. Overall the Permian Basin is doing well, in fact New Mexico added ve drilling rigs in October. Much needed pipelines to drive product to market have come online and several are due to start next year. There are also several LNG terminals in development and renery expansions in the Gulf Coast region. NOVEMBER — DECEMBER 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 Diana GeorgeTo subscribe to Oilman Magazine, please visit our website, www.oilmanmagazine.com/subscribe. 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) 562-2340Original cover photo by Alexey Zaytsev – www.123RF.comLETTER FROM THE PUBLISHERCONTRIBUTORS — BiographiesEmmanuel Sullivan, Publisher, OILMAN Magazine

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Oilman Magazine / November-December 2019 / OilmanMagazine.com3Week Ending November 1, 2019DIGITAL DOWNHOLE DATAGulf of Mexico: 21Last month: 22Last year: 18 New Mexico: 108Last month: 113Last year: 102 Texas: 416Last month: 414Last year: 533 Louisiana: 56Last month: 55Last year: 62 Oklahoma: 51Last month: 63Last year: 144 U.S. Total: 822Last month: 855Last year: 1,067OIL RIG COUNTS*Source: Baker HughesBrent Crude: $60.39Last month: $60.06Last year: $71.25 WTI: $55.60Last month: $53.60Last year: $63.67CRUDE OIL PRICES*Source: U.S. Energy Information Association (EIA)Per BarrelGulf of Mexico: 62,187,000Last month: 47,641,000Last year: 60,602,000 New Mexico: 29,019,000Last month: 27,680,000Last year: 22,052,000 Texas: 158,756,000Last month: 155,719,000Last year: 140,226,000Louisiana: 3,844,000Last month: 3,369,000Last year: 4,083,000Oklahoma: 17,438,000Last month: 17,397,000Last year: 17,431,000 U.S. Total: 383,317,000Last month: 364,736,000Last year: 352,176,000CRUDE OIL PRODUCTION*Source: U.S. Energy Information Association (EIA) – August 2019 Barrels Per MonthGulf of Mexico: 85,774Last month: 65,360Last year: 94,309 New Mexico: 160,117Last month: 150,181Last year: 132,412 Texas: 777,658Last month: 763,333Last year: 669,265Louisiana: 279,278Last month: 269,052Last year: 229,816 Oklahoma: 265,828Last month: 269,170Last year: 259,041 U.S. Total: 3,115,678Last month: 3,040,996Last year: 2,814,741NATURAL GASMARKETED PRODUCTION*Source: U.S. Energy Information Association (EIA) – August 2019Million Cubic Feet Per MonthConnect with OILMAN anytime at OILMANMAGAZINE.com and on social media RETWEETS@OilmanMagazine#OilmanNEWSStay updated between issues with weekly reports delivered online at OilmanMagazine.com SOCIAL STREAMfacebook.com/OilmanMagazine

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Oilman Magazine / November-December 2019 / OilmanMagazine.com4OILMAN COLUMNDriving Offshore Growth with Satellite Communications By Morten HansenDigitalization in the offshore market has begun to ramp up, with new technologies poised to deliver substantial costs savings and improved protability to the industry. However, these technologies depend on the existence of robust and reliable connectivity – a challenge for many offshore operators, particularly as they venture into deeper waters that are frequently out of range of traditional terrestrial networks. Today, satellite communications are supporting rig and platform owners in powering an increasingly diverse range of applications while providing value and critical support to offshore businesses. High-quality, low-latency connectivity to offshore sites is enabling digital technologies such as real-time recording of eld data, digital-twin, remote operations, which are all accelerated by the improved communications providing a major impact on operational efciencies and crew safety. The Connectivity RevolutionUntil recently, the offshore industry was limited to the use of GEO (Geostationary) satellites for the transmission of data to rigs and platforms at sea that were beyond the reach of bre or microwave networks. While GEO provides reliable and consistent connectivity, new digital applications leverage underlying technologies such as analytics, mobility and the cloud – technologies that rely on latency that is lower than GEO is able to provide. The availability of the O3b MEO (Medium Earth Orbit) system in 2014 was a game-changer for the offshore industry. This constellation operates at a lower orbit than GEO systems, providing latencies of up to 150 milliseconds for a round trip data transfer, compared to almost 600 milliseconds per round trip for GEO. The high throughput capacity and low latency of the O3b system opens the door to a range of digital capabilities that would not have been possible earlier, including applications such as real-time transfer of eld data, virtual modeling of offshore assets and wireless sensor monitoring for better reservoir management, as well as IT services such as desktop virtualization, remote server access and cloud-based storage, with the end result being improved production and lower operating costs.MEO-level latency and throughput enable an improved experience for crew wishing to remain entertained during their downtime and connected to family and friends while offshore – a key factor in the industry’s efforts to recruit and retain top talent.Being the only satellite operator to offer both GEO and MEO high throughput capacity, SES combines the O3b MEO system with its wide-beam and high-throughput GEO assets to create an even more compelling value proposition for offshore operators, delivering network resiliency that is particularly critical for deep-water sites dependent on reliable connectivity. Building the Path ForwardThat high level of connectivity will become even more critical for the offshore industry as it adopts IoT and cloud. Sophisticated sensor technologies mean the OT (Operational Technol-ogy) realm is becoming increasingly connected, feeding critical data into onshore IT systems that previously operated as isolated business func-tions, while cloud computing platforms allow companies to more efciently and cost-effectively process and analyze that data. The cloud also enables the cost-effective extension of onshore IT systems such as human resources, training and logistics to offshore sites, paving the way for safer and more efcient operations.Cloud-optimized connectivity will be a critical part of that transformation, including strategic partnerships with leading cloud service providers. For example, SES has established these relationships, bringing the capabilities of the major cloud platforms such as IBM Direct and Microsoft Azure ExpressRoute to offshore sites. Cloud services can be provisioned over dedicated MEO or GEO links, or a combination of the two, delivering a tailored service with the latency, availability and coverage that is specic to the enterprise and application requirements, all backed by solid SLAs. The rollout of SES’s next-generation MEO constellation, O3b mPOWER, in 2021 will further strengthen the ability of offshore providers to capitalize on cloud services by delivering multi-gigabit, low-latency connectivity ideal for high-throughput applications and “bursty” cloud workloads. Looking AheadProtability and business continuity in the oil and gas sector will be inextricably linked to its adaptability and the tools that make it possible. High-speed, reliable and scalable connectivity solutions are crucial to enable the right set of applications that can fully digitalize operations. The next generation of satellite technology is essential to support the industry and open opportunities for its expansion and growth, while reducing complexity and risk. The demand for real-time data is growing, and it is critical that the offshore industry continues to keep pace, using the surging amounts of information to the best advantage for their individual operations. Morten Hansen is responsible for the energy segment market management of SES Networks, a provider of global managed data services. He holds extensive experience in the remote communications and information technology services industries. He is currently leading the strategy, development, and positioning of products, services and solutions into the energy market vertical, including onshore/offshore oil and gas, resources/mining and related customer applications. SES is the only satellite operator to offer both GEO and MEO high throughput capacity. Photo courtesy of ArianespaceO3b mPOWER will further strengthen the ability of offshore providers to capitalize on cloud services by delivering multi-gigabit, low-latency connectivity.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com6OILMAN COLUMNA Closer Look at Remote Operations CentersBy John Evans and Matthew Routh Operators go to great lengths to accurately position wells and avoid well collisions as they continue to search for ways to manage oileld drilling operations effectively to maximize performance and production, while also lowering costs. As a result of these trends, operators and oileld service providers (such as Gyrodata) have introduced new drilling technologies and services into the market that help make drilling opera-tions more efcient. ROC (Remote Operations Centers) in particular have become employed on a more regular basis. These centers enable opera-tors to apply continuous improvements in real time to address a wide range of problems so they can optimize drilling operations.ROCs are multidisciplinary collaboration centers that strive to strike a balance between having the right people, technology and processes in place to monitor wells in real-time from off-site locations to maximize operational potential and better ensure service quality. Before ROCs were introduced into the industry, operators faced numerous challenges when drilling in crowded oilelds or in remote areas that had wellbore stability and service reliability issues.Over the past ten years, ROCs have transformed dramatically, as their capabilities have expanded thanks to live data feeds, powerful data analytics, and increased computing capabilities. Drilling and well planning engineers are able to provide new solutions to issues that come with multi-well pad drilling by optimizing drilling performance and avoiding wellbore collisions through real-time correspondence with the rigs. ROCs have made de-manning onsite MWD (Measurement While Drilling) services and remote monitoring of operations possible, which has greatly reduced the overall safety liability on a rig location. This also allows subject matter experts to extend their knowledge and skills across several rigs for bet-ter performance and utilization. Streaming live data into analytical software solutions increases drilling efciencies by providing optimization specialists the capabilities to make recommenda-tions and adjust drilling parameters in real-time. What Remote Operations Centers EntailAt ROCs, drilling engineers monitor and try to determine what is occurring during drilling operations to ensure well plans are appropriately followed, risks are mitigated and challenges are effectively handled. The centers can achieve the following:• Reduce the likelihood of events that cause non-productive time• Reduce costs by improving operational efciency• Help operators gain a better understanding of complex well sites• Utilize advancements in technology to obtain 3D visualization and improved models• Prevent wellbore collisions• Increase the effectiveness of drilling operationsROCs include data management, eld communication as well as remote visualization services. They basically serve as an extension of a well site. Experts at the centers analyze real-time data streams of parameters that are measured both on surface and downhole when drilling. ROCs also provide KPI (Key Performance Indicator) solutions for visualizing, benchmark-ing and reporting. This allows operators to gain deep insights into their operations so they can do a better job of dening lost time and reduce nonproductive time. Experts at ROCs are well positioned to utilize advanced analytics and customizable alerts to help operators predict and prevent problematic events from occurring. With real-time predictive road maps that the centers offer, operators are able to optimize perfor-mance, correlating live and historical data that can help determine local best practices. How Remote Operating Centers are Contributing to the Drilling Industry’s TransformationOver recent years, the industry and technology has evolved, as oil and gas companies have been at the forefront of digital operations. ROCs are proof of the trending digital transformation that the industry is currently facing. Drilling processes have become more modernized with a broader variety of analytics being tracked and monitored. Dynamic, real-time alerts allow operators to make important decisions regarding their opera-tions so they can avoid being unprepared for challenges. This is helping to lower overall well costs and shorten the number of drilling days.Modern technology and equipment has given the industry the ability to remote into equipment and gain a better understanding of operations. ROCs help operators escalate different issues and communicate more effectively. These centers are also driving more standardization in the industry so operators can really measure their performance. They allow operators to see how they are performing against best practices and indeed, local best practices.ROCs have also helped push drilling performance to the next level. Now the industry is having more asset, eld and data management in place. Data is also coming in from multiple sources, including surface equipment, downhole drilling equipment, manual reports as well as asset management software. This helps drive effective all-encompassing operations -thus helping operators understand and execute best practices to improve operating performance.As new technologies continue to evolve, so do technicians’ skill sets. Field engineers are being utilized in remote centers – not just technicians and mechanics out in the eld. Field engineers have been required to learn about drilling automation, coding, and programming. This has changed the role of the technician. As a result, oileld service companies that have ROCs have been required to have training programs that truly support the changing dynamics of the industry. Technicians and eld engineers have been required to become more competent and develop new areas of expertise.By leveraging the strengths of experts, ROCs have caused the drilling industry to more effectively reach oilelds’ true potential by improving operational efciency and lowering costs. This valuable service is saving the industry millions while also promoting safer and more effective drilling operations. Overall, integrated operations at the centers is causing signicant improvements in reserve recovery.About Gyrodata’s Guide CenterWhen you rst step into Gyrodata’s ROC, the Guide Center, you feel like you have entered a smaller version of a NASA control room. Wall-to-wall screens (with data displayed in a clean An operator drilled a 9,015-foot lateral in one run by adopting a total system approach utilizing Gyrodata’s RSS, mud motor and MWD.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com7OILMAN COLUMNand sharp way) gives the center a futuristic vibe. In a shared ofce space, drilling engineers are busy at several work stations where they carefully evaluate data and drilling performance so they can develop effective strategies and procedures that will help make drilling processes more ef-cient. Real-time models (which are vital tools for planning a well) are constantly updated with data from wells. At the 24/7 center (which opened in 2018), multi-disciplinary teams deliver real-time monitoring services and support for well plan-ning, well engineering and optimization services.The Well Planning Operational Technical Support group applies their expertise regarding various types of well geometry and elds to optimize solutions for wellbore/pad design and well permitting. The company’s anti-collision and real-time monitoring services provide clients with the safest recommended path to avoid offset wells or other potential hazards. Engineers specically leverage their expertise in tool error modeling to aid operators in reducing the ellipses of uncertainty. This allows operators to safely navigate through highly populated pads or elds without having collisions.Gyrodata survey management experts at the Guide Center also utilize software solutions that improve MWD accuracy by providing BHA (Bottom Hole Assemble) magnetic corrections and survey analysis, which also ensures accurate wellbore placement. Well engineering consultancy services help protect drilling operations. They involve torque and drag modeling, hydraulics modeling, critical speed as well as BHA analysis. The center also offers real-time optimization. Experts at Gyrodata dene pace-setter wells with optimized BHAs and drilling parameters for each section of the well that serve as a roadmap for directional drillers to follow.Experts at the Guide Center are involved in data acquisition, modeling, performance optimization as well as local best practice validation. Their workows involve managing a massive amount of data, scenario modeling, eld target planning as well as risk analysis. All of these factors help them determine what exactly is going on with a well, which also helps operators make vital decisions regarding their drilling operations. The Guide Center also serves as a data center, where experts store information on how wells perform for future reference and KPI analysis. The data allows experts to analyze operational parameters to identify trends, which in turn allows them to determine techniques that enhance drilling performance.At the center, experts also examine groups of customer specic wells that are in a close proximity of each other to determine if they are illustrating similar characteristics. Experts strive to expand on the successes of the pacesetter wells and focus on the limitations of the slower, more challenging ones. This data helps them with future planning and drilling. Previous knowledge allows experts to create an effective road map for operators.Case StudyA major operator planned to drill a Wolf Camp, A well in the Permian Basin. Experts from Gyrodata obtained customer offset data from the Permian Basin and reviewed it for the planned work. Based on the expert’s historical data of conventionally drilled wells in this formation, they were able to apply the knowledge to select the proper conguration for motor assisted RSS (Rotary Steerable System) and MWD tool selection. A directional drilling team applied the derived road maps and parameter recommenda-tions when drilling the entire well.Because of what was learned from the study of the historical data that lead to proper congura-tions, the customer was able to successfully drill a 9,015-foot lateral in one run with the GyroDrill Motor assisted WellGuide RSS in 43.84 drilling hours at an average rate of penetration of 205.8 feet/hour. Due to these measures, the operator saved about 9 days of rig time and almost half a million dollars in drilling costs. ConclusionOverall, ROCs offer modelling and drilling performance analysis, which helps improve the safety and quality of both ongoing and future operations. They also offer an opportunity for improved decision-making in the context of real-time asset management. The centers are improving drilling times signicantly for peak performance while also reducing non-productive time. They have a circular loop of obtaining and reviewing data and utilizing it to aid effective decision making so operators can run protable and efcient drilling operations.John Evans has over 30 years of experience in the oil and gas industry. He is the Gyrodata Product Line Manager for rotary steerable system (RSS) and measurement-while-drilling (MWD) services. John manages the technology portfolio and operations technical support (OTS) plus the remote operations Guide Center that provides well planning, well engineering and drilling optimization. John’s primary areas of expertise include RSS, drill bits and drilling technologies, MWD, logging-while-drilling, as well as drilling engineering and optimization.Matthew Routh has been involved in the oil industry for almost 24 years. He has spent the last 7 years with Gyrodata, with his most recent role being the Guide Center manager. Matthew graduated with a mechanical engineering degree from the University of Louisiana and has been involved in several aspects of the oil industry, including surveying, directional drilling, well planning, well engineering, and drilling optimization. Remote Operations CenterGuide Center - Matt Routh Working

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Oilman Magazine / November-December 2019 / OilmanMagazine.com8OILMAN COLUMNDrilling for IoT Data Insight By Michael SkurlaDigital technologies have been a critical factor in the oil and gas industry’s transformation. Beyond transforming the industry, the integration of “smart” technologies now has the potential to create additional cost-savings from existing capacity. McKinsey research conrms how effective use of digital technologies can “reduce capital expenditures by up to 20 percent” while reducing operating costs “in upstream by 3 to 5 percent and by about half that in downstream.” While integrating modern technologies isn’t a new phenomenon in the oil and gas sector, the advent of advanced sensing devices, and analytics from IoT and cloud services, offer signicantly more data-driven, predictive maintenance possibilities. Recent research by the Swedish analyst rm Berg Insight predicted that the installed base of wireless IoT devices in the global oil and gas industry – at a CAGR (Compound Annual Growth Rate) of 6.8 percent – will reach 1.9 million units by 2023. The report sites remote monitoring of tanks and industrial equipment in the midstream and downstream as the most common applications for wireless solutions in the oil and gas industry.With millions of physical devices connected to the Internet - from sensors, to equipment, to vehicles – collecting and sharing data across the devices, the avalanche of generated data from these devices must be captured. And the data must be transformed into comprehensible analytics to enable cost-effective preemptive operations and equipment maintenance to drive down operations cost, while increasing efciency. With distributed mission-critical facility operations across regions and continents, the oil and gas operators and executives must have holistic, real-time access and views across all their operations to prevent unforeseen risks. Tapping into digital technologies for advanced IoT analytics can not only contain operational costs, but allow for poised, data-driven business decisions.As the McKinsey study underscores, assuring the most consistent up-time alone can reduce costs by up to 27 percent while also increasing energy efciency by as much as 10 percent.Crude IoT Data into Rened “Smart” Business DecisionsWith IoT devices well integrated into all aspects of the oil and gas industry operations – from renery to pipeline monitoring to worker safety to offshore rigging – operators have full access and holistic views into their operations and across all sites. For instance, sensors installed on oil tanks can help monitor and expedite maintenance issues before there are irreversible problems with the tank. Likewise, sensors on ber optic cables can help map out oil exploration drilling sites to increase outputs without wasting time drilling in dry areas. But keep in mind that billions of data points generated from these IoT devices are similar to crude oil – they are crude data. Only when the crude data is rened by collecting, organizing and delivering actionable analytics can they be valuable business intelligence tools. Only then can operators tap into the rened data to determine where operational tasks can be improved – from nding exact drilling sites, to increased productivity to ensured employee safety and more. Facilities and sector operators can easily use interoperable IoT tools to empower existing advanced technologies and systems. They don’t need to overhaul their existing systems and sub-systems for new IoT connectivity.Drilling into IoT Platforms BenetsEdge IoT Platforms deployed at each site can seamlessly integrate into existing production and systems – without major congurations. There’s no need to bridge custom, development, programming, and proprietary technology. Its seamless integration into all existing systems quickly expedites data mining capabilities from all operations sites across regions and continents.Operators can start collecting data from sensing systems to access a full portfolio of analytics of the data that can be rened for scalable deployment on and offshore. With much of the oil and gas industry work conducted in far-to-reach spots, the IoT platforms can offer full visibility into hard-to-reach and monitor areas. Resolving connectivity issues – from tankers in middle of the ocean, to workers at far-reaching oil rigs to pipelines in the desert – allows operators to quickly detect problems or maintenance needs. Operators can swiftly mediate alerts and ag repairs before anything percolates into a major risk or disaster.The IoT platforms can expedite provisions of appliances across various regions and distributed sites by collecting and organizing all data. The data can then be stored securely in a single, comprehensive, private data collection repository – and be easily accessible in the cloud. Once stored, the collected and organized data can be easily mined for analytics, UX tools and facility management applications using either existing in-house tooling, or through other cloud-based tooling available from a multitude of micro-service analytics and visualization providers. The rened value of the data is gained with clear, actionable analytics that can help propel best business decision making. With real-time views of all the IoT devices connected across all the operational sites, oil and gas operators and executives can gain unprecedented access to:• Gather real-time data and analytics from

