ADVANCING DRILL BIT FORENSICS Intelligent technologies are poised to help the industry get to root causes of bit failures – p14 MAR/APR 2022 Volume 78 • Number 2 Official magazine of the International Association of Drilling Contractors www.drillingcontractor.org www.iadc.org How can the industry understand and fight elusive downhole enemies? Companies are seeking new ways to mitigate hard-to-detect dysfunctions like HFTO – p22 A quest for power in frac operations Manufacturers push horsepower boundaries while focusing on higher power density, equipment durability – p30 Let us clear the air. Minimize your drilling CO2 footprint Intelligent Power Management can lower rig emissions by 30% while at the same time, reducing fuel consumption by 20%. Learn how this solution can be tailored to your needs based not just on equipment types, but also your goals for fuel efficiency, emissions, and engine life optimization. It’s about doing better for the environment by understanding what we can do better. slb.com/IntelligentPower 30% LOWER EMISSIONS 20% LESS FUEL CONSUMPTION Aligned with United Nations Sustainable Development Goals: 13—Climate action, 17—Partnerships for the Goals. Transition Technolgies is a mark of Schlumberger. Copyright © 2021 Schlumberger. All rights reserved. 21-WCEQ-1057093 TAB LE OF CONTE NTS Official magazine of the International Association of Drilling Contractors MAR/APR 2022 drillingcontractor.org iadc.org Volume 78 • Number 2 As drilling operations are automated and digitalized, workflows around the post-run evaluation of drill bits are changing, too, as AI- and machine learning-based tools are developed. Cover image courtesy of Hallburton. I N N OVATI N G WH I LE D R I LLI N G 14 Digital technologies support new workflows in drill bit forensics AI and machine learning allow for dull wear data to be easily collected, digitized and analyzed, leading to better bit designs, optimized drilling BY STEPHEN FORRESTER, CONTRIBUTOR 20 IADC ART Committee moves closer to launching updated drill bit dull grading system BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 22 Industry seeks ways to understand and fight elusive downhole enemies Dysfunctions like HFTO can be hard to detect, but companies are identifying mitigation solutions through sensors, bit studies, predictive software BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 27 Multilayer mapping-while-drilling service delivers real-time insights to optimize reservoir exposure BY VERA KRISSETIAWATI WIBOWO AND HAIFENG WANG, SCHLUMBERGER 27 IMPROVING FRACKING POWER & EFFICIENCY 30 Power quest: Innovations in frac equipment push horsepower boundaries As 5,000-hp becomes the norm, manufacturers focus on delivering pumps and engines with higher power density, durability BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 36 Automated predictive frac control system taps operator’s machine-learning model to improve completion execution 38 BY JESSICA WHITESIDE, CONTRIBUTOR 38 Integrated platform aims to improve real-time decision making in frac operations BY STEPHEN WHITFIELD, ASSOCIATE EDITOR D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 3 TAB LE OF CONTE NTS IADC CONNECTION 42 From the President: IADC, members keep focus on people, collaboration, industry value BY JASON MCFARLAND, IADC PRESIDENT 43 News Cuttings 44 Wirelines 45 Conference Calendar 46 Editorial Preview DEPARTMENTS 6 Drilling Ahead: Volatility besets global economy, oil and gas markets amid Russia’s war BY LINDA HSIEH, EDITOR & PUBLISHER 7 7 D&C News 47 People, Companies & Products 49 Advertisers Index 50 Perspectives: Matt Isbell, Hess – Integration, standardization will help propel well construction performance to the next level 9 D&C Tech Digest 10 News Briefs: Environmental, BY LINDA HSIEH, EDITOR & PUBLISHER Social and Governance 12 Oil & Gas Markets 40 HSE&T Corner: New study highlights impact of COVID-19 on mental health of offshore workers in Australia BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 50 NOTE: Some articles feature QR Codes which can be scanned using your smartphone to access web-exclusive, enhanced editorial on DrillingContractor.org or in our Digital Reader. MARCH/APRIL 2022 Volume 78 • Number 2 Drilling Contractor (ISSN 0046-0702), the official magazine of the International Association of Drilling Contractors (IADC), is issued six times per year. DC is a wholly owned publication of IADC, which is also the publisher of the annual IADC Membership Directory. Drilling Contractor strives to ensure that the articles and information it publishes are accurate and reliable. However, DC cannot warranty the information provided in its editorial content, and publication in DC is not a guarantee that the material presented is accurate. DC wants to hear from its readers. Send your comments or inquiries to editor@iadc.org or Attn: Editor, Drilling Contractor Magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042 (please include your name, plus an email or phone number). We hope you will enjoy and benefit from DC’s editorial. However, should you wish to 4 complain, please contact the publisher. 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PUBLISHED BY IADC OFFICERS IADC 3657 Briarpark Drive Suite 200 Houston, Texas 77042 USA Chairman Jeremy Thigpen Phone: +1 713 292 1945 drilling.contractor@iadc.org www.drillingcontractor.org EDITORIAL STAFF Vice President, Editor & Publisher Linda Hsieh Vice Chairman William Andrew “Andy” Hendricks Secretary-Treasurer Scott McReaken Division VP North America Onshore Mike Garvin Creative Director Brian C. Parks Division VP International Onshore Miguel Sanchez Associate Editor Stephen Whitfield Division VP Offshore Brian Woodward Contributors Stephen Forrester Jessica Whiteside Division VP Drilling Services Robin Macmillan President Jason McFarland A full list of IADC staff is available here: www.iadc.org/about/staff M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R YOUR WELL YOUR OPERATION YOUR ENVIRONMENT BETTER MANAGED NOT JUST FOR DRILLING MANAGED PRESSURE WELLS With the knowledge earned from more than 50 years of experience, thousands of jobs, and millions of operating hours, we are the pressure professionals. Our Managed Pressure Wells solutions enable you to combine your knowledge of your wells with our industry leading portfolio of products and services to manage pressure. Scan to learn more. © 2022 Weatherford. All rights reserved. DEPARTMENTS • DRILLING AHEAD Volatility besets global economy, oil and gas markets amid Russia’s war IADC Advanced Rig Technology CONFERENCE & EXHIBITION 30-31 AUGUST 2022 HYATT REGENCY AUSTIN HOTEL AUSTIN, TEXAS SILVER SPONSOR EVENT SPONSOR www.iadc.org/event/ iadc-art-2022 For more information, contact IADC by phone at +1.713.292.1945 or via email at iadcconferences@iadc.org 6 BY LINDA HSIEH, EDITOR & PUBLISHER If we were hoping that 2022 was going to lead to more “normalcy” in the world and more stability in the oil and gas markets, well... it looks like that’s not going to hap- pen. In the wake of Russia’s invasion of Ukraine in late February, volatility reigns again. As this issue of the magazine was going to press in early March, many countries had already announced multiple sanctions against Russia. This included freezing Russian assets and limiting the ability of some Russian banks to operate as part of the international financial system. Canada has also banned the import of Russian oil. Within the oil and gas industry, we saw BP announcing on 27 February that it would cut its ties with Rosneft, exiting its 19.75% shareholding in the state oil com- pany. Equinor, Shell and ExxonMobil all followed suit, announcing their intentions to exit their own joint ventures in Russia. “There will be lasting implications for commodities, energy policy and the ener- gy transition,” Wood Mackenzie said in an analysis released on 25 February. It noted that “the world’s dependence on Russia for certain commodities cannot be overstated – from gas, oil, iron, ore, aluminum, plati- num group metals and zinc to copper, lead, petrochemicals and fertilizers.” On the other hand, Russia is also a large consumer of oilfield services. Rystad Energy estimates Russia was responsible for approximately 9% of global service pur- chases between 2015 to 2021. In the same period, the country also accounted for $175 billion in wells, drilling and seismic activi- ties, along with $88 billion in both subsea and engineering, procurement, construc- tion and installation (EPCI) purchases. Further, delays and additional costs in the travel of essential oil and gas work- ers are likely unavoidable. Ukraine’s air space is already closed, impacting all flight routes that cross this space. Many countries – including the entire European Union (EU) – have also banned Russian flights from their airspace. “Hour by hour, further airlines are pull- ing their flights from Russian territory,” said Murray Burnett of Munro’s Travel, a company that manages the movement of oil and gas and marine workers. “The logistics of arranging for a crew – which can comprise dozens of workers all based in different countries – to arrive for a crew change at the same time is challenging at the best of time.” Now, adding war on top of existing COVID-19 restrictions will only lead to additional risks and complications. Impact on natural gas and oil markets Russia’s invasion is doubtlessly adding pressure to Europe’s gas market, which was already going through its worst crisis on record, according to WoodMac. The firm’s analysis shows that Russian pipe- line imports of natural gas account for a very considerable 38% of EU demand. Therefore, sanctions on that flow would not be pragmatic, and “business as usual” is still the most likely outcome. However, even if the flow of Russian gas is not halted, WoodMac believes this conflict will push the EU to rethink the role of natural gas in its decarbonization strategy. “Higher gas prices make a stron- ger case for renewables, as well as alterna- tive gases such as bio-methane and green hydrogen,” its analysis stated. When it comes to oil, there have already been slowdowns in Russian crude pur- chases. WoodMac says it expects further tightening in the supply and demand bal- ance “until payment terms are clarified.” However, they believe the recent upward trend in oil prices (WTI had hit a high of $112 at press time) is likely to ease up soon, unless the world sees a real sustained slowdown in Russia’s crude exports. Volatility is no good for business, and war is no good for the world. Here’s to hop- ing for a more peaceful 2022. DC Linda Hsieh can be reached at linda.hsieh @iadc.org. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R DRILLING & COMPLETION NEWS • DEPARTMENTS Contract wins for Valaris semi in US GOM, Mexico Valaris has been awarded two one-well contracts with subsidiaries of Murphy Oil for the VALARIS DPS-5 semisubmersible. The first contract is in the US Gulf of Mexico and is expected to commence in Q3 2022 with a minimum duration of 30 days. This contract has a one-well option with an estimated duration of 90 days. The second contract, offshore Mexico, will commence in direct continuation of the first contract and has an estimated dura- tion of 60 days. Graff-1 well finds oil in deepwater Namibia The National Petroleum Corp of Namibia (NAMCOR), the Namibian state- owned oil company, and its partners – Shell Namibia Upstream and Qatar Energy – have announced that the Graff-1 deepwater exploration well made a dis- covery of light oil in both primary and secondary targets. The well was drilled in the Orange Basin , 270 km from the town of Oranjemund. Drilling operations commenced in early December 2021 and were safely com- pleted in early February 2022. In the coming months, extensive labo- ratory analyses will be performed to gain a better understanding of the reservoir quality and potential flow rates achiev- able. NAMCOR said it anticipates further exploration activity, including a second exploration well, will be required to deter- mine the size and recoverable potential of the identified hydrocarbons. Appraisal well delineates Winterfell potential in GOM Kosmos Energy announced it has fin- ished drilling the Winterfell-2 appraisal well on Block 943 in the Green Canyon area of the US Gulf of Mexico (GOM). The well was drilled to evaluate the adjacent fault block to the northwest of the original Winterfell discovery and was designed to test two horizons that were oil bearing in the Winterfell-1 well, with an exploration tail into a deeper horizon. The well dis- covered approximately 40 m of net oil pay in the first and second horizons . Equinor’s Kvitebjørn is among fi ve platforms for which KCA Deutag received contract extensions to provide drilling operations, maintenance services and engineering support. Photo courtesy of Equinor/Harald Pettersen. KCA Deutag wins contract extensions in Europe, 10-year contract to provide 4 new rigs in Oman KCA Deutag has been awarded a two- year drilling contract extension on five of Equinor’s fixed platforms operating in the Norwegian North Sea: Osberg B, Osberg South, Osberg East, Osberg C and Kvitebjørn. The contract – worth $140 million – is for the provision of drilling operations, maintenance services and engineering support and will now run to September 2024 . KCA Deutag was originally awarded the contract in October 2018 for a period of four years, with an option to extend by three further periods of two years each . In separate news, KCA Deutag announced it was receiving a 10-year contract from Petroleum Development Oman for the provision of drilling ser- vices with four new highly automated rigs that will be built in Oman . The contract comes with options to extend for a further two years and, with those options included, has a total value of around $550 million. The rigs will be constructed by International Drilling Technology Co (IDTEC) in Oman. IDTEC, majority-owned by the KCA Deutag Group, is the group’s local rig manufacturing and servicing company . The rigs will be the first of their kind to be constructed in Oman, marking a step change in the rig-build- ing capabilities in the country. KCA Deutag will invest approximately $100 million to build the new rigs and expects to commence operations in the second half of 2023. Around 40% of this value will be spent with Omani suppli- ers, including local small and medium enterprise companies. The project has high in-country value , including the establishment of IDTEC as an API-licensed manufacturer for rig structures in Oman , and the training and upskilling of Omani personnel during the construction phase . In addition to training its own employ- ees in operating the rigs, KCA Deutag will extend the opportunity to partake in the training, knowledge transfer and rig con- struction to personnel from other drilling companies . Further, it will offer summer internships to 16 undergraduates from Omani universities to be involved in the design, construction and commissioning of the rigs. KCA Deutag will then offer employment to at least four of these undergraduates upon course completion. The rig design and all key components will be provided by KCA Deutag’s new business unit, Kenera, through its Bentec engineering and manufacturing center. The rigs will be highly automated, fast- moving units and will benefit from the latest technologies from KCA Deutag’s Well of Innovation. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 7 DEPARTMENTS • DRILLING & COMPLETION NEWS Maersk secures contract extensions in Malaysia, new contract in Denmark Deepsea Nordkapp confirmed to drill Kobra East Gekko development wells for Aker BP Sarawak Shell Berhad/Sabah Shell Petroleum Corp (SSB/ SSPC) has executed two options on the previously announced contract that will employ the seventh-generation drillship Maersk Viking offshore Malaysia. The first option will be novated to TotalEnergies EP Malaysia for the drilling of one deepwater well for the Tepat project, while the second option will be novated to PETRONAS for the drilling of one deepwater well for the Layang-Layang project. Both projects are located off the coast of Sabah. The extensions have a total estimated duration of 120 days and are expected to commence in July 2022 in direct continu- ation of the rig’s prior work scope with SSB/SSPC. The total contract value of the extensions is approximately $32 million, including fees for the use of managed pressure drilling. Three one-well options remain on the contract with Shell Malaysia. In separate news, Maersk Drilling has been awarded a con- tract with TotalEnergies E&P Danmark to employ the Maersk Reacher jackup for well intervention services in the Danish North Sea. The contract is expected to commence in July 2022, with a duration of 21 months. The contract includes options to extend the duration by up to 27 additional months. Aker BP has exercised a scope-based option for Odfjell Drilling’s Deepsea Nordkapp semisubmersible under a contract originally signed in April 2018. The option covers the time nec- essary to complete four Kobra East Gekko (KEG) development wells. Operations on the KEG development wells are expected to commence in January 2023, with a combined duration of approximately 430 days. With the current term-based contract ending in June 2023, the newly exercised KEG development scope represents approximately 8.5 months of additional back- log for the Deepsea Nordkapp, occupying the unit into Q1 2024. The approximate contract value for the exercised optional scope is $80 million, excluding any integrated services . Further, an additional option period has now been agreed upon. If exercised, it will follow completion of the KEG develop- ment wells. APA Corp sees exploration success with KBD-1 well in Block 58 offshore Suriname APA Corp has announced an oil discovery at the Krabdagu-1 (KBD-1) exploration well. KBD-1 is located on Block 58 offshore Suriname, approximately 18 km southeast of the Sapakara South-1 appraisal well. APA Suriname holds a 50% working interest in the block, and operator TotalEnergies holds the remaining 50% . KBD-1 was drilled with the Maersk Valiant to an approxi- mate depth of 17,300 ft (5,273 m ). The well was designed to test multiple stacked targets in Maastrichtian and Campanian intervals and encountered approximately 295 ft (90 m) of net oil pay in good-quality reservoirs. While the rig is on location, TotalEnergies will progress with drill stem and other wellbore testing to assess the resource potential and productivity of two primary reservoirs. Liza Phase 2 starts production in Guyana, set to reach capacity later this year Hess has announced startup of production from the Liza Phase 2 development on the Stabroek Block offshore Guyana, utilizing the Liza Unity FPSO . The oil production capacity of 220,000 gross bbl/day is expected to be reached later this year . The Liza Unity arrived in Guyana in October 2021, fol- lowing construction in shipyards in China and Singapore. It is moored in water depth of about 1,650 m and will be able to store approximately 2 million barrels of crude oil. The Liza Unity is the world’s first FPSO to be awarded the SUSTAIN-1 notation by ABS in recognition of the sustainability of its design, documentation and operational procedures. 8 The Stena Spey will soon begin drilling for TotalEnergies on the UKCS, with an estimated duration of 120 days. TotalEnergies, Petrofac hire Stena Drilling semisubmersibles to work on UKCS Stena Drilling recently won new contracts for two of its semi- submersibles. The first contract is with TotalEnergies for the Stena Spey. Operations on the UK Continental Shelf are due to commence in March or April 2022, with an estimated duration of 120 days. The second contract is with Petrofac for the Stena Don, set to commence in Q4 2022 and lasting an estimated 80 days. The contract was awarded in support of a campaign with one firm well on Tailwind Energy’s Gannet E field in the UK Continental Shelf. The contract includes an option to extend for up to three optional wells on behalf of other clients, with an estimated dura- tion of 55 days. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R DRILLING & COMPLETION TECH DIGEST • DEPARTMENTS Added capacity at Port Esbjerg allows Maersk Drilling jackup to use shore-to-ship power Maersk Drilling has connected its first rig to the green shore-to-ship power unit at Port Esbjerg in Denmark . The shore power unit, the first of its kind in Denmark, reduces carbon emissions substantially and is in line with both Port Esbjerg’s and Maersk Drilling’s focus on sustainability and the green transition. The Maersk Highlander jackup is cur- rently connected to shore-to-ship power at Doggerkaj. The power plant has a capac- ity of 1,300 Amp/1.5 MW and can supply power to up to three rigs, which requires up to 10,000 kWh every 24 hours. The potential reduction in carbon emissions is substantial, but the actual figures will depend on how long the rigs are docked. Many of the other ships at the Esbjerg port have had the option to connect to shore-to-ship power for several years. The news is that Port Esbjerg now has the capacity to supply shore-to-ship power to drilling rigs, which require huge quantities of power. “More and more customers ask for shore-to-ship power, so for us, it’s not just a matter of participating actively in the green transition, on which we’re already heavily focused. It’s also a commercial necessity, which is why we’re in the process of installing more shore-to-ship power plants at the port, so even more of our customers have the opportunity to use green power,” said Port Esbjerg CEO Dennis Jul Pedersen. The potential reduction of carbon emis- sions from using shore-to-ship power rather than diesel generators is up to 500 tonnes of CO 2 per month per rig . Replacing large-diameter seals in-situ can help to reduce FPSO downtime The GeoVolve HAMMER uses a percussive drilling technique that can help to speed up the rate of penetration in geothermal drilling, minimizing damage to the drill bit so it can drill deeper and longer. New system aims to halve geothermal well costs A new percussive drilling system could potentially cut capital expenditure of geothermal wells by 50%. HydroVolve’s GeoVolve HAMMER uses percussive impulse energy to fracture the rock ahead of the drill bit, enabling deep drilling into hot, hard rock easier and faster. Operated by the flow of pres- surized drilling fluid, the technology is an all-metal construction, allowing it to operate in hazardous environments at extreme temperatures for extended periods. Currently, the cost of geothermal drill- ing can account for up to 50% of total well project costs, with the majority of spend due to time spent drilling through dif- ficult rock formations. Drilling through hard rock using conventional rotary methods causes drill bits to wear, dull or break down rapidly after short drilled depths. This results in the need to regu- larly recover the failed drill bit to surface for replacement, adding significant proj- ect time and costs. GeoVolve HAMMER uses a percussive drilling technique proven to speed up the drilling rate of penetration in hard rock by up to 10 times . The percussive drilling method is less damaging to the drill bit, meaning the bit can drill deeper for longer . The system is plug-and-play so it is compatible with any bottomhole assem- bly , and it does not interfere with mea- surement while drilling or steerable sys- tems . Its engine, HydroVolve INFINITY, is already a proven technology in the field. Trelleborg Sealing Solutions is provid- ing the oil and gas industry with a way to make in-situ repairs to large-diame- ter seals, minimizing equipment down- time and associated costs that come from maintaining an FPSO swivel stack. Replacement of large-diameter seals usu- ally requires the equipment to be returned to dock. The company’s SealWelding process begins with production of a seal in a con- trolled manufacturing area . Manufacture of the seal is to the original specifica- tion, in its original material; a special- ly designed tool precisely cuts the seal. Offshore, onboard the FPSO, highly trained personnel from Trelleborg’s service team place the new seal, which has been cut in one place, into position. Using a specialized ATEX zone 1 certi- fied fully enclosed welding machine, the two ends of the seal are joined together seamlessly. This enables other swivel stacks to continue production on the FPSO without risk. After completing the welding process, the seal is polished and check ed. A control cabinet ensures the smooth running of the process, as well as monitor- ing and logging of all data. If the values from the recorded data are within set parameters, the seal receives a release cer- tificate showing it is ready for operation. Besides saving time and costs, SealWelding also reduces CO 2 emissions that would otherwise be generated by the FPSO needing to sail back to port for repairs. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 9 DEPARTMENTS • ENVIRONMENT, SOCIAL AND GOVERNANCE Hess earns 100% score on Corporate Equality Index Hess announced it has achieved a score of 100% on the Human Rights Campaign’s Corporate Equality Index for 2022 and earned the designation as one of the Best Places to Work for LGBTQ+ Equality. For the third consecutive year, Hess also has earned a place on the Bloomberg Gender- Equality Index , which tracks the perfor- mance of public companies committed to achieve or adopt best-in-class statistics or policies and to transparency in gender- data reporting. Chevron seeks to certify environmental performance of select US land assets The Transocean Enabler, contracted to Equinor, will drill a carbon injection well and sidetrack for the Northern Lights Carbon Capture Storage Project this year. Transocean to drill wells for Northern Lights project Later this year, the Transocean Enabler semisubmersible will drill one carbon injection well and a sidetrack for another carbon injection well that had been drilled in early 2020. The wells will be drilled as part of Transocean’s current drilling contract with Equinor and in support of the Northern Lights Carbon Capture Storage Project , a joint venture by Equinor, Shell and TotalEnergies. The project aims to mitigate emissions and remove CO 2 from the atmosphere by cre- ating the first cross-border, open-source CO 2 transport and storage infrastructure network in the European Union. “Beyond our core business of drilling ultra-deepwater and harsh-environment wells, this is an excellent example of how we can further leverage our rigs and core competencies in support of renewable and alternative energy proj- ects in offshore markets across the globe,” said Janelle Daniel, Transocean’s Vice President of Human Resources, Sustainability and Communications. Upon completion, the Northern Lights project will offer companies across Europe the opportunity to store carbon dioxide safely and permanently under- ground. Parker outlines plan to achieve new goals in ESG report Parker Wellbore recently launched a plan to ensure the organization plays a leading role in tackling climate change challenges for its customers. The pro- gram is outlined in the company’s inau- gural ESG report . “This report represents a new forum for sharing our ESG trajectory, includ- ing environmental stewardship, social awareness, and strong corporate gov- ernance, which are ingrained in our mission, vision, values and company strategy,” said Sandy Esslemont, Parker 10 Wellbore President and C EO. “Our lead- ership team and stakeholders – includ- ing customers, investors, employees and the communities where we work – appreciate that companies which excel in ESG performance also achieve safe, responsible and profitable operations.” The company has conducted a green- house gas (GHG) emissions study to establish a baseline to help understand historical and future GHG emissions trends . This baseline provides a founda- tion to set emissions goals in the future. Chevron has announced a pilot project with Project Canary to independently cer- tify operational and environmental perfor- mance in the company’s North American upstream region. Project Canary will use its TrustWell Certification program to review and ana- lyze aspects of the environmental and social performance of individual wells and facilities in the Permian Basin of Texas and the DJ Basin of Colorado. Chevron will also deploy the Canary X pad-level meth- ane emissions monitoring units at select locations. More than 600 data points within 24 operational categories are included in a TrustWell analysis. Operators who earn top rankings are determined by Project Canary to utilize the highest standards and practices across their operations. The certification process is expected to begin in the first half of 2022. Based on ratings earned during the review process, Chevron anticipates being ready to deliver certified Responsibly Sourced Gas to mar- ket by mid-2022. Chevron says its 2020 US onshore pro- duction methane intensity was already 85% lower than the US industry average . The company has reduced fugitive meth- ane and volatile organic compound emis- sions through leak detection and repair, low-/no-emissions pneumatic devices, and centralized production facilities. The company is also expanding its methane detection capabilities to identify the best opportunities to further lower emissions. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R ENVIRONMENT, SOCIAL AND GOVERNANCE • DEPARTMENTS DNV report: Energy transition is accelerating, but skills shortage is critical challenge Energy industry leaders say the energy transition is accelerating faster than ever and 2022 is set to be a strong year for industry growth, according to a new report from DNV analyzing the views of more than 1,000 senior energy professionals. Findings show that industry players from across power, renewables and oil and gas believe the commercial opportunities presented by the transition outweigh the risks to their businesses . Skills shortages are the greatest barrier to growth , followed by a lack of policy support . Maintaining reliable energy sup- ply is also a concern, with many in the oil and gas industry convinced that not enough is being invested in exploration and upstream expansion to meet future demand. Some 38% of oil and gas respon- dents say that their organization is finding it increasingly difficult to secure reason- ably priced finance for projects. Across the energy industry , expecta- tions are increasing for large, capital- intensive projects to be approved in the year ahead, while almost half of the indus- try expects their organization to increase capital expenditure. Green hydrogen is the technology that the greatest num- ber of energy companies are targeting for increased investment in 2022, followed by solar PV, floating offshore wind, and car- bon capture and storage . Much of the industry is increasing investment in decarbonization, but it is telling that only 42% are optimistic about their company reaching its decarboniza- tion targets and 28% are outright pessi- mistic. Survey confirms COVID-19 advanced actions on ESG The H2opZee project to produce green hydrogen offshore the Netherlands could help to decarbonize energy-intensive sectors. New offshore green hydrogen project to begin this year Neptune Energy and RWE have signed a n agreement to develop an offshore green hydrogen project called H2opZee. The demonstration project will aim to build 300-500 megawatts electrolyzer capacity in the North Sea to produce green hydrogen using offshore wind. The hydrogen will then be transported to land through an existing pipeline. The project is an initiative of TKI Wind op Zee, supported by the Dutch govern- ment . In the first phase of H2opZee , a fea- sibility study will be carried out, likely starting in Q2 2022, and an accessi- ble knowledge platform will be set up. The objective is to start the roll-out of hydrogen at sea in the Netherlands. Implementation will then be carried out in the second phase of the project. For this phase, a tender methodology has yet to be defined. “We see an important role for green hydrogen in future energy supply, and it can be produced here in the North Sea,” said Lex de Groot, Neptune’s Managing Director in the Netherlands. “The energy transition can be faster, cheaper and cleaner if we integrate existing gas infra- structure into new systems.” Sven Utermöhlen, CEO Offshore Wind at RWE Renewables, said: “Hydrogen is a game changer in the decarbonization of energy-intensive sectors.” A new survey by GlobalData has revealed that 67% of 1,500 ESG and corporate social responsibility executives across indus- tries believe the COVID-19 pandemic has increased focus and action on ESG issues . “The sudden disruption of numerous business activities due to COVID-19 led many to realize that environmental action was much more feasible than previously thought,” Filipe Oliveira, Thematic Analyst at GlobalData, said. “Most of the focus and investment within ESG is going towards environmental issues — 69% prioritized environment issues, while 16% prioritized social and 15% governance. ” Further, 65% of respondents said ESG in decision making is “very important” while an additional 32% said it is “important.” “Since the COVID-19 outbreak, leading oil and gas companies have been reevalu- ating their operations, with emphasis on clean energy ,” said Bargavi Gandham, Oil & Gas Analyst at GlobalData. “This has brought about a change in their approach towards ESG, especially on the environ- mental aspect. Activities from leaders such as Shell, BP and Equinor has also trickled down to smaller players, national oil com- panies and service companies. Around 1,800 industry players have pledged to achieve net-zero in carbon emissions by 2050. Companies are also publishing sus- tainability reports annually to improve the transparency of their operations ” GlobalData’s annual ESG Strategy Survey report is based on a survey of 1,500 ESG leaders and executives worldwide and was conducted in October 2021. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 11 DEPARTMENTS • OIL & GAS MARKETS Oil and gas M&A’s increased by 16% in 2021, with highest values in upstream sector A total of 74 billion-dollar deals were undertaken in the oil and gas industry last year, compared with only 40 in 2020, according to GlobalData. The recovery in oil price likely encouraged companies to undertake more high-value deals to push forward their growth plans. In fact, the largest deal in terms of value for 2021 was announced toward the end of the year, when prices were at multi-year highs . Global mergers and acquisitions (M&A) activity in the oil and gas industry grew annually by 16% to reach $335 billion in 2021, considering M&As with known deal Permian basin new well productivity and lateral lengths BOED 11,000 1,100 1,000 900 Average new well productivity 10,000 Average perforated lateral length (RHS) 9,000 800 8,000 700 7,000 600 6,000 500 5,000 400 4,000 300 3,000 200 2,000 100 1,000 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 E 0 Source: Rystad Energy ShaleWellCube, Rystad Energy research and analysis Average productivity of new wells in the Permian has climbed steadily since 2010 and is closely aligned with the rise in average perforated lateral length. Rystad Energy: Permian is ‘entering a 3-mile lateral era’ The average productivity of new wells in the Permian Basin is set to hit a record high in 2022, exceeding 1,000 bbl/day of oil equivalent (BOED) due to a surge in lateral well length, Rystad Energy research indi- cates. New wells are expected to break the 1,000 BOED threshold in 2022 for the first time on record, rising from the 974 BOED achieved in 2021. Average daily production levels have steadily climbed since 2010, aligned with the horizontal well length, which is expected to reach 9,500 ft in 2022. The total completed lateral footage of wells in the Permian is expected to reach a record high of 50 million ft in 2022, beating 2021’s total of 45.8 million ft and pre-COVID-19 levels of 47.5 million ft seen in 2019. In 2020, total lateral footage in the basin dropped due to the pandemic , clock- ing in at only 32.5 million ft . Operators only started using ultra-long wells, of up to 3 miles in length, in the Permian in 2014, but their popularity has quickly grown. Their market share has rocketed from 4% of completions in 2017 12 to 18% in 2021. However, considering total completed lateral footage in 2021, these wells accounted for as much as 23% of completions. The average horizontal well length in the Permian increased to 9,300 ft in 2021, up from 9,000 in 2020 . This increase sig- nals a growing trend among operators to favor longer wells as they seek to increase productivity. “The Permian is now entering a 3-mile lateral era,” said Artem Abramov, Head of Shale Research at Rystad Energy. ”Such long wells were viewed as inferior for their high finding and development costs in some deeper zones just a few years ago, but modern equipment and completion methods allow extended-reach wells to spread across the entire basin .” However, it may be too early to view the increase in ultra-long laterals as an indus- trywide trend in the Permian, as some key operators contribute to this segment with a disproportionally large weightage rela- tive to their total number of completions. value. However, in terms of deal volume, M&A activity was largely flat at around 1,800 oil and gas deals in 2021. The upstream sector contributed to the highest M&A transaction value of $120 billion in 2021. It also recorded the high- est growth of 48% compared with 2020. Westwood: Nearly 47,000 onshore wells to be drilled around the world this year A new report by Westwood Global Energy Group is forecasting that approximately 46,700 onshore wells will be drilled globally in 2022, utilizing 3,960 active rigs per day. While those numbers are about 20% higher than what was seen in 2020, it’s unlikely onshore drilling activity will return to levels that used to be seen when oil prices were above $100 – unless there is a long-term return to such levels. In the US, Westwood expects 13,000 wells to be drilled this year, with an average of 650 rigs. In 2023, 15,000 wells are expected to be drilled with 751 rigs. Independents, which account for more than 50% of shale production, are still wary of ramping activity up to where it used to be and pushing oil prices to unsustainable levels, the report noted. In OPEC+ countries, because the pan- demic-related decline in onshore drill- ing activity had been more muted com- pared with other regions, growth will be less pronounced, as well. Overall, Westwood expects OPEC+ members to drill 23,000 wells in 2022-2023. Due to the long-term nature of the infrastruc- tural development plans ongoing in these countries, a strong ramp-up in drilling activity is not expected until late in the 2020s . In other parts of the world, Westwood pointed to China and India as countries where high oil prices and a heavy reli- ance on crude oil imports will provide incentive to increase domestic produc- tion. Argentina is also likely to see a major activity boost. In January, the country’s shale oil production totaled 224,000 bbl/day and accounted for nearly 40% of total production, which is a 61% jump from the previous year. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R OIL & GAS MARKETS • DEPARTMENTS Texas Petro Index: Strong crude prices drive recovery of state’s E&P economy BY STEPHEN WHITFIELD, ASSOCIATE EDITOR After nearly two years of contraction, Texas’ E&P economy finally saw a year of recovery in 2021, driven primarily by the upward trend in crude oil prices, according to the Texas Alliance of Energy Producers’ Texas Petro Index (TPI). “We’ve begun to recover with the oil price as demand has begun to recover and as we’ve taken a considerable amount of supply offline, certainly in Texas,” Karr Ingham, Petroleum Economist at the Texas Alliance of Energy Producers, said on 26 January. “We find ourselves in recent months with prices averaging in excess of $70, and now we’re seeing prices going over $80. We’ve had quite an uptick in price this year.” The TPI, a monthly measure of growth rates and cycles in the Texas upstream oil and gas economy, has seen continu- ous growth since March 2021. From 138.3 that month, the index had risen to 172.6 by December, a nearly 25% increase. The December 2021 index, the most recent fig- ure available as of February 2022, also represented a nearly 29% improvement over December 2020 levels. However, the December TPI still remains around 19% lower than the most recent cyclical peak (post-2015, pre-COVID) of 213.6 set in February 2019. The TPI is calculated by assigning val- ues to a group of E&P indicators, including crude oil and natural gas wellhead prices, rig count, drilling permits, well comple- tions, Texas crude oil and natural gas pro- duction and employment figures. As a main driver of the TPI, average WTI prices rose by nearly 40% in 2021: up from $35 in 2020 to nearly $50/bbl last year. Monthly average WTI peaked at $77.12 in October 2021, although average prices have since risen even higher . Natural gas prices – which represents a combination of Waha and HSC prices – averaged $5.79/MMBtu in 2021, the high- est annual average since 2008 and a 251% increase over the $1.65 average in 2020. Winter Storm Uri was an obvious factor in 2021, with both Waha and HSC seeing significant spikes that February. In fact, TPI scor sc or oree 250.00 250. 200.00 200. 213.1 193.1 185.7 172.6 150.00 150. 134.0 100.00 100. 50.00 50. 0.0.0.00 December 2017 December 2018 December 2019 December 2020 202 0 D ecember 2021 December 202 1 Texas’ E&P economy continues to trend upward, with December 2021’s score nearly 29% higher than a year ago, although it is still notably below pre-COVID levels. Waha averaged $24.28 that month while HSC averaged $36.93. If the February num- bers are removed from the calculation, then natural gas prices averaged $3.53/ MMBtu in 2021. Even without Uri, how- ever, Mr Ingham said Texas was expecting an increase in gas demand as the state recovered from the COVID-19 pandemic. Average natural gas price in December 2021 was $3.53/MMBtu, a 42% increase over the December 2020 monthly average of $2.49/MMBtu. Rig counts in Texas also improved last year, although not at the same pace as oil and gas prices. The statewide rig count averaged 216 rigs in 2021, an approximate- ly 4% increase over the 207 rigs in 2020. The improvement is more striking when looking at average monthly rig counts, which increased from a low point of 170 in January to a high of 275 in December. That 275 is the highest the average rig count has been since April 2020, when it was 283, although it’s still well below the 533 rigs averaged during the last cyclical peak in October and November 2018. Total oil well completions dropped by 33.8% from 2020 to 2021, while gas well completions declined by 24.8%. This drop was expected after 2020 saw operators restart a high number of drilled-but- uncompleted (DUC) wells in 2020. “The 2020 spike in DUCs happened because production fell off a whole lot more rapidly than we expected post-COV- ID,” Mr Ingham said. “That’s certainly why we were able to maintain production in 2020 without adding too much to the rig count. But I think that’s played out now. We’re adding production, and we’re adding more rigs, so we don’t need to draw down DUC inventory.” Production in Texas is also trending upwards. For the first time since April 2020, crude oil production exceeded 5 mil- lion bbl/day in December 2021, according to preliminary estimates from the Texas Railroad Commission. Assuming contin- ued upside price support, then by the sec- ond half of this year, production is on target to exceed the previous record of 5.4 million bbl/day, set in March 2020. Meanwhile, natural gas production con- tinues to build on the records set in 2020, moving up from 10.51 million cu ft/day in 2020 to 10.68 million cu ft/day in 2021. Further, Texas added nearly 16,500 jobs in the upstream oil and gas sector last year, according to data from the Texas Workforce Commission. As of December 2021, an estimated 175,925 people were employed in the upstream sector, up from the post-COVID low of 157,330 in September 2020 . DC D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 13 I N NOVATI N G WH I LE DR I LLI N G Digital technologies support new workflows in drill bit forensics AI and machine learning allow for dull wear data to be easily collected, digitized and analyzed, leading to better bit designs, optimized drilling BY STEPHEN FORRESTER, CONTRIBUTOR A mong the equipment and technology necessary to drill a well, the drill bit is arguably the most critical piece of the puzzle. Bit design, a fast-paced world of iterative enhancements and improvements that enable wells to be drilled more rapidly and efficiently, considers many downhole factors— geology, lithology, wellbore geometry, potential interactions with the bottomhole assembly (BHA)—as specialized engineers seek to develop bits that can overcome the challenges inherent in today’s more complex wells. Highlights Automated digital dull grading Advanced software that can analyze bit photos/scans are allowing post-run bit data to be collected in digital formats, then analyzed in context with other data sets as part of advanced forensics analyses. Automating the bit dull grading process removes human subjectivity and helps ensure the data collected is consistent, accurate and usable. Both bit and cutter manufacturers can now get faster, more detailed insights to drive enhancements to their designs. 14 While drill bits may be the metaphorical tip of the spear, the process of grading their condition after a run has seen limited changes over time. Typically, rig crews perform onsite analysis of the bit, taking photographs of its condition and assigning it a dull grade based on industry-accepted methodology. However, this process can be time-consuming and fraught with human error and inconsistency. To advance drill bit design in line with the industry’s desire to digitize and automate processes, several companies have developed new technologies that augment or replace previous methods. Dustin Lyles, Vice President of Technology for Taurex Drill Bits, said the industry has to advance beyond archaic methods for dull grading of PDC bits. “The best insight that we have into what’s going on in that rock-to-bit interaction that’s occurring miles below the earth’s surface is that dull drill bit that comes back out,” he explained. “That’s a fingerprint of what type of drilling dysfunctions and environment the drill bit is seeing while downhole, and being able to analyze that bit is what gives us insight to produce our digital workflow and feedback system.” Knowing that there is intrinsic value in a drill bit is one thing, but obtaining actionable data is another. Digitizing bit condition data so it can be used across every drill bit design decision Taurex makes has been key, Mr Lyles said. Drilling and highly detailed dull data is fragmented in nature. Runs might be captured for projects with one specific operator and/or bit part number in Delaware Basin Wolfcamp B laterals, for example, and decisions M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G Above: The Automated Metrology Laboratory (AML) puts every drill bit that Taurex runs through an automated 3D robotic scanning procedure. Right: Data from the initial AML analysis on each drill bit is pushed into a database containing other data sets to help “paint a picture about what type of drilling dysfunction occurred, or what was the driving factor behind the wear and tear seen on the drill bit,” said Dustin Lyles, Vice President of Technology for Taurex Drill Bits. made relative to necessary actions to improve performance with- in that narrow scope. Taurex, however, believes that understand- ing the correlative relationship among drill bit design, wear and application is critical to making more holistic design decisions. To accomplish this, the company produced a digital dull analysis model/workflow, which leads into forensic analysis and root cause failure analysis on a large-scale basis. The Automated Metrology Laboratory (AML) is the company’s innovation in automated digital dull grading. Deployed at the company’s central repair and maintenance facility, every drill bit that it runs goes through an automated, 3D, robotic scanning pro- cedure. Within three to four minutes, Mr Lyles said, that scan is pushed to a remote server, allowing engineers to access and quan- tify the amount of diamond loss on every individual cutter on that bit. “Data from the initial AML analysis on each drill bit is pushed into a relational database to tether dull trends with application, design, electronic drilling recorder (EDR) and other relevant data sets necessary to put the pieces of the puzzle together,” he noted. “Then, we can paint a picture about what type of drilling dysfunc- D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 15 I N NOVATI N G WH I LE DR I LLI N G The bit scan generated by the Automated Metrology Laboratory allows engineers to quantify the amount of diamond loss on every individual cutter on the bit. tion occurred, or what was the driving factor behind the wear and tear seen on the drill bit.” The issue plaguing the industry is not a lack of trained engi- neers with the skills and mechanical means to evaluate a drill bit. Instead, it is the fact that there is too