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Oilman Magazine / November-December 2019 / OilmanMagazine.com9OILMAN COLUMNinaccessible sites – from offshore rigs to tankers – maintaining full control of operations and maintenance• Expedite monitoring of renery and pipeline systems – without having “boots on the ground” or “under the ground/oceans” • Quickly resolve problems with preemptive measures – such as shut down or delay work to repair malfunctioning equipment or leaking pipes, etc. - before they erupt into major safety risks, PR nightmares and irreversible nancial damage• Unify separate monitoring systems, regardless of sub-systems, to gain sustainability and efciency by reducing costly service/repair calls• Tap advanced analytics to help reduce costs with predictive maintenance which the McKinsey report sites can decrease maintenance costs by up to 13 percent – not to mention gaining increased energy efciency• IoT data for improved customer service and customer relations and marketing strategy – by determining price-points that appeal to customers, or efcient supply chain management to improve “location planning and route optimization” as sited in the McKinsey reportToday’s IT-centric IoT ecosystem eliminates the legacy challenges of lack of visibility and access to valuable data from distributed sites. Now multi-site, distributed enterprises can quickly obtain collective monitoring without any disruptions to the efciency of their existing subsystems. Managing a portfolio of IoT connected, distributed mission-critical facilities with an IoT platform enables data mining for actionable analytics. Easily scalable across hundreds and thousands of distributed portfolio locations, the platform enables oil and gas operators to harness rened data to establish solid data-driven business decision advantages. More critically, the oil and gas industry can alleviate its top three risks – economic, political and environmental – by utilizing the valuable rened actionable analytics. Failing to harness these advantages is a risk no enterprise can afford to take in today’s volatile business world. Michael C. Skurla is Director of Product Strategy for BitBox USA, which offers a single, simple and secure IoT platform solution for enterprises to collect, organize and deliver distributed data sets from critical infrastructure with a simple-to-deploy Edge appliance with secure cloud access. Twenty-ve years ago, Boone Pickens sent me a letter describing his passion for natural gas and America’s energy future. I share with you a portion of the letter, dated October 7, 1994: “There is a lot of focus these days – as there should be – on the tremendous costs facing business and local governments as a result of the 1990 Clean Air Act. Many of the proposed solutions are so ridiculous or technologically far-fetched that they deservedly short shrift in the environmental debate. It seems a great public service can be done by advocating realistic pollution alternatives and when it comes to transportation, that solution is natural gas and natural gas vehicles.Natural gas is the cleanest fossil fuel in the world, burning 80-90 percent cleaner than gasoline at two-thirds the cost. Natural gas is a superior fuel, with an octane rating of 130 compared to 90 or so for gasoline. It’s also an abundant, domestic fuel that can cut federal trade decit in half and help reclaim many of the half-million U.S. oil and gas industry jobs lost in the past 10 years. If 20 percent of America’s 200 million vehicles operated on natural gas rather than foreign oil/gasoline, we could cut foreign crude oil imports by 50 percent. There are other environmental benets of natural gas besides dramatic reduction in tailpipe emissions. It seems that the case for natural gas is pretty clear.The rst time my wife Nancy and I met Boone was in Western Oklahoma at a reception. Boone’s energy vision was shared then and was infectious. Throughout the years, I would follow his many initiatives including natural gas vehicles, higher education support, tness initiatives, his energy plan and the list goes on. In my 2012 book, America Needs America’s Energy, I quoted Boone: “We are now spending half a trillion dollars on foreign oil, importing 62 percent of the oil we use, and we haven’t had the leadership in DC to do anything about it. We’ve got to move to other sources of energy. But we’ve gotten way behind, and will continue to pay the ddler. It’s not a good future.” In the last seven years, Boone was able to see a great deal of his vision of energy independence come to fruition. I not only followed Boone and his many initiatives, but I took on several of his challenges including support of natural gas, his energy vision and higher education support...Boone was instrumental in supporting a documentary lm, released in 2012, of which I was one of the producers. He not only helped nancially support, but was interviewed in the lm. He shared his views on natural gas and his strong belief in America. As I stated in my book, “Future generations are depending on us to keep the American dream alive.” Boone’s challenges are still at the forefront: having passion for an effective energy policy/plan, supporting higher education, looking into the future with great courage and with great vision. He could see a better future for generations ahead. It is up to all of us to make the difference! Boone’s Impact and Vision!By Mark A. StansberryMark A. Stansberry

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Oilman Magazine / November-December 2019 / OilmanMagazine.com10OILMAN COLUMNOILMAN COLUMNFour Steps to Advanced Data Science in the Oil and Gas Industry By Stuart Robertson, Nilesh Dayal, Franco Ciulla and Amar Gujral When it comes to advanced data science – including machine learning and AI – there’s a perception that energy is lagging behind other industries, like retail or technology. While un-derstandable, especially given the sheer visibility of AI solutions like online recommendations or ride-sharing apps, it’s also a bit unfair. While “fail fast and fail often” is a common mantra in the tech industry, the amount of data and AI experimentation that energy companies can pursue is restricted: In energy AI needs to be deployed into highly sophisticated systems with multiple variables at play, so trial and error is risky.Also, many activities within oil and gas happen relatively infrequently, such as developing a well or eld, so obtaining data at the required scale – crucial for a number of algorithms, such as deep learning – can be difcult. At the same time, available data is often highly commercially valuable, so there’s great incentive not to share it.Therefore, the number of opportunities in which AI can be applied in oil and gas may be more limited than in other industries. However, when AI is applied to the appropriate areas, the impact can be considerable, even game-changing. Oil and gas players understand the potential of advanced data science, and the level of investments in digital technologies reects this. Since 2011, over $1 billion in seed and venture funding has been raised by oil and gas startups. In 2018, more than 35 percent of this funding has been allocated to software, analytics and AI products. Between 2011 and 2018, over 700 U.S. oil and gas software patents were granted.Frequently operating at the cutting edge of science and engineering, the oil and gas industry stands to benet considerably from data-driven analytics. But to do so, there are four key areas to optimize: good problem formulation, data readiness, expertise availability and organizational enablement. Addressing the Right Problem Not all problems can – or should – be addressed using advanced analytical techniques. In general, AI-driven solutions are appropriate for two broad classes of problems: 1) complex business decisions that hinge on predictions inferred from data patterns and 2) automation of processes with complex but discernible underlying patterns. For example, GE determined that it could improve the effectiveness of its equipment maintenance by applying predictive algorithms to heat loss data. By handling anomalies pro-actively, operators can avoid unplanned, costly downtime. However, there are certain critical components that may not contain sensors and cannot be monitored easily by service engineers. In response, GE developed a heat-monitoring smartphone app that uses an iPhone equipped with a thermal camera to provide noninvasive monitoring. Thermal images can then be classi-ed as normal or irregular based on engineers’ domain knowledge, providing a labeled dataset. This informs an image recognition algorithm, derived through machine learning, which then identies when equipment needs repairs. Gathering the Right Data AI and machine learning algorithms almost always require signicant amounts of data, especially since both training and testing datasets are needed to effectively test a model. The data must be of sufcient quality, granularity and representative of what’s being modeled.BP was seeking to reduce fugitive emissions (emissions resulting from leaks or gases that are unintentionally released during industrial activities) that were signicant in many of its mature elds. While engineers believed that machine learning could be effective in reducing fugitive emissions, they still needed to obtain the data to develop and test appropriate models. But outtting all their wells with sensors to gather this data would be costly and hard to justify. BP came up with an inexpensive way to gather data and test their hypothesis by xing Android phones to a selection of beam pumps and then combining the data gathered with historical maintenance logs and weather recordings. This allowed them to test the algorithmic approach and prove the business case. Following this successful pilot, permanent sensors were installed that were able to yield large amounts of data on equipment telemetry and well conditions. Armed with new data, the algorithm now provides recommendations to engineers, allowing them to make the necessary changes at each of the wells to minimize fugitive emissions. Assembling the Right Expertise Of course, effective application of AI requires more analytics expertise to ensure the right tools and technology are being implemented. But that’s rarely enough. For the complex problems faced by the oil and gas industry, other capabilities are also critical to effectively close the gap between technical skills and commercial understanding.To optimize its energy portfolio, Exelon wanted to accurately dispatch excess power generated by its wind turbines, but it needed a ve-minute forecasting capability to predict when wind speed would change suddenly. The company was looking for an OEM-agnostic data aggregation and analytics solution, but didn’t have all the required capabilities and didn’t want the risk and cost of in-house development. So, Exelon decided to partner with GE’s Renewables Data Science Team. Exelon provided the team with access to a year’s worth of turbine data to use in building and training machine learning models for wind ramp prediction. GE used its Predix industrial IoT software within Exelon’s IT infrastructure for a purely software-Photo courtesy of everythingpossible – www.123RF.com

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Oilman Magazine / November-December 2019 / OilmanMagazine.com11OILMAN COLUMNOILMAN COLUMNbased machine learning solution. The result was an increase in annual energy production of around three percent, and reduction in operating costs of 25 percent. The real-time forecasting model was also applied to longer-term forecasts, resulting in improved overall accuracy.Ensuring the Right Organizational Conguration A receptive organization is key to scaling up AI solutions. Senior leadership needs to be willing to step up and take ownership of the process, and facilitate overall organizational buy-in to maximize use of the new technologies by personal across all levels. Rio Tinto sought to combine its in-house mining and analytics expertise with the specialties of various partner companies (including Komatsu, Caterpillar and Amazon) to develop automation solutions for use in drilling, extraction and ore transportation. To do this, Rio Tinto both leveraged specic partner strengths and focused on designing supportive organizational structures. It created a dedicated data science unit within a centralized innovation function to foster the spread of ideas across business units Rio Tinto succeeded in embedding cutting-edge automation as a central part of operations. Since 2014, it has been growing its use of automated haulage system trucks, which now make up about 20 percent of the eet. The trucks lowered costs by 15 percent, and automated drills improved productivity by 10 percent. It’s a daunting prospect to start an advanced analytics and machine learning initiative, especially in an industry as complex as oil and gas. Often, it makes most sense to think in terms of manageable short-term efforts (such as focusing on one or two problems of high value to the business, running pilots rst, making the most efcient use of data and partnering when possible) that can be broadened into more ambitious longer-term initiatives (like building in-house capabilities, focusing on innovations with tangible and immediate benets, providing stakeholder incentives and incorporating data analytics into core business activities).One thing’s clear: Advanced data science applications have a place in the oil and gas industry, and the potential to yield tangible benets is considerable. Innovation has always been at the core of the oil and gas industry – and many companies are already nding creative ways to implement data science solutions. Stuart Robertson is a Senior Manager in L.E.K. Consulting’s London ofce, and leads L.E.K.’s Disruptive Analytics initiative. He has extensive experience across both public and private sectors, and has provided strategy and transaction support to clients in numerous industries.Nilesh Dayal is a Managing Director and Partner in L.E.K. Consulting’s Houston ofce, and is head of the rm’s Oil & Gas practice. He has more than 20 years of experience advising clients on growth strategies related to acquisitions, new business ventures, corporate restructuring, supply chain management, protability and operations improvement, and more.Franco Ciulla is a Principal in L.E.K. Consulting’s Houston ofce. He has 25 years of experience working in the oil and gas industry in technical, operational, commercial and strategic roles, with a focus on upstream activities and oileld supply chain strategies.Amar Gujral is a Senior Manager in L.E.K. Consulting’s Houston ofce. He is focused on growth and commercial strategy, M&A, and due diligence in the energy sector. SEAL OF DEPENDABILITYWWW.OILCENTER.COMwww.oilcenter.com | 800.256.8977 | esales@oilcenter.comQUALITY THROUGH RESEARCHENVIRONMENTALLY FRIENDLY PRODUCTSSPECIALTY GREASES & OILSCLEANERS & DEGREASERSTHREAD COMPOUNDSWIRELINE PRODUCTSVALVE PRODUCTSPIPE COATINGSOIL CENTERRESEARCH LLC

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Oilman Magazine / November-December 2019 / OilmanMagazine.com12Five Essential Mobile Device ManagementFeatures for Oil and Gas Personnel By Anson ShiongChallenges abound in the oil and gas industry: from navigating unpredictable – and often treacherous – weather conditions to maintaining production levels and ensuring the safety and security of staff and equipment across a range of locations. It’s clear to see the role mission-critical communications technology plays in the smooth operation, safety and efciency of both headquartered and remote worksites. This importance is reected in the rapid development of communications technologies. The two-way radios and daily reports of the late 1980s have evolved into the Wi-Fi connectivity, personal smartphone use and real-time data transfer capabilities of today, and the benets of such are clear – with the new technologies allowing for remote, unmanned, and subsea developments. Needless to say, the oil and gas industry has been transformed by improved communications systems, and one such system ushering in the next stage of communications technology and efciency is mobile device management, or MDM. At a base level, MDM allows companies to manage, control, and create security policies on company-deployed mobile devices. But the capabilities of MDM go much further than this; with some solutions offering features benecial to the oil and gas industry, like bulk, two-way le transfer capabilities, remote control for unmanned devices and grouping capabilities. However, not all MDM solutions are created equal. For oil and gas companies looking to invest in MDM technology, the following ve features should be considered: Two-Way Bulk File Transfer CapabilitiesOne of the biggest communication challenges in having a remote and varied workforce is the transfer of large les and amounts of data. Manually sending les and data, one-by-one via email channels is time-consuming and frustrating for personnel, and many companies can do without incurring the cost of sending technicians to remote worksites to install important updates. With this in mind, the need for simple and reliable two-way data transfer channels is obvious. As such, companies should seek an MDM solution with two-way, bulk le transfer capabilities that enable staff at remote facilities to transfer large les through a secure TLS, or similar, encrypted channel.Application Management ServicesOil and gas industry-specic applications have emerged since the popularity boom of smartphones, and it’s clear to see why: they simplify certain processes within each sector of the oil and gas industry while providing easy access to information. As such, another essential function to look for in an MDM solution is an Application Management Services suite, also referred to as an AMS suite. An AMS suite enables companies to create their own ‘app store,’ where company-developed, process-specic applications can be customized, branded and remotely deployed to company devices, without any interaction with the end-user. Companies can also take advantage of the force install feature which makes sure critical security updates are installed on all devices, leaving no room for potential exposure to security threats. They can also use the staged rollout feature which enables updates on only a certain percentage of devices so that if there are any system-breaking bugs only a portion of devices will be affected. Remote Control for Unmanned DevicesWith the rapid evolution of technology, many processes that previously required human interaction have been automated, such as daily reports. However, this presents several challenges for companies, with the maintenance of these devices and installation of important updates often requiring an IT technician to be on-site. Considering the remote nature of many worksites, this can be a costly exercise.The right MDM solution will enable oil and gas companies to remotely control their unmanned devices, allowing managers to perform maintenance and deploy important updates through an admin console. Device ManagementWith any remote device, sometimes things will inevitably go wrong, and due to the varied worksite locations in the oil and gas industry. Using an MDM solution allows companies to monitor all devices from the dashboard, giving them a bird’s eye view of all deployment operations. On the dashboard, you can see the current home screen status of each device by taking a screenshot and can see detailed device information such as device name, network status, battery status, CPU usage and which group the device belongs to. The dashboard also shows the location of the device which makes it easier to track when moving from one place to another. Grouping CapabilitiesThere is a range of employee functions within each stream or sector, so it makes sense that not all employees will need the same tools, applications, information or updates. To streamline the dissemination of information to certain functions or groups, the right MDM solution should offer grouping capabilities. These capabilities enable companies to dene devices by user and function. For example: If a company has engineer-specic information, they can group all engineer devices, and target their le distribution to that group, ensuring personnel only get the resources they need to do their job well. With the implementation of any new technology, companies need to assess their own unique needs and determine which solution is the right t. But, following the above suggestions should empower oil and gas companies to embrace MDM technology and reap the benets of simplied processes, streamlined communication, and increased control and security.Anson Shiong is CEO of Sand Studio, the developer of mobile device management (MDM) solution for Android devices, AirDroid Business. OILMAN COLUMN

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Global cloud service revenues exceeded $175 billion in 2018, and Gartner expects them to grow beyond $278 billion by 2021. SaaS (Software as a service) has been the star in that success story. It contributed more than $72 billion to 2018 global cloud service revenues, and SaaS is projected to grow nearly 18 percent this year to reach $85.1 billion. Now there’s a new star on the horizon: MaaS (Machine as a Service).MaaS is the New SaaSWhat cloud computing did to the software industry in the 2010s, digital twins and articial intelligence platforms are doing to heavy-asset industries today. Although nascent, MaaS is poised to become the star of Industry 4.0. MaaS in the EPC and OEM (Original Equip-ment Manufacturer) arenas is the equivalent to SaaS in the software product business. It implies a shift in the commercial structure of the relationship, moving risk, prot margin and capital expense from the customer – the equip-ment operator – to the supplier. The MaaS model gives suppliers an incentive to keep machinery running rather than having it break down, which benets the customers. In addition, service businesses benet suppliers because they are less cyclical and less vulnerable to global nancial turmoil.MaaS is Here Today, Providing Great ValuePioneering MaaS examples by progressive industry leaders are already bearing fruit, and prospective fast-followers are watching closely. For example, Caterpillar Inc. is working to steady its boom-and-bust business cycle by adding monitoring services to its parts and repairs business. As Caterpillar CFO Andrew Boneld explained, “Parts and services are the area where we can actually reduce some of the cyclicality.” The company had 700,000 machines connected to its cloud services in the summer of 2018. Caterpillar hopes to double its parts and services revenues from 2016 to 2026, which would bring them to $28 billion. The company already has provided its dealers with access to such digital tools as the Cat’s Service Information System Parts Inventory Optimization Tool and its Remote Flash and Remote Troubleshoot, which provide dealer technicians with live machine diagnostics to remotely identify problems.Rolls-Royce employs the TotalCare business model for its wide-body aircraft aero engines. Under that program, Rolls-Royce is responsible for ensuring its engines perform to customer requirements. More than half (52 percent) of the company’s civil aerospace business revenue came from services in 2017.International engineering and services company Kone also has embraced the MaaS model. A third of the company’s group total revenues now come from its maintenance business, which also services non-Kone equipment in its People Flow business.Aker BP and Framo also have partnered on a MaaS effort. The largest independent oil and gas operator in Europe, Aker BP wanted to create an autonomous platform that’s smart enough to make decisions that optimize production. So, it offered pumping company Framo access to its live pump data for the rst time. And Framo agreed to actively support Aker BP in its operation and maintenance of the pump system. This MaaS relationship has resulted in a 30 percent reduction in mainte-nance, 70 percent reduction in shutdowns, and 40 percent increased pump availability.A McKinsey analysis across 30 industries indi-cated the average earnings before interest and taxes margin for aftermarket services was 25 percent. It’s just 10 percent for new equipment.This Model is Poised to Change Oil and GasIt’s difcult to predict what the oil and gas sec-tor will look like in the next ve to 10 years. But it seems clear that digitalization will cause some players in this industry to rise and others to fall. MaaS is coming of age as machine learning matures as a discipline, making its disruptive force twice as potent. Now asset-intensive industries like oil and gas can use advanced data platforms and advanced APIs to share data with their suppliers to take advantage of MaaS. Digital frontrunners in the oil and gas supply chain and other machine operating industries are examining closely what happened with SaaS disruption and preparing to leverage the MaaS model in a similar way. That is stimulating discussion and steering digital strategies in industrial board rooms around the world. Petteri Vainikka is vice president of product marketing at Cognite - www.cognite.com. Machine as a Service Will Be theStar of Industry 4.0Why MaaS Is Shining Brightly, Positioned as the New Software as a ServiceBy Petteri VainikkaOilman Magazine / November-December 2019 / OilmanMagazine.com14OILMAN COLUMNPhoto courtesy of wrightstudio – www.123RF.com

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Oilman Magazine / November-December 2019 / OilmanMagazine.com16Automation and Economy: Driving Principles of the Modern Oil and Gas Industry By Eric R. Eissler OILMAN Magazine had a chance to catch up with Bill Coskey CEO of ENGlobal, a speciality engineering services company that focuses on oil and gas automation solutions, subsea control systems and construction and engineering; essentially, their lines of business cover all three streams of the oil and gas industry: downstream, midstream and upstream.ENGlobal experienced some difcult times after Bill entered retirement between 2010 and 2012. One of the biggest changes that occurred dur-ing Bill’s retirement period is that the industry suffered two precipitous drops in commodity prices and activity during the last 10 years. Downturn and ComebackBill came back to take back the helm of his company to steer it in a better direction. He reiterated, “I returned to run ENGlobal mainly out of concern for our people and to preserve their jobs, and to a lesser extent, out of a great sense of pride for the Company I had founded.”The company downturn was due, in part, to having suffered with the implementation of “larger company” structure, policies and practices. Despite the good intentions of this shift in size and management, the large-company management changes with an added extra overhead structure did not produce any signicant additional revenue or prot. “I also believe that the lack cash forecasting during that time, together with difculties we encountered with a new banking relationship, sent us into a downward spiral and liquidity squeeze that we eventually recovered from,” he said. ENGlobal was able to get out of their hard nancial position by selling off three of their operations to pay off debt and put some cash in the bank. This was the rst thing they did in 2012. While a critical move to save the business, the large sell off left ENGlobal in a position where they became short staffed to support the “large scale” operations the rm ventured into years back. Modular-built Factories ENGlobal’s automation integration facility, 80,000 square-feet, is located in Houston. The company engineers, designs and integrates systems for clients’ individual requirements that incorporates all of the instrumentation and electrical power functions of an energy related facility. The modular packaged systems include electric power houses, control buildings, and on-line process analytical systems and enclosures.Bill describes the way the modular units are produced by saying that “We have two “factories.” One is a 10 acre mechanical fabrication/shop facility in Henderson, Texas which per-forms structural/pipe fabrication and welding.” He continues, “the type of modular systems we produce in Henderson will take from two weeks to three months to produce depending on the complexity. All the modules we produce are transported to the job site over the road and are thus ‘truckable.’” A typical module produced by the company is 10-12 feet wide by 40-50 feet long, made up of structural steel, piping, vessels and other types of equipment.Automation Key to Growth and Expansion It has been said many times before, and it will be said many times after, but automation is key to the success and growth of many companies in the modern era of information technology. Automation provides better efciency and improved safety. Furthermore, all facilities can be monitored and controlled at a single location by use of electronic control systems. Bill went on to further illustrate the above with an example from his company, “Facilities which in the past were ‘manned’ are now remotely operated. Data and alarms generated from the local operation are continuously analyzed which leads to greatly improved safety. The operating data can also be used to optimize each process, which leads to a more efcient and economical operations.” Following these practices leads to a signicant increase in prot and production. Bill went on to state that going forward, “Our mission is to more than double our revenue over three years while keeping overhead at a constant level. We have put the pieces of this puzzle together and are excited about the early results from our new strategy.”Digital oilelds have grown in number, which, in turn has led to an increase in investments and productivity. Automation has proved to be a cost saving investment for the oil and gas industry, because it used to improve many of the processes in the industry. In conjunction with big data, the investment and implementation in the oil and gas industry has grown substantially. ENGlobal is looking to capitalize on this opportunity to take the company higher. OILMAN COLUMN Analytical Modular Building – Photo courtesy of ENGlobalWhen I left the company, spending within the energy industry was depressed and still negatively impacted by the “great recession” of late 2008 and early 2009. By the time I returned, the market for our services had slowly recovered, and this recovery lasted until late 2014. Unfortunately, during this recovery, our company was mainly focused on managing through nancial difculties and raising cash to solve liquidity issues and thus we did not benet to a large degree from the recovery during the rst two plus years. Then after we had solved some internal issues of our own making, our industry went into the cyclical downturn of late 2014 through 2016.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com17OILMAN COLUMNWhat Safety Measures Should You Take for Lone Workers By John CarvalhoYou hear about lone worker accidents all the time. “Lone Worker” is not just remote oileld or pipeline workers in the wilderness. According to Wikipedia, a lone worker can be “an employee who performs an activity that is carried out in isolation from other workers without close or direct supervision. Such staff may be exposed to risk because there is no one to assist them and so a risk assessment may be required...” That denition covers many activities within the oil industry and others. Up in our neck of the woods in New England, we had a few lone worker incidents that grabbed signicant coverage. One involved a worker who was severely injured after falling into a large lathe at a Glastonbury, CT manufacturer DAC Technologies. The 58-year-old man was extricated and airlifted to Hartford Hospital by Life Star helicopter.Another involved a National Grid worker who fell out of the bucket he was working in and struck wires as he fell approximately 35 feet to the ground. Given these types of incidents, lone workers are now often supported by cloud-based automated monitoring systems and specialized monitoring call centers - often referred to as an ARC (Alarm Receiving Center) in the UK, or EDC (Emergency Dispatch Center) in the U.S. In fact, Man Down/Lone Worker detection devices have become standard, if not a requirement, for most work sites in the oil and other industries. Given the gravity of this investment—cost and what is at stake, literally people’s lives – companies need to do their homework when purchasing a man down/lone worker detection device or devices. Sure, your budget will play a large factor in the system you purchase. Yet to make the best investment for your dollar and provide optimal safety for your workers, you want your man down/lone worker devices to contain the following features:Man-down (no-motion) detection – If a worker is down and not moving, optimal response time is key. In addition to having this feature, you want a system where you can adjust the alarm time. Many systems will come pre-set to 90 seconds. Different projects and clients can have different safety requirements and you will want a system where you can adjust the no motion setting.Panic alarm – As the name implies, a worker may not always be able to verbally communicate distress. A device with a panic alarm provides an extra communication tool to alert the command center of a problem.Live cloud-hosted web software for conguration and emergency response management – With today’s technology, software and rmware updates occur on a regular basis. By having your lone worker/man down system hosted in the cloud, you ensure that updates to the system occur immediately and in real-time. Live gas detection compliance dashboard – This feature eliminates manual data collection, review and reporting. But most importantly it provides a real time view on conditions.24/7 live monitoring Safety Operations Center – A few providers of lone worker/man down systems will offer 24/7 live monitoring. This is in addition to your own staff keeping a watchful eye and ear on your lone workers. This second set of eyes and ears provides an extra layer of safety.Push messaging with the live monitoring team – Another imperative for lone workers to be able to communicate by receiving a text for example to “evacuate” or “check-in.”False detection – This feature enables a lone worker to cancel a pending alert before it is communicated to the command center dashboard. A quick “shake” or resuming movement returns the work-alone device to normal operation. Automated-prescheduled, wireless rmware updates and device conguration changes – Whether your service is on the cloud or not, you want to ensure your device and rmware are current 100 percent of the time. Automated prescheduled /Pre - Approved updates should be included with any system you purchase.Customizable system – Most lone worker/man down systems come with pre-set congurations. For many operations, the standard settings will sufce. Yet there are many benets to purchasing a system that is customizable. For example, should you do government contracts. Many of those might require a system that has shorter no-motion detection (e.g., 60 seconds detection rather than 90 seconds). Think of your lone worker/man down system like an iPhone. You purchase your phone and then in another year a new phone comes out with a few additional features. If you want the additional features, you must buy the new phone. Lone worker/man down devices come in customizable formats so that instead of buying an entirely new system, you can simply add onto your existing one.Extended warranties – Your typical lone worker/man down devices will come with a two-year warranty. That’s standard. If you have an opportunity to purchase an extended warranty, you should do so. The length of the extended warranties will vary. Our organization offers a ve-year warranty. That will typically cover the lifetime of the devices. Extended warranties are an even better idea if the system you purchase is customizable.Man Down/Lone Worker detection systems vary in price. For a smaller organization requiring ve devices, you can expect to spend in the neighborhood starting at $6,000. You can’t place a value on human life. Unfortunately, price does play a role in the type of system you might purchase. By doing your homework, you can nd a system that offers optimal protection for your workers, liability protection, and value for your business. John V. Carvalho, III is the president of Apollo Safety, Inc. Veteran-owned, Apollo Safety specializes in gas detection products and services for portable and stationary systems. For information, please visit www.ApolloSafety.com or call 800-813-5408.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com18OILMAN COLUMNThe Case for AI in Planning and Forecasting By Jack KokkoObtaining robust market intelligence for a complete view of the oil and gas industry across the supply chain comes with its fair share of challenges. The rise of web search engines made access to publicly available information easier for companies to tap into disparate competitive resources that were hard to access previously. For modern researchers and analysts, the burden now rests on distilling disparate public and proprietary resources to identify consensus and track long-term impact of emerging trends. One of the biggest benets of AI is the ability to distill large amounts of information quickly and efciently, giving researchers a new way to streamline insight discovery and focus on more strategic initiatives. NLP (Natural Language Processing), an AI technique that focuses on the understanding of human language, works to add a contextual layer, with the ability to distinguish nuances and tonality in differentiated verbiage – uniting different sources that share similar themes under a shared context or sentiment, regardless of variations in terminology.Understanding Macro Trends Developing a full understanding of the long-term impact of current macroeconomic trends is a balancing act of collecting information en masse, while maintaining a razor-sharp edge on the most important insights to inform strategy. Complexity deepens when the market landscape takes the global stage, with different entities using different verbiage to discuss similar themes. How are different stakeholders responding? What is the tonality of companies that face potential impact? What is the consensus of Wall Street analysts, and how does it vary from other global perspectives? For example, in September 2019, an unexpected drone attack on Saudi Aramco facilities raised a urry of questions on the impact on the price and supply of crude oil. According to AlphaSense data, contextual mentions of “global oil production” spiked throughout the week of the attack across a range of document types – especially within broker research, news and company presentations.Dissection of these different content sets together in real-time can lead to a greater understanding of both the short-term and long-term implications of the event as a whole. First, let’s look at regulatory data, which is notoriously difcult to mine when searching through agency repositories. Further investigation immediately reveals a highly relevant EIA regulatory report released on September 23 detailing an immediate production drop at Saudi Aramco facilities to 2 million b/d in wake of the attack – down from estimates of 6.7-9.9 million b/d of crude oil production in August.A later report led by the EIA at the start of October forecasts lower crude oil prices through the duration of Q4 and into 2020, despite tighter global balances in wake of short-term loss of supply, stating; “The tighter balances are largely the result of unprecedented short-lived loss of global supply following the September 14 attacks on crude oil production and processing infrastructure in Saudi Arabia.” The report also states that supply will outpace demand into Q4, posing questions over inventory. Understanding and tracking these larger regulatory forecasts can be useful when assessing your own planning and forecasting in light of shifting oil prices and demand. Analyzing broker research alongside other content resources can help afrm strategy in alignment with forecasts from the Street. Broker research is also especially valuable when extracting data tables to build out your own reporting. According to AlphaSense trends data, more than 400 broker reports discussing global oil production were released within the two weeks following the attack, with a spike on September 18. Of those reports, 217 of them mentioned Saudi Arabia. Sorting and ltering these reports by relevance, broker tag, and report type can give you a more robust, qualitative view of the issue. Drilling in deeper, analysts can Photo courtesy of nicoelnino – www.123RF.com

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Oilman Magazine / November-December 2019 / OilmanMagazine.com19OILMAN COLUMNleverage sentiment analysis to immediately understand how other market leaders are discussing industry issues to help afrm their own consensus. Sentiment analysis leverages deep learning AI models to identify tonality of language. When those AI models are applied to company documents like earnings transcripts, analysts can quickly identify how companies are discussing specic trends and how that language may have changed over time.When looking at all earnings transcript mentions of “global oil production” through 2019 (63 at the time of the study) we found that overall sentiment skewed negative (38 percent overall positive, 62 percent negative). Total SA explicitly addressed the Saudi Aramco attack at their Investor’s Day conference on September 30, saying: “It’s also a shock for the oil markets because obviously, it increased somewhat the risk premium in the oil price, and it might also force the market to reconsider what are the acceptable levels of inventories and spare capacities in the world.” This is an interesting insight from Total SA, and could also be worth noting when considering planning and forecasting for changes in demand and inventory in the event of short-term shifts in global supply. Using AI for Planning and Forecasting in Oil and Gas The future of AI within the Oil and Gas space is promising, with companies already investing heavily in AI to improve processes, increase production, and reduce waste (research shows oil and gas investment in AI is projected to reach $4.1 Billion by 2025). When it comes to corporate planning and forecasting, AI tools can help elevate market intelligence by consolidating and streamlining insight discovery, and adding greater contextual depth for a more complete picture of the market landscape and the potential short and long-term impact of macroeconomic trends. The ability to forecast effectively, while still remaining nimble is strengthened by those nuggets of information that can provide the greatest condence in afrming or dissuading hypotheses in both near-term and long-term scenario planning. An information edge is also obtained when these insights are discovered early, allowing for room to quickly and condently execute ahead of competitors, identify opportunities, improve processes, or preemptively safeguard against unfavorable market conditions to mitigate impact on the bottom line. Jack Kokko is the CEO and founder of AlphaSense, a groundbreak-ing AI-based market intelligence search en-gine. His mission is to leverage AI to help businesses acquire information more efciently, and make better decisions more quickly and condently. AlphaSense is currently used by over a thousand investment management rms and corpo-rations across all industries, and has won numerous industry awards, including “Best Analyt-ics Product” and “Best Mobile Solution.” Jack holds an MBA with a major in nance from the Wharton School of the University of Pennsylvania. He also holds a master’s degree in electrical engineering from the University of Oulu, Finland and a bachelor’s degree in nance from the Helsinki School of Economics.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com20OILMAN COLUMNRevolutionary Evaporation System Cuts Costs To $.006 Per Barrel And ProtectsEnvironment From Particulate Contamination By Robert Ballantyne Disposing of industrial wastewater is a problem in many industries. Wastewater is so named because it typically contains a high concentra-tion of contaminants including chemicals and particulate matter that are beyond the capabilities of municipal sewage systems. Mining endeavors including all types of fossil fuel recovery are particularly awash in wastewater. Oil and gas operations may produce 5 to 10 times more water than oil, meaning millions of barrels per day have to go somewhere.Some water can be lightly treated then reused for well completions and recovery methods. Some can be injected deep into the earth, but this is costly and has been scientically linked to earthquakes in some areas of Texas, Oklahoma and elsewhere.Evaporation of wastewater has been another viable option for decades, but older methods had their own environmental issues. Most evaporation units were simply sprinklers or snowmakers that used great force to stream water out over a holding pond. The two main problems with this method was, rst, that the large pumps required were power hogs, requiring 40 HP motors and costing 20 cents per barrel. The other issue has been that, once the water evaporates or when the droplet sizes shrink below 75 microns, the particulate matter—whose toxicity made the water a problem in the rst place—was launched into the surrounding atmosphere as dry aerosol, where it could travel for miles before precipitating out. It has not been uncommon to see evaporation ponds where airborne salts have killed nearby trees, rusted out barbed-wire fences and caused other problems miles away.The most common pollutants include salts like sodium chloride, sodium sulfate and calcium chloride.It is clear that the contamination that keeps industrial waste out of the city sewer system also prevents the water from being evaporated completely, in order to keep those contaminants from being released into the air. But evaporation does greatly reduce the volume of water to be injected or otherwise disposed of. Herein lies the system’s scal benets.Regarding injection of this denser water, one might ask if injecting that into an SWD would cause problems in the formation. RWI’s research shows that water with TDS levels at 160,000 ppm can indeed be injected without harming the for-mation into which the water goes.Most produced water in the Permian Basin, for example, tests at 6,000-10,000 ppm. So, concentrating it by approximately No w Av A i l A b l e : T h e C r u d e l i 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 e2.0 units float on the surface of the evaporation pond, allowing concentrated droplets to fall back into the water.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com21OILMAN COLUMNten times through the evaporation process cuts the amount of water injected by 90 percent. This is another layer of cost savings.Time for a ChangeThe arrival of new EPA air quality rules—specically Rule 40 CFR 51-300 in 2018—has put older methods in danger of nes or worse. And increasing emphasis on reducing costs and increasing protability has caused mining operations in particular to examine every procedure for possible cost savings.In 2017 Colorado-based Resource West, Inc. (RWI) began testing 2.0 series enhanced evaporators, a system designed completely from the ground up with the goal of satisfying both the economic and environmental requirements of the industry.RWI spent two and a half years researching and testing 2.0 at their ve acre test site in western Colorado. The system they released to the public proved to be 116 percent more effective at evaporating water, using approximately 88 percent less power while keeping droplet size above 100 microns, which allows them to fall back into the pond for disposal.Instead of 20 cents per barrel, RWI 2.0 evapo-rates water for approximately .006 cents per barrel.Efciency BoostSnowmaker-based units use strong air force and pumped large amounts of water into the air. This method requires bulky 40 HP pumps which not only require high levels of power, the ow they create allows water particles to collide, greatly reducing the evaporation rate and, therefore, the efciency of the process. When particles collide, some tend to break up into smaller pieces, known as daughter particles, which oat for miles and are the main source of airborne dry aerosol contamination. For RWI 2.0 the droplets are injected in the middle of the ow, which greatly reduces collisions. This creates a more efcient process and helps keep particles above 100 microns by eliminating daughter particles (see photo above).Instead of pumps, 2.0 uses fans requiring only 5HP each, reducing power consumption by 35 HP per unit. The 2.0 units oat on the surface of the pond, allowing the concentrated drops to fall back into the water.In the FieldRWI installed its rst 2.0 commercial units in Hobbs, NM, in retention pond holding super-saturated drill cutting water. Because of the region’s hot climate, the water held an abnormally dense 230,000 ppm of TDS. The purpose of this test was to prove the unit’s ability to control the drift of salts—a critical requirement in a pond adjacent to a U.S. government uranium enrichment area. The unit passed the test successfully.In an ongoing installation that is now starting its third year, a mining operation in the state of Washington installed 15 Landshark 2.0 evaporators. Power draw for these 15 units totals 56 KWH, powering 75 HP compared to the 450 KWh required for previous units using a total of 40 HP each. The 15 Landshark 2.0 units evaporate an average of just under 7.2 million gallons per month, compared to the 2 million gallons being evaporated by the previous system. And after more than two years with these systems in place, there has been no buildup of salts in the area near the evaporation pond. Uses in the FieldRWI 2.0 can be used either by large producers who own and manage their own produced water systems or by SWD companies looking to reduce their costs and the amount of water they inject downhole. The need for alternatives to SWD is unprecedented, as the Groundwater Protection Council predicts that, by 2028, produced water in the Permian Basin alone may total more than 6 billion barrels per year, an increase of approximately 50 percent from 2019 numbers. Reuse by 2028 is projected to be less than 2 billion barrels per year—leaving 4 billion barrels to be injected, if these numbers play out as predicted.If producers or SWD operators could reduce this amount by 90 percent through evaporation that would leave less than 1 billion barrels to be injected.Agencies such as the Texas Railroad Commission and the U.S. Geological Survey have linked SWD operations to earthquakes, as per the following quote from the USGS website: “The injection of wastewater and salt water into the subsurface can cause earthquakes that are large enough to be felt and may cause damage.”Safe evaporation systems such as RWI’s Series 2.0 units could be instrumental in reducing the risk of human-induced earthquakes in the Permian and other producing basins across the U.S.The combination of uncertain economic times and public pressure on the industry to improve its environmental footprint, the oileld is increasingly looking to innovation for solutions. This could be an important step in that direction.Robert Ballantyne served in the United States Marine Corps. An electrical engineer, his ongoing education has concentrated on molecular and atomic spectroscopy. His science research focuses on environmental monitoring, mitigation, and remediation systems design, with an emphasis on waste stream reduction. His current role as Director of Research and Development for RWI Evaporation allows him to pursue raw scientic research into ways to fundamentally change environmental mitigation markets and methods. Injecting droplets into the middle of the water flow reduces droplet collisions, making a more efficient flow and keeping particles from escaping into the ambient air.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com22FEATUREProgressive Strides in Unconventional Oil and Gas RecoveryBy Sarah SkinnerWhen talking about advances in oil and gas tech-nology, we would be remiss if we didn’t discuss unconventional methods of oil and natural gas recovery and the ways in which they could benet the U.S. economy. There are always the tried and true methods – foolproof and with little-to-no risk. With these standard approaches, there have been and continue to be advances that make them more efcient and cost-effective. But it makes you wonder, what else is out there? What other innovations are there that could potentially revo-lutionize the oil and gas industry and the recovery of these vital resources? Companies, universities, researchers, government agencies, etc. would all benet from the exploration of alternate meth-ods. The problem with unconventional methods is that it’s a risky operation to research them and without proven success, it is hard to nd backing. The U.S. DOE (Department of Energy) has recognized the extreme benets associated with this kind of research and they have generously chosen to invest approximately $30 million dollars to boost unconventional oil and natural gas recovery. In January 2018, they announced the selection of six projects, selected under the Ofce of Fossil Energy’s “Advanced Technology Solutions for Unconventional Oil and Gas Development” to receive the federal funding. The eld projects that were chosen are currently producing less than 50,000 barrels per day using unconventional plays. According to the DOE press release dated January 3, 2018, “The newly selected projects will help us master oil and gas development in these types of rising shale, along with bolster DOE efforts to strengthen America’s energy dominance, protect air and water quality, position the nation as a global leader in UOG (unconventional oil and natural gas) resource development technologies, and ensure the maximum value of the nation’s resource endowment is realized.”The DOE took careful measures in selecting the six recipients of this award. Without further ado, they are as follows:1. C-Crete Technologies, LLC – Hexagonal Boron Nitride Reinforced Multifunctional Well Cement for Extreme Conditions2. The Institute of Gas Technology – Hydraulic Fracture Test Site II (HFTS2)3. Texas A&M Engineering Experiment Station – Eagle Ford Shale Laboratory: A eld Study