much subjectivity and incon- sistency in the process. “Our measurement system for evaluating diamond loss is accurate down to three-thousandths of an inch,” Mr Lyles said. “We know that it is extremely accurate and consis- tent across every bit that we run, and evaluating trends with that system provides insight into our bit design and how we overcome challenges in today’s drilling environments.” Understanding the complex relationships between back rake angle, side rake angle, axial force and tangential force versus cut- ter damage, which vary across every single bit design, allows for improvements to drilling performance and reductions in the wear sustained on a given bit. Cutter testing and development plays a critical role in advanc- ing drill bit performance. By having these types of data sets avail- able, Taurex can work directly with cutter manufacturers to drive enhancements to their designs before they even leave the lab. Traditionally, these manufacturers have not had a true feedback system providing insights from the end user. With the detailed data coming out of AML, however, these same companies now have access to the information they need to drive better decision making in their own design processes, leading to better cutters being implemented in drill bit design across the industry. “By application, the manufacturers can now go in and do their own statistical analyses based on the cutter grade run so that they can start to better understand and correlate cutter performance to real-life field applications, on a large-scale basis,” Mr Lyles explained. There is also the issue of how long it takes for individual human beings to perform drill bit analyses. A process of mechani- cal measurements would typically require several hours for an engineer to complete, but AML can now complete the task – with improved accuracy and precision– in only a few minutes . This provides Taurex with the ability to drive iterative improvements to bit design at a much more rapid pace than previously possible, especially when multiplied across hundreds of bits. “Data we get from AML can be used the same day on repairs going on in our shop,” Mr Lyles noted. “We need to have that data at our fingertips. It’s all about empowering us to make better deci- sions, and it really does come down to speed, which is why we automated as much of the process as we could.” Within 15 minutes — three to four for the scan and 12 to get everything uploaded to the database — Taurex engineers can access live data on every bit, tracking information on which cut- ters are performing best in which positions and which designs might have a higher damaged-beyond-repair frequency or higher rate of failure on a specific portion of the drill bit, Mr Lyles said. “Data democratization is a really critical component of what we do, and something we’ve spent a lot of time on,” he concluded. “You can’t automate producing an optimized drill bit, but you can auto- mate a lot of that analysis and evaluation methodology. You still need engineers, and you still need contextual domain knowledge to interpret the data — at least until we can use machine learning to build models. That might not be as far away as you think.” Digital dull analytics and in-bit sensors Halliburton’s Cerebro in-bit sensor package captures downhole data, including lateral and axial vibration, torsional resonance, whirl and stick-sli p. Understanding the drilling environment with data about downhole conditions and phenomena coming directly from the drill bit makes it possible to determine why damage occurred to the bit. 16 Chris Propes, Strategic Business Manager for Halliburton Drill Bits and Services, said that drill bit forensics are key to how the company does business. “It involves analyzing the dull condition of the bit and combining that data with information we know about the run to develop solutions that improve drilling perfor- mance,” he explained. One technology Halliburton uses as part of its bit forensics program, Oculus, is a big data analytics platform that takes 3D scans of every drill bit the company runs and uploads them into a database. This provides insight into cutter and bit-body condi- tion in every market in which it operates. The massive amount of information coming in, Mr Propes said, must be understood before it can become actionable. “What we’ve done is built internal design platforms that allow us to search down to a specific application — whether an inter- mediate section in the Permian or a drill-out run offshore — and M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G narrow our scope down to extract all of that forensic informa- tion for that application,” he noted. “That includes dull analytics from Oculus data, photography and downhole performance data. Having all that made it possible to build visualizations that help design engineers make trade-offs to optimize bit design for those applications.” The sheer number of bits that go into Halliburton’s repair and maintenance facilities on any given day is actually an advantage when paired with a system like Oculus. “Every service center is set up with Oculus,” Mr Propes said. “So, when a bit comes back to the facility post-run, the first step of the cycle is to scan it with Oculus to capture that forensic data.” It is not enough, though, to simply obtain information on the dull grade. Instead, forensic data from Oculus must be correlated with design characteristics — the cutters being run, the back rakes being run, and so forth — so that design decisions can be tied to the advanced forensics analysis to make meaningful improvements. Halliburton, Mr Propes noted, approached this process in a systematic way. “When you think historically about how you design a bit, you would get offsets from three or four runs, you would look at pho- tographs and determine if there was impact damage or abrasion, and then you would make decisions based on that, but you’d be isolated with those designs,” he explained. “The key enabler we’re seeing gain traction is that, although we can still look at those three offsets in fine detail, we can now enhance decision making using data from 100 offsets or 1,000 offsets — whatever we filter to be relevant. It’s about making data-driven decisions versus intuition-driven decisions, and we’ve moved our whole design philosophy in that direction.” Cutter development is the other area in which Oculus provides quantifiable improvement. With Halliburton running thousands of cutters, a system that allows the company to compare cutter performance in a manner that is analytical instead of anecdotal has driven a step-change in how it interfaces with cutter manu- facturers. “In collaboration with the cutter manufacturers, we have a robust understanding of the levers of PDC diamond — grain size, pressure, leech and all the other variables that go into making different types of cutters,” he said. “The additional value we bring is a high-level understanding of dull condition, so we can provide data on the cutters relative to the downhole environment and determine what levers we need to pull to solve specific challeng- es. The advent of data in those discussions has been beneficial by taking subjectivity out of the equation.” Another technology critical to Halliburton’s drill bit forensics program is the Cerebro in-bit sensor package. The sensors capture downhole data, including lateral and axial vibration, torsional resonance, whirl and stick-slip, while an upgraded version also captures data on weight, torque and bending measurements. Understanding the drilling environment with data about down- hole conditions and phenomena coming directly from the drill bit makes it possible to determine why the damage noted by Oculus occurred in the first place. “We want to combine data-driven dull analytics and in-bit sensing with advanced bit technologies and cutters to bring The Oculus data analytics platform lets Halliburton take 3D scans of bits and then correlate the data from the scans with the bits’ design characteristics to make meaningful improvements. everything together through our design interface,” Mr Propes said. “We want to take all that information and efficiently integrate it into a bit design that will consistently outperform whatever the baseline target is. Historically that’s been an SME-driven, one- off process. Now, with automated systems, we can make it more repeatable and consistent to extract performance out of our designs through data.” Instead of basing decisions on limited, often anecdotal pieces of information, companies that use technologies like Oculus and Cerebro are able to more precisely understand cutter failure mechanisms and downhole drilling environments. Advanced dull analytics and depth-based run data come together to provide a much clearer picture of what happened to the bit, enabling superior solutions that ultimately result in drilling performance improvements. Autonomous bit dull forensic digitization system While some bit forensics solutions focus on technology in a lab, Trax Electronics has a system that can be used either in a shop, lab or at the rig site. Called grA+de, the autonomous dull bit foren- The images collected by Trax’s bit scanner are used to produce high-resolution 3D models of the bit, including all wear measurements and characteristics. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 17 I N NOVATI N G WH I LE DR I LLI N G A point cloud map of a scanned bit can help companies decide if they want to change drilling parameters to avoid the same damage seen in the visualization. sic digitization system can be used immediately after a run . The goal is to eliminate the inherent inconsistency and unreliability in human interpretation, while also freeing up engineers to focus on other critical tasks. Before such technology was available, laboratory staff would manually sift through and analyze post-run data. This was always a laborious task, made more daunting by variation in the quality of data from the field. Due to the discrepancy in the type and quality of data coming in, aggregation of the information into an analytical software package for diagnosis was difficult. Furthermore, attempting to overlay this data with relevant drill- ing parameters to truly assess bit performance was extremely challenging, if not impossible. “We wanted to build a machine that could be easily operated by someone with minimal training in a shop, at a lab, at a rig site, or The bit scanner from Trax Electronics is a roughly 4-ft cube that can be placed on a rig, in a shop or in a lab. It automatically takes pictures of the bit to build a 3D visualization. 18 potentially anywhere, and reliably build a 3D visualization,” said Ron Schmitz, Executive Advisor at Trax. “We use photogramme- try, which is basically taking photographs from various perspec- tives around the bit, and build a visualization with that.” Robotic-controlled, AI-enhanced photogrammetry, or the sci- ence of making measurements from photographs, is at the core of the system. The user places the bit within the scanner, a roughly 4-ft cube, and lets the system get to work, with a camera taking pictures automatically at all relevant angles. Once those images are input, the output is typically a point cloud map, which is a drawing, measurement or 3D visualization of some real-world object or scene. The scan takes approximately 15 to 20 minutes depending on the size of the bit, while it takes approximately 90 minutes for the AI to compute the dull bit forensic characteristics. By leveraging and applying this technol- ogy to dull bit grading, the system produces highly accurate and repeatable measurements of individual cutter wear in PDC bits, as well as machine-generated base parameters for the IADC dull bit grading protocol. Trax says it sees quantifiable value in having its system on a rig, in a shop or in a lab. “We feel that there’s a big advantage in being able to obtain an independent analysis from a third party,” Mr Schmitz said. “There are also time and cost factors; since we can provide photographs on site, at a lab or in a shop, you can view the visualization in a few hours. It may not help you decide which bit to run, but it could help you decide that you want to vary drilling parameters to avoid some of the damage you saw in the scan.” The point of collecting this data is not simply to understand what happened to the bit, of course, but also to use the data to opti- mize drilling. By obtaining reliable, independent cutter-by-cutter forensics, Trax sees five key areas of bit forensics that will enable better drilling performance. First, companies can improve bit design and quality control, enabling better operator/vendor collaboration and potentially enhancing drilling and directional performance, particularly in unconventional wells that are longer and more complex. Then, drilling dysfunctions can be identified to eliminate cutter dam- age, ultimately prolonging bit and BHA life and reducing the time needed for tripping . Next, bit wear can be managed, which Mr Schmitz said is critical. “There are a lot of issues around bit wear instead of bit damage,” he explained. “For example, looking at where the cutter is located on the bit and if it’s spalled, chipped or broken, people can get a good idea of what was going on downhole to cause that damage.” He also noted that often, pulling a bit with no or only “smooth” cutter wear may not be optimum, as this could indicate that performance wasn’t maximized. Being able to assess smooth wear down to “sub-0” levels could be very important in some applications, as that could mean higher ROP could be achieved without causing damage. Less wear does not necessarily mean an optimum run. The fourth area is increasing data granularity to make big data analytics possible. “A typical dull code involves an overall average for the bit as a whole,” Mr Schmitz said. “The new protocol being considered by the IADC has information across all the cutters on M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G UT Austin’s automated forensics process relies on software to accurately evaluate bit damage and failure so that changes can be made to the bit and/or BHA before the next run. every blade, distinguishing if the damage is in the cone, nose or shoulder, how much is the loss area, and what kind of damage occurred.” The next step, which could be enabled via Trax’s bit forensics, is an even more detailed analysis on a per-cutter basis, down to the wear or damage seen at a micro level. The final objective is to improve overall quality assurance, which is critical in iterative bit design improvements. “When we analyzed one bit with a depth-of-cut (DOC) limiter, for example, we noted a difference in the visualization between what it was supposed to be and what it actually was,” Mr Schmitz noted. “When we’re talking about the very precise designs that they’re trying to develop now, in terms of limiting the DOC to exactly what they want in order to avoid damage while maximizing DOC to drill as fast as possible, differences of that magnitude start to become important.” Drill bit failure forensics using field photography Drill bit forensics is also a topic of study in the world of aca- demia. An ongoing research initiative at the University of Texas (UT) at Austin involves the development of a software algorithm that can automatically analyze photos taken of the bit at the rig site and identify, from those photos, the root cause of bit damage and failure. The goal of the project is for the software to be able to accurately evaluate a used bit so that changes can potentially be made to the BHA and/or bit before the next run . The methodology for this automated forensics process involves four steps. First, the algorithm is given a set of drill bit photo- graphs that clearly show individual blades, allowing the software to identify all the cutters on that bit. The software then quanti- fies the damage to each cutter, drawing on a database of surface sensor and downhole vibration data, as well as offset well rock strength information, to characterize drilling dysfunction relative to the damage seen on the bit. After calculating cutter location, the software then uses a classifier to determine the average damage in various parts of the blades, thereby enabling it to infer the root cause of damage. Jian Chu, a PhD student working on bit forensics research, explained that the initiative continues to advance. Previous versions of the software were not always able to detect all the cutters based on the photographs available and lacked precision. Additionally, not all damage could be calculated, and when it was, it was only quantified as a whole number. Further, the algorithm was affected by lighting, and the forensics process did not include EDR data. However, the team is now focusing on identifying the damage type (such as worn, chipped) and improving the precision of damage grading via semantic segmentation. Mr Chu said it was critical that noise from the drilling environ- ment is removed in order to develop something truly useful. “One big issue we had is that we didn’t have a lot of data,” he explained. “For traditional machine learning algorithms, they would need millions of data points to train the neural network. We didn’t have that much data, so we had to remove all the noise and really focus on what we had.” Through precise area isolation, damage categories identifica- tion and integration of expert systems, the process will eventually be entirely automated, with the algorithm becoming more and more accurate. Since the photography used to drive the algorithm is still prone to human error, Mr Chu said that maybe one day, computer vision on the rig floor could take photographs of the bit as the BHA is pulled, capturing all angles and feeding that data to the algorithm. There is additional potential should a company choose to develop an application for the algorithm that could be deployed on a smartphone or tablet, which would make the process even easier and reduce the concerns associated with limited connec- tivity on remote sites. For now, Mr Chu said he isn’t worried about the commercial potential of the platform. He is more interested in advancing the field of drill bit forensics: “I want to make some- thing useful for the industry .” DC D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 19 I N NOVATI N G WH I LE DR I LLI N G IADC ART Committee moves closer to launching updated drill bit dull grading system When completed, new system is expected to remove human subjectivity in grading process, support root cause analyses of bit damage BY STEPHEN WHITFIELD, ASSOCIATE EDITOR In 2021, the IADC Advanced Rig Technology (ART) Committee launched a project to upgrade IADC’s long-standing bit dull grading system. The objective was to develop a more modern system for under- standing and grading bit wear that better supports workflows for root cause analy- sis and continuous improvement. “The existing bit dull grading classifica- tion system needed to get a major upgrade,” said Robert van Kuilenburg, Mechanical Engineering Manager at Noble Corp and former ART Committee Chair. “It was heavily focused on the justification of pull- ing and not on the root causes. It relies too heavily on expertise, and there’s no frame- work for metadata inclusion and limited support for automated drilling systems. It just doesn’t cut it in today’s environment.” The ART workgroup, led by Mr van Kuilenburg along with ExxonMobil’s Paul Pastusek, Shell’s Dustin Daechsel, and Data Gumbo’s Robin Macmillan, formed four smaller teams to examine differ- ent aspects of the upgrade process: drill bit code definitions; BHAs and motors code definitions; data management; and case studies. During a live Virtual Panel Discussion hosed by Drilling Contractor on 9 February, representatives