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Oilman Magazine / November-December 2019 / OilmanMagazine.com24FEATUREtight gas sand reservoirs. By using the newly-developed and comprehensive monitoring solutions, unprecedented and comprehensive high-quality eld data will improve scientic knowledge of not only the hydraulic fracturing process, but re-fracturing, and subsequent huff and puff gas injection as an EOR method. The Trustees of the Colorado School of Mines (Golden, CO) & Oceanit Laboratories, Inc. (Honolulu, HI)Colorado School of Mines (CSM) and Oceanit Laboratories are developing a novel ‘hydrate-phobic’ coating for deepwater well environments that will improve safety, cost, and component life during operations. The ability to mitigate gas hydrate blockages in owlines is critical to ensure the safe and economic operation of deepwater facilities, to extend the life of the eld, and to minimize product loss. Prevention of hydrate blockages will mean operating in a safer and more cost-effective environment, as current mitigation costs can exceed $1M per mile of pipeline.A coating capable of repelling deposition and preventing hydrate build-up - that can be applied in-situ to existing owline facilities - would represent a breakthrough over the current state-of-the-art, mitigating the severe production, environmental, and safety issues that this deposition can cause during operations, including catastrophic blowouts and sustained leaks. CSM and Oceanit are further testing this novel coating against the adhesion and deposition of waxes and asphaltenes to investigate the broader capabilities of the coating under eld conditions, where these solids will accumulate to cause restricted ow problems in the owlines. This research represents a novel, cost-effective solution to unresolved ow assurance challenges that would ultimately lead to major fundamental breakthroughs in gas hydrate and related solids engineering.“Novel, nanocomposite-based surface treatment technologies, such as the ones being developed by Oceanit can have a profound impact on the efciency, safety and therefore environmental impact of production operations. In bringing this technology to the market, Oceanit is proud to partner with CSM, who brings decades of expertise in hydrates and ow assurance testing to the effort. The funding support from U.S. DOE National Energy Technology Laboratory made this partnership and maturation of the technology possibly. We are excited to advance a eld-deployable solution to a very long-standing challenge faced by the industry today.” – Dr. Vinod Veedu, Oceanit Laboratories, Director of Strategic Initiatives “Gas hydrate plugs in owlines present a major economic and safety concern to the oil and gas industry during subsea production. The ability to prevent hydrate deposition is using coatings is especially critical to mitigating pipeline blockage and ensuring safe and efcient production. “– Dr. Carolyn Koh, Colorado School of Mines, Director, Center for Hydrate ResearchUniversity of Louisiana at Lafayette (Lafayette, LA)Tuscaloosa Marine Shale Laboratory (TMSL) is an excellent example of collaborative effort between the federal government (DOE, Las Alamos National Lab), several academic institutions (University of Louisiana at Lafayette as the lead, University of Missouri Science and Technology, University of Oklahoma, and University of Southern Mississippi) and private sector (Goodrich, ExxonMobil, Signal, and Helis) to support energy production and development projects. The goal of TMSL project is to bring all stakeholders together in a synergistic approach to unlock signicant estimated unproved hydrocarbon resources of Tuscaloosa Marine Shale, as a major challenging shale play, in economic and environmental-friendly manner. TMSL is a multidisciplinary team of more than 30 faculty and research assistants with background in petroleum engineering, geology, geophysics, and socio-economics studying the key issues in reservoir quality and completion quality of TMS.The University of Louisiana, Lafayette is home to a TMS virtual laboratory with a signicant amount of whole cores, slabbed cores, cuttings, and data for TMS wells. The team recently published the results on the mineralogy and geochemistry of 11 TMS wells at “Marine and Petroleum Geology” journal: “Heterogeneity of the Mineralogy and Organic Content of the Tuscaloosa Marine Shale, Marine and Petroleum Geology. Vol. 109, Pages 717-731” The virtual laboratory will conduct testing and analysis of various properties of rock and formation uids from the TMS to determine sources of the wellbore instability issues, improve formation evaluation, the role of geologic discontinuities on fracture growth and shale creep. University of Louisiana – Lafayette also plans to investigate the application of stable CO2 foam and super-hydrophobic proppants for improved reservoir stimulation, as well as to better understand the nature of water/hydrocarbon/CO2 ow in a clay and organic-rich formation. The TMS has been estimated to contain 7 billion barrels of recoverable light, sweet crude oil, while its current total average production is only about 3,000 barrels of oil per day. Over the years, operators have been unsuccessful in the TMS play, in part due to its clay-rich nature which makes it sensitive to water. Improved understanding of the TMS, along with public scientic assessment of new approaches for developing the play, will expand and accelerate industry efforts to cultivate this resource with minimal environmental impact. Virginia Polytechnic Institute and State University (Blacksburg, VA)The Central Appalachian region is host to an abundance of hydrocarbon resources including coalbed methane, shale, and other unconven-tional reservoirs. Many of these plays are verti-cally stacked such that a single well or group of wells in close proximity can produce simultane-ously from multiple reservoirs. Because many of these reservoirs produce less than 50,000 BOE (Barrels of Oil Equivalent) per day and can thus be classied as ESUPs (Emerging Stacked Unconventional Plays). The project is designed to improve characterization of the multiple emerging unconventional pay zones that exist in the established Nora Gas Field through the drilling and coring of a vertical stratigraphic test well up to 15,000 feet deep. This project will evaluate and quantify the benets of novel completion strategies for lateral wells in the unconventional Lower Huron Shale. A major research objective of the project is to characterize the geology and potential deep pay zones for Cambrian-age formations in Central Appalachia. A second major research objective is to evaluate and quantify the potential benets of novel well-completion strategies in the emerging (and technologically accessible) Lower Huron Shale. The benet of this research will reduce surface footprint, infrastructure requirements and development costs by combining best practices, state of the art technology and effective outreach to carefully develop these resources. ConclusionThe motive behind the unconventional methods research consists primarily of three objectives: 1. Improving understanding of the process involved in resource development2. Advancing technologies and engineering practices to ensure these resources are developed efciently with minimal environmental impact and risk3. Increasing the supply of U.S. oil and natural gas resources to enhance national energy dominance and securityThe oil and gas industry is advancing by leaps and bounds, to be progressive, the unconventional must be explored. The DOE assisting in these efforts is displaying their commitment to the industry and the U.S. economy as a whole. It will be interesting to follow these projects and see where the end result leads.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com25OILMAN COLUMNThe Plaza Group Defining and Embracing the Core Values By Lillian Espinoza-GalaIt is not unusual for a Houston Petrochemical mar-keter to celebrate 25 years in business. But a look at the history of the company, and the extraordinary decisions made by a 33-year old chemical engineer-ing executive, Randy Velarde, in 1994, is to see some important lessons for all corporate leadership in the 21st Century. Velarde began his executive level career after graduating from University of New Mexico with a B.S. in Chemical Engineering in 1981. Velarde’s corporate climb began with Shell Oil Chemicals followed by an even better management job with Texaco Chemicals ten years later. After 15 years climbing the corporate ladder with Shell and Texaco, Velarde learned that Texaco would be selling its Chemical Division to Hunts-man. Feeling stied by the bureaucracy involved in working for two major operators, Velarde proposed to Texaco’s corporate management that he take over the marketing and distribution of the by-products not included in the Huntsman sale. In 1994, he became the exclusive distributor of the aromat-ics that are not a valued fuel by the major reners. Velarde found customers, such as 3M and Sherwin Williams and Pzer Pharmaceuticals, that could use the acetone, benzene, and butane in everything from nail polish remover to paint thinner and medicinal compounding.In those nal days of completing the legal docu-ments to create the new company, he struggled to come up with a name. Velarde is the son of a former long-time government worker and a stay-at-home mother, who had a passion for genealogy, and had traced ancestors on both sides of the family to Spain. Since his company would be a global petrochemical marketer, the Spanish term “Plaza”— the square where merchandise is bought and sold — came to mind. Thus the name, The Plaza Group. Within two years, Velarde bought out his initial investors and partners and remains the only shareholder.The rst 15 years of The Plaza Group saw increased revenues and new customers and suppliers annually. However, as the U.S. and other countries recovered from the Great Recession of 2008, The Plaza Group experienced a plateau. While other companies borrowed money to breathe new life into their businesses, Velarde decided to pause and examine the organization. He instructed his board of directors and management team to read and study the book Built to Last: Successful Habits of Visionary Companies by Jim Collins and Jerry Porras. Velarde and his team then went on a two-day retreat to brainstorm the fundamental building blocks that created the foundation of The Plaza Group. Velarde recalls the retreat as the event that would forever set the compass and future direction of The Plaza Group.“This was hard work writing as a group the ingredients in our recipe that had led to 15 years of success and extraordinary growth. We had to dene the organizational DNA – those fundamental building blocks that enabled our entrepreneurial success. We had to do a lot of soul searching, brainstorming, and wordsmithing to nail down how many core principles we would adopt and dene how each one would be embraced and honored throughout the entire organization. If you choose too many core values, the organization simply cannot embrace and enforce all of them.” Realizing the world is dynamic and successful businesses must be nimble enough to adopt quickly to unexpected changes, Velarde says it would be important to select values that would serve in up and down markets.Five core values were adopted. “It’s one of those moments when you realize what things you want to live by — knowing at some point mistakes will be made. We are all human and prone to make mis-takes, but you want everyone in your organization to understand what the corporate DNA is. It is not just a plaque that you put on the wall.”The Plaza Group adopted ve core values:1. To be honest and forthcoming2. To treat people with respect, courtesy, and professionalism3. To provide exceptional service to customers and suppliers4. To be opportunistic5. To be nancially responsibleVelarde says the ten years following this break-through season became a process of leading by example. Every employee from top management to those on the front line had to embrace each of these ve core values in both their professional and personal lives. Velarde says in our litigious U.S. corporate world one sign the organization has succeeded in adopting the ve core values is the fact The Plaza Group has never had to deal with a lawsuit. Velarde likes to recount an example when a Plaza Group employee discovered a supplier had undercharged by $100,000. In business transactions that amount to millions each year, some companies might have let this mistake pass, but it was brought to the attention of the supplier and corrected. This proved to be a trust building experience in the relationship between The Plaza Group and the supplier AND with The Plaza Group employees. Everyone witnessed the true meaning of core value number one — being honest and forthcoming.Velarde says feedback is critical in order to take the pulse of the entire organization. He created a Core Value Team that meets with him every 60 to 75 days to share with him both positive and negative feedback. Velarde wants to know where mistakes are made and feels that it is important to know if they are simply human error or a violation. He believes it is important to be compassionate when mistakes are made, but it is critical to spot a trend when standard operating procedures begin wandering from the ve core values. Velarde says, “If you spot a negative trend, it is critical to nip it in the bud in order to prevent bad seeds from growing within the organization.”Within last three years, The Plaza Group has acquired Dallas-based Conchemicals and the Woodland-based Truth Fuels. Being a minority-owned business has given The Plaza Group a great advantage with the Truth Fuel Group, which pro-vides fuel for small generators to cities and special events, as often cities or non-prots or NOGs want to do business with a minority-owned company.Velarde’s two sons have joined The Plaza Group within the last ve years and brought forward the principles for work-life balance. Velarde says he realizes that may be one of the shortcomings of his generation and that this younger generation helps balance the organization in attracting young professionals and allows him to focus on mentoring the next generation.As 2020 approaches, Velarde says he is excited about new challenges in nding solutions for climate change and creating a healthier environment in the petrochemical industry for the benet of everyone on the planet. As someone who loves to sh, he is passionate about helping foster good stewardship of land and water resources.Listening to Velarde share his extraordinary journey from a Shell/Texaco corporate executive leader to striking out to build a niche business proves that, while Velarde began his career as an ordinary chemical engineer, he adopted an extraordinary vision for his organization and has prepared The Plaza Group to be uniquely positioned for the next season of the 21st Century. Randy Velarde and sons: Vincent and Garrett – Photos courtesy of The Plaza Group

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Oilman Magazine / November-December 2019 / OilmanMagazine.com26OILMAN COLUMNConductor Supported Platforms: Demystifying the Industry’s Best Kept SecretBy Rob GillFor the eld development engineer striving to deliver the most cost-effective concept design for a shallow water development, there are a variety of possible routes to take. Maybe a subsea tieback would provide the most protable solution, or perhaps a jacket supported wellhead platform? Maybe separate offshore processing is worth considering? One option that is all too often overlooked though, and that can substantially reduce the capital cost of a development, is the conductor supported platform (CSP). Frequently this boils down to a simple lack of familiarity. Other times, some persistent misconceptions lead eld development planners to quickly write-off a CSP as a viable option. In fact, a CSP can be an extremely cost-effective option - one that can accelerate time to production and which is suitable for a far wider range of conditions than commonly assumed. In some marginal cases, a CSP could even be the difference between a viable and non-viable project. So, perhaps it’s time to demystify the sector’s best kept secret?The Power of CSPsFirstly, what is a conductor-supported platform? Simply put, it’s a more exible and cost-effective alternative to a traditional jacketed structure. A CSP provides all the dry tree functionality of a jacket supported platform, with the difference being that the well conductors themselves are used as the structural and foundation support for the topsides. So why are they worth considering?The use of a CSP can drastically reduce installation costs. Modular design means it is possible to fully install a CSP using a jack-up drilling rig, rather than having to rely on a heavy-lift crane barge, which will inevitably be accompanied by notoriously high mobilization costs. It is highly likely that a jack-up will already be onsite to drill the wells themselves, so it makes sense to simply keep the rig for slightly longer to install the structure too. Assuming a daily cost of $150,000 per day, an extra week with the rig would cost around $1 million. Contrast that with a traditional jacketed supported platform, which would require a heavy-lift crane barge for installation. In many parts of the world, the mobilization costs alone for a crane barge could run into tens of millions of dollars, meaning that seven or eight gure savings from this point alone quickly become achievable. Because it also uses the conductors for support, a CSP is a much lighter structure, requiring less steel and representing a lower material cost than a comparable jacket supported platform. Though the conductors themselves may need to be over specied in comparison, it is important to bear in mind that a budget price quotation for a CSP will include the conductor cost. By contrast, the cost of the conductors will generally be excluded from a budget price quote for a comparable jacket supported platform and will instead be hidden within the drilling cost estimate. The simpler design of a CSP also enables a more exible approach to fabrication. With an almost modular design, it is not necessary to fabricate one single huge structure in a large fabrication yard. Instead, the job can be split between smaller fabrication yards, with more competitive pricing. This can also be a great benet for projects with strict local content rules, offering the exibility to designate some sections to local yards, which may not always have the ability or experience to fabricate large structures. Finally, CSPs also offer exibility with regards to early production and helping to realize project returns faster. It is possible to install the conductors and subsea support structure and then begin drilling right away, without waiting for the topside to be installed. If the topside is not expected for another couple of months, this can signicantly accelerate time to production and the critical path to reaching rst oil or gas.Myth Busting CSPsSo with a lower capital cost and so many other advantages, why don’t CSPs feature more prominently as an option for shallow water eld developments? Perhaps, they’re dismissed due to

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Oilman Magazine / November-December 2019 / OilmanMagazine.com27OILMAN COLUMNsome persistent misconceptions that surround conductor-supported designs and the types of developments they would be suited to?Myth 1: CSPs are only suitable for shallow, benign ocean conditionsIt’s true that CSPs are not a deep-water technology – they are suitable for water depths of up to 100m and excel in depths up to 65m. It is also true that many of the CSPs deployed today are in locations with relatively mild met ocean conditions, such as the Gulf of Thailand, West Africa and the Middle East.It doesn’t follow however, that CSPs are only suitable for the most easy-going met ocean conditions. There is an idea that: “yes, CSPs may be great for the Gulf of Thailand, but they wouldn’t stand up to the kind of storms you see in more challenging environments.”Actually, CSPs are capable of withstanding the most extreme storm or seismic events. The governing design criteria for a CSP structure is generally its fatigue life, with the design focus being on the structural stress caused by constant wave action. If a CSP has been designed properly for fatigue, then it will always be able to withstand the most severe conditions.Myth 2: Boat collision regulations preclude CSPsRules vary from location to location, but many take a blanket approach of taking perceived best practice from one scenario and applying it across the board.For example, BS EN ISO 19902 structural design standards require that platforms be designed with reasonably foreseeable collision events in mind. A specic energy impact value is not stated, but 14MJ has traditionally been accepted. This represents a signicant event, with a 5000-tonne vessel drifting at a speed of 2 m/s (4 knots), in a sea-state with wave heights of 4m. How likely however is that scenario in most instances? For a CSP installation, a typical supply vessel might be only 100 tonnes, and is more likely to be approaching at 0.5 m/s than 2 m/s. The key is to focus on “reasonably foreseeable collision events,” and take a risk and evidence-based approach to deciding what they are, rather than relying on blunt received wisdom. Sharing the SecretCSPs are well-known to too few eld development planning engineers, and well-understood by even fewer. In a sense, they are the industry’s best kept secret. Engineers looking for a dry tree solution for a shallow water development should nd CSPs, such as Aquaterra Energy’s Sea Swift platform, to be a viable and attractive option. CSPs are capable of reducing capital expenditure, accelerating time to rst production and even helping with sometimes-tricky local content rules. Perhaps it’s time the secret got out?As a member of Aquaterra Energy’s Management Board, Rob is responsible for growing the company’s platforms and offshore structures business. Before joining Aquaterra Energy, Rob has held positions within Granherne, Petrofac and Worley where he was responsible for the early stage development of major projects within the upstream oil and petrochemicals businesses. This has included the conceptual and early phase engineering design of new upstream developments as well as the initiation of new products and services and several innovative nancing schemes.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com28OILMAN COLUMNPipeline Technology: Data’s Role in Midstream Pipeline Segmentation By Tonae’ HamiltonIn recent years, the role of technology has become more signicant in midstream and downstream operations. With the increased use of technology in the oil and gas industry, oil producers and service providers have been able to improve the efciency of their operations and maximize prots. Now with data and automation on the rise, the midstream market is bound to undergo a major transformation. A large number of oil and gas processing facilities are demanding more data collection and automation programming be put in place as a way to maximize output, reduce plant downtime, and increase their ROI. By increasing the use of data and analytics in midstream operations, oil and gas companies have the ability to observe and determine the efciency of their pipelines, solve problems and improve processes, and plan more strategically to improve their business. As a result, many oil and gas operators and oil and gas solution companies are partnering with or acquiring pipeline data and analytics companies to enhance operations or better their services. Rapidly growing provider of energy data analytics and advisory services, LawIQ, is one of the companies that has taken the initiative to acquire leading liquids pipeline rate and tariff data company, Lens On Washington. As expressed by Craig Heilman, LawIQ’s Chief Operating Ofcer, the purpose of the acquisition is to expand their widely used natural gas and liqueed natural gas analytics platform, and extend their customer base into the oil pipeline and exploration and production market.With the oil and gas industry experiencing an increased demand to improve and ramp up production, operators need feasible ways of obtaining and utilizing data to respond to such demand. Thus the assistance of oil and gas data and solution companies is crucial. Aware of the competitiveness within the oil and gas transporta-tion market, LawIQ acquired the LawIQ Liquids Database (formerly Lens On Washington) to extend and build on their data and analytics covering oil and other liquids products’ pipelines and improve access to valuable insights buried in tariffs and other lings. “Our customers need to know the details of origin and destination points and rates, so that they can position themselves effectively and protably,” stated Heilman. Their database, which has over 30 years of data, was meticulously aggregated and structured into an indispensable resource for customers.In addition, the ability to monitor pipelines in midstream operations has become a crucial need for oil and gas operators. By monitoring pipelines, operators can determine the effectiveness of their pipelines (i.e., which segments of the pipeline are useful, pipeline errors), predict outcomes and prevent future risks, and plan better business practices. In addition to combining data, technology, and expertise for customers to better anticipate events impacting their growth, LawIQ is one of the companies aiding operators in acquiring pipeline and infrastructure data to improve business operations, with their acquisition of Lens on Washington. “Our analytics platforms, research content, and advisory services help customers model and assess their risks and opportunities and serve as a foundation for teams across their enterprises to better understand regulatory, and market dynamics from origination to ongoing operations,” Heilman expressed. Although operational efciency is a key reason for the increased need for data, another signicant factor for operators seeking the use of data and analytics is revenue. LawIQ focuses on how data and technology can be used on the commercial side of the business for companies that own or develop energy infrastructure. “In our case, we leverage technology to help customers predicting regulatory timelines and costs that drive ROI and optimal infrastructure capacity” stated Heilman. With the use of data and analytics, operators would also have the ability to predict project and production costs and therefore, gain the advantage of thoughtfully planning out budgets and creating methods to reduce such costs. Though many operators expect to maximize ROI with the utilization of data and analytics to en-hance production, there are still issues that need to be addressed concerning production and pipe-line capacity. As Heilman explained, “Growth in production will never match takeaway. There is always a period of falling prices followed by an increase when pipeline capacity comes online, then another drop with additional capacity. Supply and demand imbalances and periods of price volatility and instability are persistent across basins.” With a lack of infrastructure to get more of the production to market, basins will be left congested and supply and demand could be impacted, along with revenue and cost of operations.Nevertheless, the oil and gas industry can still expect to see a rise in data and analytics with many operators investing in the solutions of data companies to improve pipeline operations and segmentation and discover potential business opportunities. “Teams use our platforms to baseline assumptions and data sets, benchmark projects, and identify commercial opportunities,” Heilman shared. In addition, the oil and gas solu-tion and software sub-industry has also become a competitive market, with an increased number of solutions companies seeking to improve the business practices and strategies of oil and gas facilities and the operations of the oil and gas industry overall through data and software. “We will always be looking for ways to grow our offer-ing of analytics platforms, research content, and advisory services,” stated Heilman.Data and analytics and pipeline technology overall has been in popular demand for the oil and gas industry in recent years. With many oil and gas operators in North America looking to monitor the efciency of their pipelines, improve midstream operations, and expand their prot and company growth, oil and gas data and solution providers are being invested in to help achieve such goals. Ultimately, as the industry undergoes a signicant technological transformation on the domestic front, such transformation is expected to happen on a global level. Heilman expressed that LawIQ would welcome the opportunity to work with global companies. “As we continue to grow our exports, we expect to assist companies outside of North America that have opportunities and exposure to North American infrastructure capacity and performance,” stated Heilman. Photo courtesy of Iurii Kovalenko – www.123RF.com

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Oilman Magazine / November-December 2019 / OilmanMagazine.com29OILMAN COLUMNCoarse Filtration: The “First Line of Defense” In Protecting Oil and Gas ProcessesMulti-element, automatic self-cleaning strainers optimize upstream and downstream production, while minimizing maintenance and downtimeBy Del WilliamsFor the oil and gas industry, coarse ltration of various uids is critical to ensure reliable production, extend the life of a wide variety of upstream and downstream equipment, and increase the intervals between backwashing or necessary maintenance. Upstream, production wells often use coarse ltration (from 30-100 microns) to remove sand, solids, or debris during secondary phase waterooding, where clean ltered water is introduced into a rock layer through injection wells to push residual oil to operating wells.Deep water rigs may prelter seawater to remove solids before further ltration for uses ranging from enhanced oil recovery, to heat exchangers, to producing potable water.Upstream, when oil is produced, liquid separation is used to separate produced water from the oil. Coarse ltration may be needed during the produced water treatment.In downstream applications coarse ltration may be 125-3200 microns. Reneries often prelter raw water from lakes, rivers, and aquifers to remove organic, aquatic, and other solids, which allows fresh water to be used as process and cooling water. In cooling towers, ltration can improve cooling efciency while reducing fouling and plugging. In process equipment, the removal of suspended scale and debris from heat exchangers and cooling systems can prevent the clogging of equipment and nozzles.“Without adequate coarse ltering of process uids, oil and gas systems can be susceptible to expensive damage from large particulates,” says Glenn Mountain, General Manager at R.P. Adams, a Buffalo, NY-based manufacturer of industrial ltration equipment. “Raw or produced water that is not adequately pre-ltered can cause excessive fouling, leading to decreased production as well as costly, premature replacement and unscheduled production downtime.” Fortunately, a growing number of oil and gas indus-try professionals are ensuring more reliable produc-tion with superior water or process uid quality by using low maintenance, multi-element, automatic self-cleaning strainers. This approach provides a more effective rst line of defense against equip-ment damage and downtime.Optimizing Process Reliability and ProductionHistorically, the oil and gas industry has utilized certain types of sand or media lters, centrifugal separators, and basket type strainers for coarse ltration. However, in many cases these have a number of shortcomings, including susceptibility to fouling and damage, which can require frequent cleaning, maintenance, and early replacement.“Whether for upstream or downstream processes, the industry wants to keep production going 24/7,” says Mountain. “So, the goal is to avoid equipment damage, process interruption, and having to pay maintenance technicians to open up lters for cleaning when they get dirty.”In response, many oil and gas industry professionals now rely on multi-element, automatic self-cleaning strainers like those from R. P. Adams. The company rst introduced and patented the technology in the 1960s, and has over 10,000 installations worldwide today.This design provides an alternative to sand and media lters, centrifugal separators, and basket type strainers. Unlike those designs, the multi-element, automatic self-cleaning strainers can provide continuous removal of suspended solids. When utilized as the “rst line of defense” for oil and gas water or uid ltration, the strainers can reliably lter out sand, silt, and other suspended solids as small as 30-100 microns in size.A signicant feature of the multi-element design is in the engineering of the backwash mechanism, which enhances reliability. With many traditional strainers, the backwash mechanism comes into direct contact with the straining media. This can be problematic, as large, suspended solids often encountered with raw or produced water can become lodged between the straining media and the backwash assembly. The result is straining media damage and/or rupture that can compromise ltration and even other downstream equipment, hindering production. Instead, the multi-element design utilizes a tube sheet to separate the straining media from the backwash mechanism. This prevents the backwash mechanism from coming into contact with the media and damaging the elements.Oil and gas industry operators often also need to consider how to best reduce membrane fouling and required maintenance. Traditional strainers, howev-er, due to limitations in straining area can become clogged quickly. When that occurs, cleaning, media replacement or backwash-ing is necessary, which adversely affects productivity as well as maintenance costs. In this regard, the multi-element design provides three to four times the surface area of traditional strainers and pre-lters. This translates directly into less frequent backwashing so less water goes to waste, less power is consumed, and less maintenance is required. While traditional media found in large basket designs can lead to collapse and failure under differential pressures as low as 35 PSID, the smaller diameter of the media used in the multi-tube strainers also enables the strainer to safely handle differential pressures in excess of 150 PSIG. This protects production even under higher differential pressures in the eld, which could otherwise result in signicant downtime.As an additional protective measure, the strainers also include a shear key, which sacrices itself in the presence of excessively large debris. So, if large de-bris were to cause mechanical problems within the strainer, the shear key breaks, protecting the unit’s rotating assembly, motor, and gearbox by halting the drive shaft rotation. Filtration continues, but opera-tors notice an increase in differential pressure as the backwash cycle is interrupted, and can take action to clear the obstruction and replace the shear key.For oil and gas environments exposed to highly corrosive elements like seawater or salt spray, upgrade options to materials such as super duplex and duplex stainless steels, titanium, Monel, Inconel, and Hastelloy can also provide further resistance to corrosion and corrosion-related damage.When considering technology for oil and gas course ltration systems, automatic multi-element, self-cleaning lters are an increasingly popular choice and a reliable, cost effective solution.Del Williams is a technical writer based in Torrance, California. He writes about health, business, technology, and educational issues, and has an M.A. in English from C.S.U. Dominguez Hills.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com30OILMAN COLUMNVirtual Reality is Not Just a Game, but Training By Andres Ocando With the passage of time, it is increasingly difcult to get trained personnel for the oil industry. The experience as a crane operator, drilling rig, welder, drilling oor engineer among others, will only be achieved with time, and practical knowledge is only acquired with practice.Worldwide companies use millions of dollars for the training of personnel in these areas, and they still have the risk of some problem when using the equipment they were trained for. This is why it can be highly difcult to nd experienced professionals in practical operations such as equipment management in the oil industry.Faced with this need, the virtual reality industry offers a solution to the oileld. By bringing together design professionals, architects, mechanical engineers, petroleum engineers and (as a key piece) engineers of the disciplines related to the computational area, such as computer, systems and virtual design engineers.With the aforementioned ingredients, we expect as a result a functional response to the need for practical staff training, and it has not been fully achieved, but there has been a growing process. Every time, more companies are venturing with these types of tasks and more and more operations are simulated for learning every day.When this type of service is hired, specialists in the area to be trained are mixed together with the virtual reality technology, which emulates the operating controls of the drill (if this is the type of operation to be learned), then every training provides practical and theoretical knowledge by specialists. This undoubtedly translates into less preparation hours and better results regarding staff learning.The investment when training staff with this type of tool represents a greater amount than the one that’s usually put in professional training with specialists in the area, but the risk of losses due to errors of non-experienced professionals is even greater.What is This Learning Based On?With replicas of the original controls to operate drills or cranes in some cases during teaching, the difculties that the operator can face could be modied, from environmental conditions to the occurrence of blowouts or accidents. It implies going further.By understanding that there are different types of learning, experienced professionals are used in the training areas, together with the virtual reality simulator. In this way kinesthetic, visual, auditory and reading learning are covered all at the same time.Nowadays, there is a signicant amount of companies that are dedicated to this training modality, but some dare to innovate a bit further.The Optimax MLA Simulator created by Castillo Max, a Venezuelan company, is a virtual reality system that allows the training of Marine Cargo Arms operators. With the use of this simulator, the transition from theory to practice in the handling of Load Arms by operators is facilitated.This mechanism gets to simulate different environmental conditions as well as different operating protocols, operational emergencies or extraordinary situations; and most important, the arm control scheme, as it includes original handlers of this type of equipment to recreate an experience as close to reality as possible.The position of marine cargo arms operator is a dangerous work and calls for a high responsibility, not only the component’s integrity is put in danger, but also human lives, like the diver in the bottom of the sea.On the other hand, we have the Luminous Company from the United Kingdom, which uses laser technology to copy scenarios, that is, with the structures scanning, you can create an exact copy of the location so the public can learn from the processes in the same place where they will be working.Despite not having controls schemes that are normally used in the oil and gas industry, this system allows the personnel training in the most important eld: safety. Using a 3D scenario with virtual reality in real time, it shows workers the structures to be occupied in their day-to-day labor, with the use of casual examples such as putting out the re, picking up tools on the oor or a check list to achieve the basic instruments of protection.Luminous offers to companies the ability to train people with real structures, either offshore or on land by changing environmental conditions or by varying the possible problems that the worker may face.Unigine is the Russian company pioneer in the use of virtual reality for personnel training, although it moves a little away from the drilling oors, it focuses on one of the sectors with the most exposure to danger the industry has: the reneries.In the past, accidents registered in reneries were due to lack or neglect of maintenance tasks. This is why Unigine has an Interactive Maintenance Training program that uses detailed virtual scenarios in which the apprentice can do several things, from moving into the premises to doing maintenance work to a power box, in order to start a process cooling pump, Optimax MLA Simulator – Photo courtesy of CastilloMax Oil and Gas

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Oilman Magazine / November-December 2019 / OilmanMagazine.com31OILMAN COLUMNand thus avoiding an accident in the future.In the reneries arduous search for qualied and attentive personnel, Unigine shows great progress, despite not having extreme emergency situations, as could happen in some cases, it gets very close to what is necessary for the development of common activities in a rening plant operator’s day.Q-bit Technologies, located in Palo Alto, CA, represents one of the most important presences in VR training for the oil industry, because it covers areas such as lifting, on land and offshore drilling, renery, and the implementation of virtual classrooms.They use the internet to provide theoretical training in virtual classrooms, and practice sessions in real time from anywhere in the world.And We Wonder, Why Virtual Classrooms?Well, in this line you have the duality of sharing classrooms with other people from other countries with rich experiences. At the same time, you can carry out drilling practices with people worldwide, who occupy different roles on the drilling oor or in reneries, depending on the chosen type of training. In this way, they could not only save time, but also money, since only the VR equipment and an internet connection are needed.Among the qualities of Q-bit are:• Industrial Machinery and Procedures VR training• Risk and Safety VR Training• Oil and Gas, Drilling and Renery Simulators, Oil & Gas VR Training• Hospital and Emergency Care Procedures VR Training• Soft Skill and Management VR Training• Collaborative VR Workshops and Virtual Reality Classrooms• Collaborative VR Training Environments• Virtual Reality Collaborative Training SimulationsAfter analyzing the different advances in VR technology for the oil industry, it shows that there is a long way to go. Although the demand is high, what the oil and gas industry looks for every day is highly trained personnel, which can be reliable for different practical activities such as drill, cranes and marine arms manipulation, or renery processes to name a few.The pending subject of this training modality would focus on the actual equipment controls and on being able to simulate experienced situations in order to prepare their staff, not only to face the ideal scenario, but also the most difcult tasks, such as a pressure increase during drilling, as an example.It is expected that one day VR simulators can train a diver and a sub-marine arm operator in real time, by using the North Sea waters as a scenario, among other activities. Apparently, that day is nearer that we think.Therefore, it is not an easy task for VR engineers joined with the oil and gas specialists, but in terms of security, the sum invested in training and safety is usually not restricted in the oil companies. For this reason, the VR appears as an option with more and more importance.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. Unigine VR Refinery Model – Photo courtesy of Unigine Qbit VR Drilling Platform Training Situations and Qbit VR Training – Photos courtesy of Qbit TechnologiesLuminous 3D Laser Scan – Photos courtesy of Luminous

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Oilman Magazine / November-December 2019 / OilmanMagazine.com32OILMAN COLUMNThe State of Water 2019: How to Sustain the Oil and Gas Industry’s Lifeblood By Blythe Lyons, John Tintera and Kylie Wright Led by unconventional play development, the U.S. is closer than ever to energy independence. Texas plays a leading role in the current U.S. oil and gas boom. Yet Texas has a two-fold challenge born of this success: The state must source huge amounts of water for fracturing operations, often in arid, drought-prone areas. At the same time, it must manage billions of gallons of produced water from these onshore unconventional operations. To maintain its oil and gas production capabilities, Texas must continue to make its signature strides in management of produced water and expand recycling and reuse opportunities. To this end, the Texas Alliance of Energy Producers (the Alliance) and the IPAA (Independent Petroleum Association of America) teamed up to publish the white paper: “Sustainable Produced Water Policy, Regulatory Framework, and Management in the Texas Oil and Gas Industry: 2019 and Beyond.” The paper is a sequel to one we wrote in July 2014, “Sustainable Water Management in the Texas Oil and Gas Industry,” which was published by the Atlantic Council. The following factors drove our decision to update that paper:• Data points to exponential increases in the amount of produced water that the industry will generate over the next ve years. In the Permian Basin alone, produced water output will reach a level of 8.5 billion barrels of water by 2024. (See Table) Table: Produced Water Projections to 2024 for the Permian BasinYear MMbbl/year2019 7,0902020 7,4002021 7,6702022 7,9902023 8,2402024 8,510Source: B3 Insight, 2019• Texas has done many things right – including legislative and regulatory actions – to encourage safe and economic produced water reuse and recycling options. However, more remains to be done at both the state and federal levels. • Produced water recycle and reuse is likely to increase as the midstream water management industry continues to mature, demand for fracturing water grows, freshwater and trucking costs increase, treatment costs decline, and injection capacity is constrained.• Current and emerging treatment technologies can support cost-effective recycle and reuse in the oil and gas industry. However, no silver bullet technology exists that would replace the need to maintain disposal capacity. We report on factors that impact the costs of and availability to access saltwater disposal wells going forward.Published on September 16, the white paper outlines 10 recommendations to encourage the economical and sustainable recycling and reuse of produced water. We hope this can serve as a model for other states. The report centers around three guiding principles related to state and federal policy and regulation: 1. Texas must maintain leadership and control over produced water management; 2. Texas must continue to update its laws, regulations, and practices; and 3. The federal government must update its rules and continue discussions with its state partners.Here are the 10 specic recommendations:Maintain State Leadership and Control Over Produced Water Management:1. Preserve the RCRA (Resource Conservation and Recovery Act) exemption: The RCRA exemption gives Texas primary jurisdiction over produced water. The existing RCRA regulatory framework is the keystone for nearly all oil eld waste management practices – and essential for expanding produced water management options. It is imperative that Texas preserve the RCRA exemption. 2. Delegate NPDES (National Pollutant Discharge Elimination System) authority to Texas: Texas recently passed legislation that will lead to the consolidation of state authority for discharge permitting. The new law directs the TCEQ (Texas Commission on Environmental Quality) to seek delegation from the EPA for oil and gas wastewater discharge. Achieving this NPDES delegation – target timeline is 2021 – would simplify permitting and expand reuse options for produced water in Texas. 3. Maintain Texas jurisdiction over pipelines: Texas regulates produced water pipelines via a comprehensive framework as well as state eld employees who regularly Source: Tintera, J., Lyons, B.J., Wright, K.A. 2019. Sustainable Produced Water Policy, Regulatory Framework, and Management in the Texas Oil and Natural Gas Industry: 2019 and Beyond. Texas Alliance of Energy Producers and IPAA.10 Policy Recommendations for the Sustainable Use of Produced Water

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Oilman Magazine / November-December 2019 / OilmanMagazine.com33OILMAN COLUMNinspect produced water operations and maintenance activities. The state currently has an all-time high of lled inspector positions with 69 pipeline safety inspectors and 170 oil and gas inspectors. Any federal usurpation of state oversight by agencies such as the PHMSA (Pipeline and Hazardous Material Safety Administration) would burden the recycling industry and add little value. Continue to Update State Laws, Regulations and Practices:4. Increase interstate and association policy coordination: Texas government and industry ofcials should participate in nongovernmental organizations with broad representation across the states to share best practices and other information. The eventual goal would be to standardize policy across the U.S. as much as realistically possible given the differences in local geographic conditions and state regulations. This can be accomplished through the auspices of the IOGCC (Interstate Oil and Gas Compact Commission), which gathers ofcials from across the country to meet regularly and discuss policy and issues. Other organizations such as the national GWPC (Groundwater Protection Council) should be supported as a vehicle for producing valuable research. In June 2019, the GWPC published a produced water report that will advance the conversation on hydrocarbon extraction management, regulations, and overall energy security.5. Revise produced water statutes and regulations: The oileld regulatory framework in Texas is well funded by the state legislature, has modern and updated regulations, and is competently administered by accountable state regulators. Yet the midstream recycling industry is rapidly evolving. As scientic knowledge expands, technology progresses, and new facts are uncovered, Texas regulators must draft rules that keep pace with these advancements. The state has made strides here in the past several years. For instance, some recycling is now PBR (Permitted by Rule), a concept that has encouraged produced water recycle and reuse. On May 16, 2019, the U.S. House Subcommittee on Energy and Mineral Resources invited California, Ohio, South Dakota, and Texas to testify on hydraulic fracturing and state regulation of produced water. Alliance President John Tintera gave testimony that clearly demonstrated Texas’ impressive and effective regulatory framework, which is a model that could help other states address regulatory concerns.6. Prepare a roadmap for benecial reuse outside the oil and gas industry: The industry should continue to advance the state of the art, hone its operations, and follow sound produced water management practices in the oileld. Meanwhile, the government can encourage uses outside the oilelds by creating a roadmap of how to update regulations, sponsor research, and issue permits for pilot studies. Scientic research must be supported through a solid, repeatable funding mechanism.7. Develop incentive mechanisms: In the recent Texas legislative session, legislators voted against several bills that would have provided tax relief or tax credits for documented produced water recycling activities. For example, one bill that failed specied tax credits for desalters, including those handling produced water. These incentives would lower produced water treatment costs, facilitate higher recycle rates, and eventually lead to benecial reuse of produced water. Legislators expressed interest in an interim study of incentives and economic impacts, which they should pursue and learn from for the next legislative session in 2021. 8. Collect and provide public access to better produced water data: Standardized, statewide produced water data is needed to track water volumes and production activity. This information would also help communicate the value of produced water and the opportunities recycling represents. Texas should determine the best mechanisms to collect and publish this data in a way that is not onerous or costly to the industry. The industry itself should standardize produced water terminology, reporting, and disclosure.Federal Government Agencies Must Update Rules and Work with State Partners:9. Update or eliminate 98th Meridian policy: The 98th Meridian is an arbitrary geographic marker the EPA uses to separate discharge permitting under NPDES rules. The meridian bisects Texas into land roughly east or west of Dallas. Under the current federal regulatory scheme, onshore discharges east of 98th Meridian are typically not authorized. For onshore discharges west of 98th Meridian whose “produced water has a use in agriculture or wildlife propagation,” benecial use permit applications may be considered. The EPA must eliminate or modify this federal regulatory contrivance. It is not reective of the current technological advances in recycling or the need for site specic permit conditions independent of broad national controls.10. Institutionalize Texas and federal agency cooperation: Some states have been working with the EPA on memorandums of understanding, white papers, and other endeavors involving produced water. In May 2019, the EPA issued its own draft “Study of Oil and Gas Extraction Wastewater Management,” which will be nalized by year end. These efforts are laudable, and Texas should pursue similar opportunities to collaborate with the EPA and DOE.Texas has created an environment where produced water is no longer just a waste; it can be a valuable resource. As the nation’s oil and gas leader, the state must vigorously defend its legislative and regulatory framework against federal oversight and evolve them as needed to promote the recycle and reuse of produced water. It’s time for the next generation of innovation, with careful consideration of these 10 recommendations. John Tintera is the past President of the Texas Alliance of Energy Producers. He is the former Executive Director of the Texas Railroad Commission and is a regulatory expert and licensed geologist (Texas #325) with a thorough knowledge of virtually all facets of upstream oil and gas exploration, production and transportation, including conventional and unconventional reservoirs. Blythe Lyons serves as a consultant to the Texas Alliance of Energy Producers, and was formerly a Senior Fellow with the Atlantic Council’s Energy and Environment Program. Kylie Wright is a Senior Environmental Specialist with GAI Consultants, Inc., and is a former geologic consultant with the Texas Alliance of Energy Producers.. Photo courtesy of Ronald Loveday – www.123RF.com

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Oilman Magazine / November-December 2019 / OilmanMagazine.com34OILMAN COLUMNThe Rule of Capture has been a foundational concept of oil and gas prospecting for 150 years. The Rule of Capture exists to provide an afrmative defense to drillers when they tap into oil and gas pockets that cross property lines. As ctional oilman Daniel Plainview so aptly described it in the lm There Will Be Blood, “Underground, there’s no way to know whose milkshake is whose.”But does the venerable Rule of Capture apply to ssures and proppants crossing property lines during hydraulic fracturing? And if not, where does that leave production companies accused of subsurface trespass? In 2008, the Texas Supreme Court in Coastal v. Garza held that the Rule of Capture shielded Coastal from liability for trespass claims arising from hydraulic fracturing operations. But an appeals court in Pennsylvania has found just the opposite—that the Rule of Capture defense does not apply to hydraulic fracturing activities. Both Texas and Pennsylvania are two of the leading natural gas-producing states in the country and divergent opinions on the application of the Rule of Capture to hydraulic fracturing activities is particularly noteworthy. The Pennsylvania Supreme Court agreed to consider the issue and heard oral arguments in September 2019. Their ultimate decision could have far-reaching and long-term repercussions on the entire industry.Fracing Company Loses in Pennsylvania Court; Appeals to State Supreme CourtIn Adam Briggs et al. v. Southwestern Energy Production Co., a Pennsylvania family claims that a fracking operation next to their property unlawfully crossed over into their 11-acre lot to tap into gas pockets.A three-judge panel in Pennsylvania Superior Court sided with the plaintiffs in 2018, nding that the Rule of Capture does not apply to fracking operations. The ruling overturned a 2015 decision by a lower court, which dismissed the lawsuit on Rule of Capture grounds.At issue is the very technology used in fracking. Traditional oil and gas development taps into pockets of natural resources. But fracking involves the injection of proppants, or pressurized uids, into solid rock formations in order to release natural gas and hydrocarbon liquids trapped within. The plaintiffs compared this process to a drill bit digging into their property. The court ruled that this procedure is invasive to the point of being substantively different from traditional well drilling and, thus, not protected by the Rule of Capture.“In light of the distinctions between hydraulic fracturing and conventional gas drilling, we conclude that the rule of capture does not preclude liability for trespass due to hydraulic fracturing,” the Pennsylvania Superior Court wrote in its decision.In its lings to the state’s Supreme Court, Southwestern Energy Production argued that if the Superior Court’s ruling is allowed to stand, it would create mass confusion among oil and gas producers and open up virtually every fracking operation to subsurface trespass claims. “Settled expectations would be upended if this court were to limit [“the Rule of Capture’s”] application in this case,” the defendants wrote in a brief to the Pennsylvania Supreme Court.Texas Supreme Court Says Rule of Capture is a Valid Defense to Trespass ClaimsThe Pennsylvania Superior Court’s decision is contrary to the 2008 ruling of the Texas Supreme Court in Coastal Oil & Gas Corp. v. Garza Energy Trust, et al. In Coastal, the dispute arose between two energy companies. The plaintiffs claimed that Coastal’s fracking operations in Hidalgo County, Texas drained gas from a reservoir underneath the plaintiffs’ nearby tract.The court’s majority did not rule on the question of whether or not such activity could be considered trespassing. But they did say that in order to be actionable, trespass must cause injury and due to the Rule of Capture, there Whose Milkshake is Whose?: Pennsylvania Supreme Court Considers Whether the Rule of Capture Appliesto Hydraulic Fracturing By Tony Guerino and Liz KlingensmithPhoto courtesy of Vladimir Endovitskiy – www.123RF.com

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Oilman Magazine / November-December 2019 / OilmanMagazine.com35OILMAN COLUMNcould be no nding of injury. The majority wrote that the owner of mineral rights has “title to the oil and gas produced from a lawful well bottomed on the property, even if the oil and gas owed to the well from beneath another owner’s tract.” In other words, the Rule of Capture protected Coastal from trespass claims.The Texas Supreme Court rejected arguments from the plaintiffs that fracking is an “unnatural” activity, pointing out that all drilling for oil and gas is a human-directed, and thus unnatural, activity. The Court also outlined several points in favor of keeping the Rule of Capture in place, including for fracking operations. They noted that property owners have other business and legal remedies available to protect their interests, including simply drilling their own wells to capture the gas on their property. In his concurrence, Justice Don Willett noted the importance of the oil and gas industry to the Texas economy, and wrote that overturning the Rule of Capture for fracking would leave much of the state’s valuable natural resources untapped and unusable. “The Court today averts an improvident decision that, in terms of its real-world impact, would have been a legal dry hole, juris-imprudence that turned booms into busts and torrents into trickles. Scarcity exists, but above-ground supply obstacles also exist, and this Court shouldn’t be one of them,” he wrote.However, the Texas decision was not unanimous. Dissenting justices wrote that the Rule of Capture only applies to legal oil and gas production methods. Just as the plaintiffs in both Texas and Pennsylvania have done, the dissenters on the court likened fracking across property lines to an oil drill that unlawfully crosses property lines.“Both involve a lease operator’s intentional actions which result in inserting foreign materials without permission into a second lease, draining materials by means of the foreign materials, and ‘capturing’ the minerals on the rst lease,” the dissenting justices wrote.What’s Next for Fracking Industry, Rule of Capture?Without a doubt, all eyes are on Pennsylvania and that state Supreme Court’s consideration of Briggs v. Southwestern Energy. Interested parties are weighing in on both sides, with energy companies asking the Supreme Court to overturn the Superior Court decision and property rights advocacy groups urging the Justices to uphold it.If the Supreme Court sides with the plaintiffs, the effects on Pennsylvania’s natural gas industry could be chilling. The Rule of Capture acts as an afrmative defense to trespass claims. The Briggs decision obliterates that defense, and anyone in the unconventional natural gas and liquids business would have to think long and hard before undertaking any fracking operations in the Keystone State, which is home to the gas-rich Marcellus Shale.Observers also correctly wonder what a plaintiffs’ verdict in Briggs would mean nationally. At least in the short term, it likely would mean a great deal of state-to-state variation in how the Rule of Capture is applied. Company ofcials would need to be aware of any particular state’s approach if they intend to conduct fracking operations in that state.For example, West Virginia’s Supreme Court of Appeals issued a ruling in June 2019 (EQT Production Co. v. Crowder et al.) that horizontal drills that cross property lines underground, even if not producing from that strata, constitute subsurface trespass, and that gas companies cannot drill such wells without the permission of the neighboring property owner. Even though distinguishable from alleged trespass arising from ssures and proppants resulting from hydraulic fracturing, the Court took a broad perspective when it wrote, “This court will not imply a right to use a surface estate to conduct drilling or mining operations under neighboring lands.” Those operations arguably include the effects of hydraulic fracturing. With fracking operations taking place across the country, it seems likely that more and more state courts will be forced to reconsider the age-old Rule of Capture for a modern-day energy industry.Tony Guerino and Liz Klingensmith are energy and environmental litigators serving the oil and gas industry. They are Partners in Womble Bond Dickinson’s Houston ofce. 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! We have a creative team that can design your ad! Call us (800) 562-2340 Ex. 1 OilmanMagazine.com/advertise Advertising@OilmanMagazine.com

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Oilman Magazine / November-December 2019 / OilmanMagazine.com36OILMAN COLUMNFrom Gemini Corporation to Gemini Fabrication: Recovery after Receivership By Tonae’ HamiltonAny corporation can succumb to nancial hardship, bankruptcy, or receivership at any given time, no matter the industry. Unfortunately, Gemini Corporation, a 30-year professional services rm that provided multi-disciplined engineering, eld, and environmental services for energy and industrial facilities is one of the corporations that went into receivership last year in April. With the company staggering in growth and prot for its last several quarters and underperforming in its third quarter back in 2017, it underwent restructuring. The ofcial release announced that the restructuring would include “changes to the executive leadership team and signicant reductions in personnel resulting in a $6 million annual reduction in overhead costs.”With the announcement of restructuring, the operational staff at the time experienced a lot of uncertainty. “In uncertain times, it is very difcult to stay focused on the task at hand,” stated Andy Farrow, President of Gemini Fabrication, the company that developed out of Gemini Corporation. As a result, Gemini Corporation saw the departure of executive leaders including Peter Sametz, president and CEO, and Roger Harripersad, vice president of Human Resources.FTI Consulting Canada Inc. was appointed the receiver and manager of all of Gemini’s current and future assets. With the restructuring and receivership order, Gemini Corporation was almost completely wiped out, along with all the jobs attached to it. That is, until the team of the Ponoka Plant worked together to salvage what they could of Gemini. “It was an outside party that ultimately acquired the Gemini assets, hired the operational teams and created Gemini Fabrication Ltd., but it was the team in Ponoka that really pulled together to try and keep things going during the receivership,” Farrow explained. Thanks to the efforts of the Ponoka team, along with the outside support they received, they were able to save the fabrication entity of Gemini and 150 jobs, and make Gemini Fabrication succeed in the same facility where things almost fell apart. Today, the Gemini name has transitioned to “Gemini Fabrication,” which still remains on the 56-acre facility. Although Gemini Fabrication does not retain executives or board members once associated with parent company Gemini Corporation, it has made efforts to retain some of the same values as its predecessor company. “We have tried to uphold some of [Gemini Corp’s] values that were very good, such as their commitment to safety. Gemini, through its history has always made safety a priority which continues today as a pillar of the business,” expressed Farrow.Although the companies share a few similari-ties in values, Gemini Fabrication is far from the image of its predecessor company. Farrow explained that Gemini Fabrication is a much more focused organization with a goal to be rec-ognized as the #1 fabricator in Western Canada within ve years. “We are a lean organization that doesn’t have extra layers of management, which also allows the people doing the work to be more engaged in what they are doing. We are focused on being an industry leader in terms of Safety, Quality, Price and Delivery,” Farrow further explained.With a complex history, dedicated team, and plan for continued success, Gemini Fabrication has shown that anything is possible, with it currently being recognized as one of the largest employers in the Ponoka AB area. The company celebrated their one-year anniversary on October 1st and is on its way to being the #1 fabricator in Western Canada. Farrow offered his advice to companies currently undergoing the same or similar events as Gemini Fabrication’s predecessor company once did before succumbing to receivership. “Staying ahead of the down cycle is critical because you can’t save money after you have spent it. You need to stay focused on what you are best at and where you can add the most value. Time is a limited resource and if you’re focused on chasing something you’re less capable of doing, you’ll miss the opportunity to focus on the things you do well,” Farrow expressed. Andy Farrow, President, Gemini Fabrication – Photos courtesy of Gemini Fabrication

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Oilman Magazine / November-December 2019 / OilmanMagazine.com38OILMAN COLUMNRobotic Process Automation: Four Key Considerations for Oil & Gas By Steven Bradford and Kent LandrumMany energy companies have embarked on signicant digital transformation projects utiliz-ing emerging technologies such as big data, cloud, mobile, APIs (Application Program Interfaces), natural language processing, machine learning and RPA (Robotic Process Automation) to reduce costs and streamline operations. In a recent discussion with an organization contemplating a major RPA initiative in the commercial and logistics area, the possibility of investing some time up front on process improvement, along with RPA implementa-tion, was raised. A Case for Process Improvement The response from the client was basically, “No, why do I need to spend time optimizing or reworking processes anymore when I can just automate them?” The query appeared simple on its surface, but it calls into question the role that process improvement methods ranging from TQM, to ISO 9000, to Lean and Six Sigma plays in a world lled with software bots and AI workers (especially outside of manufacturing). It challenges the notion that master data management and governance are foundational for technology-enabled operational excellence and questions the value proposition of simplication in the form of reduced customization and application portfolio rationalization.The reality is that it’s not quite so black and white but, rather, lies somewhere along a continuum for most companies contemplating how best to leverage automation. Below are four key reasons to consider combining process improvement/optimization with any major RPA initiative:1. Lower Technology Implementation CostsImplementation cost almost always represents one of the highest initial hurdles to any information technology initiative. Adding a process optimiza-tion lens to RPA projects can serve to reduce implementation cost in a number of different ways. Perhaps most obviously, automating fewer and simpler processes will require less IT resource effort. Time spent up front to clarify process owners, actors, steps/tasks, hand-offs, informa-tion inputs and outputs, etc. will pay dividends by simplifying requirements gathering. Standardizing and simplifying processes will reduce the amount of complex exception logic that must be congured or developed. Removing unnecessary or unrelated steps in the process may also present opportuni-ties to reduce the number of integration points between systems, which can be a signicant cost driver. These benets continue to accrue through-out the implementation project lifecycle as the more focused process scope streamlines development/training of the bots, compresses testing complexity and effort and reduces delivery risk by eliminating many unknowns. Finally, many RPA solutions are licensed in a manner that increases cost based on the number of bots or processes being managed, so rationalizing the number of actors and process steps may provide some relief both at project kick-off, as well as in steady-state operations.2. Reduced Ongoing Maintenance & Support CostsThe introduction of virtually any new technology such as RPA into an organization has the poten-tial to increase IT operating cost by consuming infrastructure resources either on premises or in the cloud be it CPU, memory, storage, bandwidth or otherwise. On the other hand, many of the benets of including a process improvement component in an RPA project compound over time long after the initial system implementation. Calling out these savings opportunities can help establish the benets case necessary to secure project approval and ensure that funding can be made available for other value-generating investments across the IT portfolio. In many instances, the time savings on the business side alone are insufcient to justify the investment; however, identifying and articulating recurring IT cost reductions can help substantiate the business case. Fewer, simpler processes will result in a smaller sustainment burden for business subject matter experts and IT support staff given a lower number of processing errors that require troubleshooting. These savings multiply when the cost of shadow IT within the business necessary to compensate for poor data quality resulting from ineffective processes is taken into consideration. Patches, upgrades, extensions and enhancements to the underlying systems utilized by the automated processes will be less costly as a result of more straightforward integration and more compact regression testing requirements. 3. Enhanced Reliability & ResiliencyRecent business continuity events such as Hurricane Harvey or the Shamoon cybersecurity attack expe-rienced by energy companies have highlighted the importance of an organization’s ability to operate and meet commitments to key stakeholders even in the face of signicantly impaired IT capability. Process automation certainly has the potential to compensate for many of the mistakes of the past by powering through unnecessarily arduous tasks in a very cost-effective manner. However, energy companies should carefully consider how they will continue to operate if the RPA platform and/or related systems were rendered unavailable. During a business continuity incident business teams will need to fall back on manual transaction processing and during such episodes the benet of optimized and well documented processes will be highly vis-ible. Ensuring that the most critical processes are simple, well understood, documented and built to operate effectively in a business continuity context will be of increasing importance in the future. 4. Greater Enterprise Value CreationThe focus of most RPA initiatives in the past has been on taking cost out of the organization by automating repetitive steps performed by employ-ees in transaction processing. However, adding a process improvement component from the outset can help identify opportunities to eliminate unnec-essary processes altogether, streamline those that remain and create value in new and differentiated ways. While automation can simplify what oil and gas companies do today some of the most power-ful prospects for its application lie in the ability to offer incremental value-added services to customers that cannot be provided in a cost-effective manner today. Leveraging a company’s past investment in skillsets such as BPR/BPM, TQM, ISO 9000, Lean, Six Sigma, etc. and partnering with outside experts can help identify and unlock these opportunities to make the most from a technology investment in process automation. ConclusionRPA offers signicant opportunity as a central component in any oil and gas company’s digital transformation strategy. The ability to capitalize on the base investment to maximize return by controlling costs, increasing resiliency and delivering new value-creating capabilities can be signicantly enhanced by putting early emphasis on process us-ing time-tested methodologies and proven business insight. Project sponsors and managers of automa-tion initiatives should carefully consider building these elements into their projects from the outset.Steven Bradford is a Managing Director with Opportune’s Process & Technology prac-tice. He has over 23 years of leadership experience in busi-ness transformation, systems/technology implementation, business process and controls improvement. Kent Landrum is a Director, Process & Technology at Opportune LLP. He has more than 18 years of diversied information technology experience with an emphasis on solution delivery for the energy industry.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com40OILMAN COLUMNHistory tells that in the past Standard Oil company – for the sake of distinguishing – painted barrels that were used to carry crude oil in blue color (while those for kerosene – in red). Therefore, the rst letter “b” stands for “blue.” But this is a non-grounded myth as “blue” was carried by the barrel many years well before Standard Oil was created at all. A more realistic look at the fact that the Vikings used wooden barrels to store salted herrings, which, as you know, shine blue.Actually, Richard III, King of England from 1483 until 1485, had dened the wine puncheon as a cask holding 84 gallons and a wine tierce as holding 42 gallons. By 1700 custom had made the 42 gallon watertight tierce a standard container for shipping eel, salmon, herring, molasses, wine, whale oil and many other commodities in the English colonies. After the American Revolution in 1776, American merchants continued to use the same size barrels.Oil companies that are listed on American stock exchanges typically report their production in terms of volume and use the units of bbl, Mbbl (one thousand barrels), or MMbbl (one million barrels) and occasionally for widest comprehensive statistics the Gbbl (or sometimes Gbl) denoting a billion. There is a conict concerning the units for oil barrels. For all other physical quantities, according to the International System of Units, the uppercase letter “M” means “mega-” (“one million”), for example: Mm (one million metres, megameters), MHz (one million hertz, or megahertz), MW (one million watts, or megawatt), MeV (one million electronvolt, or megaelectronvolt). But due to tradition, the Mbbl acronym is used in the USA today meaning “one thousand bbl,” as a heritage of the roman number “M” meaning “one thousand.” On the other hand, there are efforts to avoid this ambiguity, and most of the barrel dealers today prefer to use bbl, instead of Mbbl, mbbl, MMbbl or mmbbl.Outside the United States, volumes of oil are usually reported in cubic metres (m3) instead of oil barrels. Cubic meter is the basic volume unit in the International System. In Canada, oil companies measure oil in cubic metres, but convert to barrels on export, since most of Canada’s oil production is exported to the USA. The nominal conversion factor is 1 cubic meter = 6.2898 oil barrels, but conversion is generally done by custody transfer meters on the border, since the volumes are specied at different temperatures, and the exact conversion factor depends on both density and temperature. Canadian companies operate internally and report to Canadian governments in cubic metres, but often convert to U.S. barrels for the benet of American investors and oil marketers. They generally quote prices in Canadian dollars per cubic meter to other Canadian companies, but use U.S. dollars per barrel in nancial reports and press statements, making it appear to the outside world that they operate in barrels.Companies on the European stock exchanges report the mass of oil in metric tonnes. Since different varieties of petroleum have different densities, however, there is not a single conversion between mass and volume. For example, one tonne of heavy distillates might occupy a volume of 256 U.S. gallons (6.1 bbl). In contrast, one tonne of crude oil might occupy 272 gallons (6.5 bbl), and one tonne of gasoline will require 333 gallons (7.9 bbl). Overall, the conversion is usually between 6 and 8 bbl per tonne.The measurement of an “oil barrel” originated in the early Pennsylvania oil elds. The Drake Well, the rst oil well in the U.S. was drilled in Pennsylvania in 1859, and an oil boom followed in the 1860s. When oil production began, there was no standard container for oil, so oil and petroleum products were stored and transported in barrels of different shapes and sizes. Some of these barrels would originally have been used for other products, such as beer, sh, molasses or turpentine. Both the 42-U.S. gallon (159 l) barrels (based on the old English wine measure), the tierce (159 liters) and the 40-U.S. gallon (151.4 l) whiskey barrels were used. Also, 45-U.S. gallon (170 l) barrels were in common use. The 40 gallon whiskey barrel was the most common size used by early oil producers, since they were readily available at the time.In August 1866, at the height of the oil boom in northwestern Pennsylvania, a handful of American independent oil producers met in Titusville. One of the issues that were discussed at this meeting was the coordination of standard containers for oil supplies to consumers. As a result, a 42 gallon volume was agreed as a standard oil barrel.Already by the year 1700, everyday practice in Pennsylvania and accumulated experience led to the fact that the sealed wooden barrel of 42 gallons became the de facto standard container for transporting sh, molasses, soap, wine, oil, whale oil and other goods.Barrels with a capacity of 42 gallons when lling them with oil had just such a weight that one healthy person could handle. One person could not cope with larger barrels, and the use of smaller barrels was not so economically Why bbl? Energy Units in the USA and Other Countries By Eugene M. Khartukov

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Oilman Magazine / November-December 2019 / OilmanMagazine.com41OILMAN COLUMNadvantageous. In addition, 20 barrels with a capacity of 42 gallons were ideally placed on typical, at that time, barges and railway platforms.Thus, choosing a 42 gallon barrel as an industry standard was a logical and natural step for early oil producers. In 1872, the American Petroleum Association ofcially approved a 42 gallon barrel as a standard.Currently, oil, of course, is no longer transported in any barrels. It is transported by tankers and oil pipelines. But the oil barrel as a unit of measure remained in the practice of world oil trade.Then why is the abbreviation “bbl” used to refer to a barrel? Why are there two letters “b” in the barrel designation (bbl), although the English word barrel has only one “b?”Popular rumor says that such an abbreviation owes its origin to the phrase blue barrel. The fact is that in the early practice of Standard Oil, it was to paint its oil barrels in blue. The blue barrel was a kind of guarantee that its volume is 42 gallons.But upon careful reading, you may notice the use of the abbreviation “bbl” in Sally Brig Ship Cargo Declaration dated September 11, 1764.There are other hypotheses about the origin of the abbreviation “bbl.” For example, some believe that bbl was used to indicate the plural. That is, one barrel is 1 bl, two barrels is 2 bbl, etc. Others believe that the abbreviation “bbl” was used to mean the word “barrel” so as not to confuse it with the word “bale.” That is, 1 bl is one bale, and 1 bbl is one barrel.In general, the truth is somewhere nearby. But what is a real truth there, it is no longer to nd out. However, as it was mentioned above, the “viking” hypothesis seems the most realistic.Around 1866, early oil producers in Pennsylvania came to the conclusion that shipping oil in a variety of different containers was causing buyer distrust. They decided they needed a standard unit of measure to convince buyers that they were getting a fair volume for their money, and settled on the standard wine tierce, which was two gallons larger than the standard whisky barrel. The Weekly Register, an Oil City, Pennsylvania newspaper, stated on August 31, 1866 that “the oil producers have issued the following circular:”Whereas, it is conceded by all producers of crude petroleum on Oil Creek that the present system of selling crude oil by the barrel, without regard to the size, is injurious to the oil trade, alike to the buyer and seller, as buyers, with an ordinary sized barrel cannot compete with those with large ones. We, therefore, mutually agree and bind ourselves that from this date we will sell no crude by the barrel or package, but by the gallon only. An allowance of two gallons will be made on the gauge of each and every 40 gallons in favor of the buyer.And by that means King Richard III’s English wine tierce became the American standard oil barrel.By 1872, the standard oil barrel was rmly established as 42-U.S. gallons. The 42 gallon standard oil barrel was ofcially adopted by the Petroleum Producers Association in 1872 and by the U.S. Geological Survey and the U.S. Bureau of Mines in 1882.In modern times, many different types of oil, chemicals, and other products are transported in steel drums. In the United States, these commonly have a capacity of 55-U.S. gallons (208 l) and are referred to as such. They are called 210-litre or 200 kg drums outside the United States. In the United Kingdom and its former dependencies, a 44-imperial-gallon (200 l) drum is used, even though all those countries now ofcially use the metric system and the drums are lled to 200 liters. Thus, the 42-U.S. gallon oil barrel is a unit of measure, and is no longer a physical container used to transport crude oil, as most petroleum is moved in pipelines or oil tankers. In the United States, the 42-U.S. gallon size of barrel as a unit of measure is largely conned to the oil industry, while different sizes of barrel are used in other industries. The abbreviations “Mbbl” and “MMbbl” refer to one thousand and one million barrels respectively. These are derived from the Latin “mille,” meaning “thousand.” This is different from the SI convention where “M” stands for the Greek “mega,” meaning “million.” Outside of the oil industry, the unit Mbbl (megabarrel) can sometimes stand for one million barrels. Some sources assert that “bbl” originated as a symbol for “blue barrels” delivered by Standard Oil in its early days. However, while Ida Tarbell’s 1904 Standard Oil history acknowledged that the abbreviation “bbl” had been in use well before the 1859 birth of the U.S. petroleum industry.Oil wells recover not just oil from the ground, but also natural gas and water. The term BLPD (Barrels of Liquids per Day) refers to the total volume of liquid that is recovered. Similarly, barrels of oil equivalent or BOE is a value that accounts for both oil and natural gas while ignoring any water that is recovered.Other terms are used when discussing only oil. These terms can refer to either the production of crude oil at an oil well, the conversion of crude oil to other products at an oil renery, or the overall consumption of oil by a region or country. One common term is barrels per day (BPD, BOPD, bbl/d, bpd, bd, or b/d), where 1 BPD is equivalent to 0.0292 gallons per minute. One BPD also becomes 49.8 tonnes per year. At an oil renery, production is sometimes reported as barrels per calendar day (b/cd or bcd), which is total production in a year divided by the days in that year. Likewise, barrels per stream day (BSD or BPSD) is the quantity of oil product produced by a single rening unit during continuous operation for 24 hours.Continued on next page...

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Oilman Magazine / November-December 2019 / OilmanMagazine.com42OILMAN COLUMNWhen used to denote a volume, 1 bbl is exactly equivalent to 42-U.S. gallons and is easily converted to any other unit of volume. A volume of 1 bbl is exactly equivalent to a volume of 158.987294928 liters.In the oil industry, following the denition of the American Petroleum Institute, a standard barrel of oil is often taken to mean the amount of oil that at a standard pressure (14.696 psi) and temperature (60°F) would occupy a volume of exactly 1 bbl. This standard barrel of oil will occupy a different volume at different pressures and temperatures. A standard barrel in this context is thus not simply a measure of volume, but of volume under specic conditions. The task of converting this standard barrel of oil to a standard cubic meter of oil is complicated by the fact that the standard cubic meter is dened by the American Petroleum Institute to mean the amount of oil that at 101.325 kPa and 15°C occupies 1 cubic meter. The fact that the conditions are not exactly the same means that an exact conversion is impossible unless the exact expansion coefcient of the crude is known, and this will vary from one crude oil to another.Thus, for a light oil with an API gravity of 35, warming the oil from 15°C to 60°F (which is 15.56 °C) might increase its volume by about 0.047 percent. Conversely, a heavy oil with an API gravity of 20 might only increase in volume by 0.039 percent. If physically measuring, the density at a new temperature is not possible, and then tables of empirical data can be used to accurately predict the change in density. In turn, this allows maximum accuracy when converting between standard bbl and standard m3.International commodity exchanges will often set an arbitrary conversion factor for benchmark crude oils for nancial accounting purposes. For instance, the conversion factor set by the NYMEX (New York Mercantile Exchange) for WCS (Western Canadian Select) crude oil traded at Hardisty, Alberta, Canada is 6.29287 U.S. barrels per cubic meter, despite the fact that crude oil cannot be measured to that degree of accuracy. Regulatory authorities in producing countries set standards for measurement accuracy of produced hydrocarbons, where such measurements affect taxes or royalties to the government. In the United Kingdom, for instance, the measurement accuracy required is ±0.25 percent.A barrel can technically be used to specify any volume. Since the actual nature of the uids being measured varies along the stream, sometimes qualiers are used to clarify what is being specied. In the oileld, it is often important to differentiate between rates of production of uids, which may be a mix of oil and water, and rates of production of the oil itself. If a well is producing 10 mbd of uids with a 20 percent water cut, then the well would also be said to be producing 8,000 barrels of oil a day (bod).In other circumstances, it can be important to include gas in production and consumption gures. Normally, gas amount is measured in standard cubic feet or cubic metres for volume (as well as in kg or Btu, which don’t depend on pressure or temperature). But when necessary, such volume is converted to a volume of oil of equivalent enthalpy of combustion. Production and consumption using this analogue is stated in boed (barrels of oil equivalent per day).In the case of water-injection wells, in the United States it is common to refer to the injectivity rate in bwd (barrels of water per day). In Canada, it is measured in cubic metres per day (m3/d). In general, water injection rates will be stated in the same units as oil production rates, since the usual objective is to replace the volume of oil produced with a similar volume of water to maintain reservoir pressure. Thus, a 42 gallon barrel, which accommodates 158.987294928 liters, became a standard unit for measuring oil in the States in 1866.A boe or BOE (barrel of oil equivalent) – is often used in the USA for energy comparisons and combinations. This is a unit of energy based on the approximate energy released by burning one barrel (42-U.S. gallons or 158.9873 litres) of crude oil. The BOE is used by oil and gas companies in their nancial statements as a way of combining oil and natural gas reserves and production into a single measure, although this energy equivalence does not take into account the lower nancial value of energy in the form of gas.The U.S. IRS denes higher heating value (HHV) of the boe as equal to 5.8 million BTU (5.8×106 BTU59°F equals 6.1178632×109 J, about 6.1 GJ or about 1.7 MWh.) The value is necessarily approximate as various grades of oil and gas have slightly different heating values. If one considers the lower heating value instead of the higher heating value, the value for one boe would be approximately 5.4 GJ. Typically, 5,800 cubic feet of natural gas or 58 CCF (100 cubic feet) are equivalent to one boe. The (1) Per m3 and bcm. (2) Kcal15/kg Table 2 – Gross Caloric Values of Various Fuels in Australia, in Kcal-IT per kg (or cm) and in petajoules per mln tonnes (or bcm)(1) Per dm3.Table 1 – Average Energy Contents of Various Russian Fuels (Incl. in Relation to the Reference Fuel)

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Oilman Magazine / November-December 2019 / OilmanMagazine.com43OILMAN COLUMNUSGS gives a gure of 6,000 cubic feet (170 cubic meters) of typical natural gas.Over the northern border, in Can-ada, Europe and Russia ofcially uses the IEA (International Energy Agency) as well as in the PRC a similar but larger energy unit is used for these purposes and energy balances – the toe or TOE (ton of oil equivalent). In particular, toe is used by the Canadian ministry of energy – NEB (National Energy Board) – and Canadian leading energy companies. NCV of this energy unit is dened as 41.868 gigajoules (GJ) or 10 gigacalories (Gcal). Net caloric value (NCV) is dened, by convention, as follows: • 1 toe = 11.63 megawatt-hours (MWh);• 1 toe = 41.868 gigajoules (GJ);• 1 toe = 10 gigacalories (Gcal) – using the international steam table calorie (calIT) and not the thermochemical calorie (calth); • 1 toe = 39,683,207.2 British thermal units (BTU);• 1 toe = 1.42857143 tonnes of coal equivalent (tce).At the same time, in Russia and the FSU other countries, the tce is widely used for energy comparisons. This energy unit is usually called tonne of standard reference fuel (trf), net caloric value of which is dened as 29.3 GJ or 7,000 kcal. In this case it equals 0.7 toe and is assumingly referred to energy contents of various fuels in the following way (Table 1):In its turn, in Australian energy industry PJ (petajoules) are very popular and 1 PJ equals 1015 joules. In detail:• 1 PJ = 947,817,077,749.15 BTU• 1 PJ = 2.3890295761862E+14 calories 15°C (cal15)• 1 PJ = 2.3900573613767E+14 calories [thermochemical] (calth)• 1 PJ = 947,816.08955725 dekatherms (dath)• 1 PJ ≈ 277.77777777778 gigawatt hours (GWh)• 1 PJ = 23,884.58966275 tonnes of oil equivalent (TOE)Here, in Australia, PJs are used even in the gas industry (Table 2).Also, in Australian energy industry, quite popular is coe (crude oil equivalent), which is sometimes understood as a synonym of oil equivalent. But in Australia this has a special meaning and its GCV is ofcially dened as 10,250 Kcal15/kg or 18,500 btu/ft3.As prices, production, consumption and trade of natural gas (including LNG) worldwide are often presented in MMBtu and dekatherms, 1 MMBtu = 1,055,055,852.62 Joules and 1 dth = 10 therms or 1,000,000 British thermal units (MMBtu) or ≈ 1.055 GJ ≈ 1,000 cubic feet (cf) or one Mcf (of natural gas measured at standard conditions, since one cubic foot of dry natural gas has a high heating value (HHV) of approximately 1,000 Btu).To measure and present large and very large amounts of energy Quads and Q units are used in the States. In particular, Quad is used by the U.S. Department of Energy in discussing world and national energy budgets and is equal to 1015 (quadrillion) BTU, or 1.055 × 1018 joules (1.055 exajoules or EJ) in SI units, which is an approximate equivalent of the following:• 8,007,000,000 gallons (US) of gasoline• 293,071,000,000 kilowatt-hours (kWh)• 293.07 terawatt-hours (TWh)• 33.434 gigawatt-years (GWy)• 36,000,000 tonnes of coal• 970,434,000,000 cubic feet of natural gas• 5,996,000,000 UK gallons of diesel oil• 25,200,000 tonnes of crude oil (the USA)• 252,000,000 tonnes of trinitrotoluene (TNT) or ve times the energy of the Tsar Bomba nuclear test• energy of 15,750 nuclear explosions, each of which was in theory produced by the A-bomb thrown on Hirosima on August 6, 1945• 13.3 tonnes of uranium-235In its turn, the Q energy unit is equal to 1018 (quintillion, trillion) BTU or 1.0E+18 BTU.Just to feel this better by putting the Quad and Q units into a frame of actual reference, we say that in 2019 inland consumption of petroleum and other HC liquids is projected in the U.S. Energy Information Administration of the Energy Department (EIA USDoE)’s Reference Scenario of its Annual Energy Outlook (January 2019) at over 38 Quads while global primary energy consumption is forecast by the EIA to grow by 2040 up to 0.82 Q from some 0.52 Q in 2010. It is noteworthy that each of the above energy units is used at certain national measurement conditions which are called Figure 1 – Oil and Gas Volumes under the U.S. and Russian Current STP, in %% Continued on next page...

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Oilman Magazine / November-December 2019 / OilmanMagazine.com44OILMAN COLUMNthe standard temperature and pressure (or, shortly, STP). This is very important to know since national STPs vary noticeably country-by-country. It is well known that, if all other things being equal (or in Latin “ceteris paribus”), the volume is directly proportional to temperature and inversely proportional to pressure, which are applied to it. Or, in other words, under constant temperature and pressure, the relationship between the volume of gas and the number of moles is direct. This law is known as Avogadro’s Principle or Avogadro’s hypothesis. This hypothesis was rst published by Amedeo Carlo Avogadro (1776–1856), an Italian scientist, in the year 1811. Just for those who prefer a mathematical language, we refer to Avogadro’s original and simple modied equations: V ÷ n = k, which means that the volume amount fraction will always be the same value if the pressure and temperature remain constant. Let V1 and n1 be a volume amount pair of data at the commencement of our research. If the amount is transformed to a different value called n2, then the volume will b altered to V2.As we are aware that V1 ÷ n1 = k and we are acquainted with: V2 ÷ n2 = kMeanwhile as k = k, we can determine that V1 ÷ n1 = V2 ÷ n2.This equation of V1 ÷ n1 = V2 ÷ n2 will be very useful in cracking Avogadro’s Law problems. Here is the Law articulated in fractional form: And if we emphasize that the temperature should be presented in kelvins (and Celsius degrees) and the pressure – in Pascals (how all the units are accepted in modern chemistry and physics, as well as in the SI, where 0 K = –273.15°C and 1 Pa = 1 Newton/m2 = 0.00014503773 Psi), then the needed equation looks as follows: Vx = Vo × (273.15 + Tn) ÷ Po x Pn, where Vx – a new, sought-for volume, Vo – an original volume in the same units, Tn – a new temperature in Celsius degrees, Po – an original pressure, Pn – a new pressure in the same units.Although the Avogadro’s Law relates to an ideal gas (an abstract, theoretical gas composed of many randomly moving point particles whose only interactions are perfectly elastic collision), the above equation is actually good (universal) for any gaseous or liquid hydrocarbons.The USA currently uses STP correspond to 60°F (288.706 K, 15.556°C) and 14.696 psia (1 atm, 1.01325 bar, also named “1 Standard Atmosphere”). At these conditions, the volume of 1 mole of a gas equals 23.6442 liters while 1 cubic foot of a gas does not equal 28.3168 liters (under any similar measurements) but 28.8719 liters (in line with the denition of the STP, used by the International Gas Union (IGU) (15°C and 760 mmHg). The above mentioned set of volume measurements, known as U.S. STP, is ofcially used by the national oil and gas and energy business (and, rst of all, by the API, DoE, PRMS, SPE and USGS).In Canada, Europe, Australia, and Latin America, for example, the STP conditions used by the ISO (International Organization for Standardization) (that are 15°C and 101.325 kPa) have been adopted, as a rule, and are used as the base values for dening the standard cubic meter.In its turn, in Russia, 20°C and 760 mmHg, corresponding, in particular, to the U.S. NIST’s NTP and EPA’s STP, are ofcially used for volume measurements. As the matter of fact, this is almost the biggest difference in temperatures used at present in the oil and gas industry worldwide (20°C and 60°F)2. At the Russian conditions, 1 U.S. cubic foot of a gas does not equal 28.3168 liters but nearly 28.7527 liters or contains almost 1.54 percent more gas, while U.S. oil 42 gallon barrel is not equal to 158.987295 liters but accommodates over 161.4345 liters of oil (again by nearly 1.54 percent more) (Figure 1).Surely, not a big deal, of course. But, if taken in absolute physical terms, with gas production standing now in Russia at some 730 bcm a year and that of crude oil and mixed/leased condensate at over 560 mta, this is more than what was actually produced last year in Vietnam (9.6 bcma or 0.93 bcfd) or Peru (6.4 mta or 154 kb/d) (Table 3).2 To be exact, an even larger difference should be attributed to volumes (of natural gas) exported by Russia to the EU (almost 1.74 percent).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. Khartukov has authored and co authored over 320 articles, brochures and books on petroleum and energy economics, politics, management, and oil and gas in the FSU, Russia’s Far East, the Caspians, Europe, the OPEC, ME and Africa. Participated as a speaker and/or a session chairman in more than 170 international energy, oil and gas and economic fora. Table 3 – Production of HCs in Russia: Effects of Different Oil & Gas Measurements

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Oilman Magazine / November-December 2019 / OilmanMagazine.com45OILMAN COLUMNMost Common Oil and GasCybersecurity Threats By Emmanuel SullivanWe are currently in the middle of a technological revolution, and the signs are all around us. Go ahead and name any tech buzz word such as the Internet of Things, Big Data, or Articial Intelligence, and it will denitely be related to so many industries out there. Here, however, we’re not going to talk about the new opportunities, but we’ll be warning you about emerging threats.Integration and automatization have exposed many industries to new threats and vulnerabilities, and the oil and gas industry is no exception. It has never been more important to protect critical infrastructures due to the increase in cybersecurity threats in the oil and gas industry.According to research conducted by ABI, the oil and gas industry has been gearing up against cyber threats by taking some preventative measures. The report illustrates how a cumulative $1.87 billion has been spent against cybersecurity threats in the oil and gas industry. Even though this is the case, most of the players in the industry still lack awareness and can easily fall victim to dangerous cyber-attacks.What Could Possibly Happen?The possible consequences of a cyber-attack highly depend on the cybercriminal’s aims. An example can be state-backed hackers or competitors that are interested in attaining or revealing important information held by the victim companies. Sabotage, on the other hand, is a whole new problem and is usually the aim of hacktivists – such as the case of #OpPetrol operation back in 2013.The Possible Risks of a Successful AttackSome of the risks that can be faced by victims of a successful cyber-attack can include the following:1. Plant shutdowns2. Equipment damages3. Interruption of utilities4. Shutdowns of production cycles5. Inappropriate or inconsistent product qualities6. Undetected spills7. Violations of safety measures which could result in injuries or even deathHackers Can Break Into Operational Technology (OT) NetworksA computer worm called Stuxnet has been known to target PLCs or the industry’s programmable logic controllers along with SCADA systems. This was a wake-up call for so many industries other than the oil and gas industry because the worm had been designed in this way.The general idea of cyber-attacks of this nature is quite simple. Applications in enterprises such as Enterprise Resource Planning systems or even Business Intelligence systems are usually connected with a large number of devices in plants. This is done with the help of some integration technologies that are used to transfer data across platforms such are smart devices. If these connections are not secured, such as the connections between OT and IT environments, then reneries are most denitely vulnerable to cyber-attacks.Oil Market FraudImagine if a cybercriminal uploaded malicious software into a system which has the ability to change stock information for oil and gas companies. An example can be the case where malware had the ability to fake certain types of data and make quantities appear much larger than they really are.Once this occurs, the victim company will easily run out of production resources and hence fail to satisfy its respective obligations. As a result, the malware would have wreaked havoc and caused the company to experience huge losses while driving the oil price much higher.Plant DestructionIn the production units of oil and gas companies, tank gauging systems and tank information management systems are connected. Some of these are equipped with functionalities that allow them to send individual commands to PLCs, which in turn are placed to control the lling of tanks.When cybercriminals make their way to this information, nothing can prevent them from changing its critical values. How is this dangerous? Well, a cybercriminal could easily engineer an oil explosion by simply increasing the maximum lling limits of individual oil tanks.In a similar manner, there are numerous processes in reneries and oil separation units that can be open to potential attacks via their burner management systems. These systems are not only meant to send information, but they are also designed in a manner to be managed remotely via special intermediate systems and business applications. Vulnerabilities in these remote operations can easily be compromised leading to the worst-case scenario of a plant explosion by simply turning off the purge functionalities.Equipment SabotageRemote plant equipment is usually at risk of data manipulations as well. This can be in terms of pressure or temperature measurements and hackers could easily implant false forms of data which show breakdowns have occurred in remote facilities. This would then lead the victim renery to waste their nancial resources and time in false investigations.The takeaway from all of the above may sound banal, but it is the ugly truth. The newest technological features and booming usage of the Internet of Things have simplied our lives quite a lot, but have also brought ahead some new risks. Now, it’s not only a question of the vulnerabilities of the people who use the Internet of Things or even electric skateboards. Every critical infrastructure that is connected to these technologies should take the threat seriously.It is now time for oil and gas companies to realize that there are no gaps between OT and IT systems and that there are certain business applications that exchange critical information with devices. Due to this, these companies should seriously consider cybersecurity and setting strong lines of defense against possible attacks.

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Oilman Magazine / November-December 2019 / OilmanMagazine.com46OILMAN COLUMNPipelines as Critical Infrastructure By Jason SpiessThe state of California currently experienced a reality check in energy accountability and aging infrastructure. While the majority of the attention is on the spike in gas prices, black outs and stress on the grid in California, Wesley Cate of Eco-Energy believes the national conversation should shift to the issue of aging pipelines. The most recent “Infrastructure Report Card” published by The ASCE (American Society of Civil Engineers) gave the United States an overall grade of D+. According to Cate, most of the natural gas pipelines are over 40 years old and are in need of updates sooner rather than later, especially since natural gas plays a large role in energy, manufacturing and providing an overall quality of life. “Natural gas in 2018 we were at 35 percent of your overall power demand. That’s massive. Coal was at 27 percent and nuclear was at 19 percent,” Cate said. “When we look at critical infrastructure and electricity, so if our natural gas pipelines are 35 percent of our overall power portfolio, I think that is critical.”Cate recently spoke to the members of the Southern States Energy Board about natural gas supply, infrastructure and demand. A key point of the discussion was if SSEB members want industrials like Pzer, P&G, Toyota, GM and many others in their states, then states should be encouraging and not opposing natural gas infrastructure.“Pipelines create lasting jobs, which creates lasting tax revenue,” Cate said. “There are over 8,000 miles of proposed projects in these members states, imagine the amount of jobs and economic stimulus this would create. Economic prosperity follows pipelines.”Cate is quick to point out that economics and the opportunity demand natural gas gets all the attention, but there are other factors as important. “Natural supply has always been the focus from a conversational standpoint. Everyone wants to talk about the growth and that is great, and I don’t want to shift away from that, however, there are other elements to consider,” Cate said. “When we look at critical infrastructure there are three components to that discussion - supply, infrastructure and demand.”According to WhatIs.com, “critical infrastruc-ture” is the body of systems, networks and assets that are so essential that their continued operation is required to ensure the security of a given nation, its economy, and the public’s health and/or safety.While there are many interpretations and special interests usurping this law, Cate believes the conversation shifted to include multiple layers, creating a complex critical need to understand.“I think it is important to shift that narrative over to the demand side because that is where I believe we can start to label this as a critical infrastructure component,” Cate said. “When we look at where pipelines are going and what they are providing for us as a society, really the societal shift has already happened.”Cate added this shift needs to be understood and acted upon before more issues like what happened to California’s grid. Blackouts and power rationing is only part of the story, protes-tors and policy are inuencing when and how the nation’s critical infrastructure is updated. Protests of critical infrastructure projects – even those actions that are deemed peaceful and nonviolent – involve not only trespassing on private property, but often can put the trespassers, workers, and environment at risk. Each arrest and incident are another play in the protestors play book, which was put into collective play at Standing Rock in North Dakota. The Standing Rock protest in the Bakken oil elds garnered national attention due to the narrative of the protest. Many argue that the state ushered industry right into the protestor’s true agenda of capturing the narrative of energy and the environment. Consider this. Wounded veterans and Hollywood stood with Standing Rock protestors. They brought in the bright lights and big city sex appeal while pulling on the heart strings of virtually everyone with those who were injured while ghting for our freedoms. The state responded by ring rubber bullets at them and dousing them with a re hose in sub-zero temperatures.That’s cold. And the pipeline protestors warmed up to the attention and shift in national narrative. Standing Rock is ranked number two on the FBI’s hate crimes. Now pretty much every protest is using the Standing Rock model. That’s an incredible shift and reality. However, the Standing Rock protest is a prime example of the damage that can be caused during these “peaceful” actions. The protest lasted from August 2016 until February 2017 and resulted in a $33 million cost to taxpayers, more than 700 arrests, 1,400 charges and over 1,000s of tons of waste and several hundred abandoned vehicles that created an environmental issue for their water supplies. The protestors actually created a reality of an environmental threat in the exact specic area they were trying to protect - the water supply. Furthermore, the glorication of martyrism and Instagram moments fan the ames of cash supporting the protestors as a career more than a cause. Roughly 92 percent of the arrests at Standing Rock involved people from out of state.Pipelines are obviously of national interest. The nation’s natural gas and oil industry plays a critical role in fueling America with reliable and affordable energy. In fact some counties are testing the “eminent domain” argument to update their pipelines or nish projects. “Our industry needs to shift from the supply side as the focal point and shift towards the demand based narrative. This shift will naturally spotlight the needs in critical infrastructure,” Cate said. From a tax standpoint, to a manufacturing standpoint. Without pipeline infrastructure we don’t have a stock market.” The bottom line is that damage to our aging critical infrastructure risks interrupting necessary services across the United States. Pipelines are critical. According to Cate, most of the natural gas pipelines are over 40 years old and are in need of updates sooner rather than later.Some counties are testing the eminent domain argument to update their pipelines or finish projects.

Oilman Magazine Nov/Dec 2019

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