from each team discussed the work they have done, their planned output, work items left to be resolved, and the estimated timeline to completing the system upgrade. Drill Bit Code Definitions This team set out on its task by recog- nizing that the current codes haven’t been updated since 1987. Not only do they not provide enough granularity on the types of damage experienced so that detailed root 20 causes analyses could be conducted, but they also require human expertise and are subject to interpretation. So the team set out to develop a qualita- tive classification scheme of PDC cutters, drill bits and tools with cutting elements, along with second priority on quantitative analysis. While the system will focus on PDC bits due to their market domination, the system will also be compatible with other bit types. Further, it recognizes dif- ferent levels of dull grading. “We’re looking to split the grade in terms of a rig grade, which is still similar to what we do today in terms of grading at the rig, and then we’re going to have the more accurate forensic shop grade,” said Tom Roberts, Vice President – PDC Strategy and Development, NOV. “The importance of the two is that the rig grade provides real-time decision making and is still extremely important, but both will come together in terms of advanced forensics.” New damage categories, such as cham- fer damage and axial break, were also added, along with a category of classes specifically designed to evaluate the wear on the substrates of PDC cutters. This was a critical addition because substrate dam- age can often indicate more substantial damage within the BHA, said Dustin Lyles, VP of Technology at Taurex Bits. “When you look at, say, a corroded sub- strate and you see a lot of pitting, you know that’s a sign of either H2S or poten- tially caustic mud,” Mr Lyles said. “When that occurs on a drill bit, it’s obviously very critical for not just the drill bit providers but also the operators to know that there’s H2S present or that the mud is caustic. That lends itself into pushing that person or that organization into looking at other BHA components, because it’s likely that it’s not only the drill bit that’s experienced that type of corrosive damage.” The group also oversaw an expansion of the bit zone categories, from just “inner” and “outer” to include the cone, the nose, the gauge and the shoulder. “The historic ‘inner two-thirds to outer two-thirds’ system was very applicable to roller cones, but it was not very applicable to PDC bits,” Mr Lyles said. “We believe this type of improved granularity into the drill bit zones will give additional color and help drive the root cause forensic analysis.” The next steps for the drill bits group are to finalize a training document with exam- ples of the new wear categories. Later this year, the group also expects to conduct field trials, where companies will grade cutters and provide feedback on the effectiveness of the new categories. Further, this group will work with the data management team to develop a digital interface of the new cat- egories for the IADC Daily Drilling Report. BHA & Motors Code Definitions This group is focused on the classifica- tion of the BHA, motors, RSS tools, stabiliz- ers and other BHA elements and has been working to create a forensics evaluation workflow and best practices document for BHA coding. “The bit dull grading system has served very well in creating a picture of the con- dition of the bit once it’s above rotary, and it has been a proven tool in improving performance. But there’s nothing that’s been done on the BHA side,” said Paul Neil, Senior Director of Drilling Solutions, Engineering and Reliability at NOV. The BHA team is comprised of five targeted sub-groups, each tasked with developing a coding system specific to its area of focus: motors, rotary steerable, data acquisition, performance enhancement and iron (stabs, collars, subs). The BHA coding is structured into three levels, where the first is a high-level exam- ination of the BHA. At this level, users can quickly flag any issues with a part of the BHA that require review and investiga- tion. This coding system lists six main codes indicating different types of damage or reasons for failure (no damage, back- M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G The IADC ART Committee recently held a Virtual Panel Discussion to detail its progress to upgrade IADC’s bit dull grading system, which had been widely used for decades but had become outdated in today’s environment. off, washout, cracks, fracture) for different components within the BHA (bit, MWD, positive displacement motor, RSS, stabi- lizer, formation evaluation and perforation enhancement). Users can also note rea- sons for pulling the BHA. Level 2 is designed to give users a detailed method for reporting issues with individual components within the BHA. In addition to the six main damage codes, it contains separate codes for the location of the damage, wear severity and field obser- vations. Users can also note primary and secondary causes of damage or failure. Level 3 will standardize classifications when performing root cause analysis and conducting post-run investigations of the BHA, although work on this section is not scheduled to begin until later this year. This year, the BHA team expects to finalize the field coding system for each of its five sub-groups. So far, the BHA team has added 13 new categories to describe the reasons for pulling the BHA, and it established 46 new damage/failure codes. Mr Neil said the team will continue to update these codes once it conducts field testing later this year. Case studies This team focused on collecting case studies for the most common modes of dysfunctions encountered while high- lighting their corresponding post-run forensic evidence. These case studies will be used for training, as well as to ensure that the codes developed by the other teams are adequate for forensics and con- tinuous improvement investigations. Willie Watson, Well Engineering Manager for Shell, described this team’s work as a means of synthesizing the work done by the other teams. It is linking the damage identified in the new codes from the drill bit and BHA teams with informa- tion gathered from its own investigations and polling of subject matter experts. “As you start to investigate, you see what damage is caused by specific drilling dys- functions,” Mr Watson said. “Our goal is to pull the information from our investiga- tions together, combine the forensic evalu- ation with the actual conditions that drill bits and the BHAs have been exposed to, and use that to help us diagnose the failure.” The team’s work to identify potential case studies focusing on common failures, which will be included in a best practice document, is still ongoing. A group of subject matter experts continue to review examples of failures and damage to see which ones are best suited for develop- ment as case studies and as best practices. This group is also reviewing the codes proposed by the drill bit and BHA code definition teams to make sure they are necessary, unique and well understood, and that accurately describe the damage and current status of a given component. This work should be completed by the end of Q1 2022. By Q2 this year, the team aims to define the standards for critical and the “nice to have” data required for each study and establish consensus among the teams on each standard. It will also gather and label a set of photo and digital data examples of various damage/failure codes for human and machine training. By Q3 2022, when field trials of the updat- ed bit dull grading system are complete, the team will document the frequency of occur- rence of different degradation modes to use as a priority guide for human and machine training. After that, the team hopes to cre- ate a forensics evaluation workflow and continuous improvement best practices document for industrywide rollout. “More and more people are involved with the data collection process, data management process, exchanging data and essentially getting a hold of data so that it could help them make good deci- sions,” said David Shackleton, IDS Business Development Manager at Schlumberger. To create the guideline, the team inves- tigated best practices for bit, BHA and sur- rounding data formats, and for collecting and classifying digital visualizations such as photos, videos and 3D models. In one chapter of the document, the team looks at different ways of storing and accessing data, data model types, and current stan- dards such as PPDM and WITSML. Another chapter covers good practices in data man- agement, focusing on the proper ontology, validation and verification for data. Collection and storage of example data was facilitated by cooperation among the workgroup’s various teams. Based on these examples, the data management team was tasked with creating a training data set of forensics photos with agreed upon codes. Work is still ongoing for the design, construction and eventual launch of the training data set. However, the guideline offers some suggestions for the industry to consider. It outlines possible structures for a training data set, as well as the role- based permissions companies can use to establish who gets access to the data. DC Click here to watch the Virtual Panel Discussion on the dull grading project. Data management The data management team focused on developing a guideline to store codes, digi- tal images and other metadata about drill bits. This digital data exchange guideline will be usable for machine learning tools and real-time data exchange on the rig. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 21 I N NOVATI N G WH I LE DR I LLI N G Industry seeks ways to understand and fight elusive downhole enemies Dysfunctions like HFTO can be hard to detect, but companies are identifying mitigation solutions through sensors, bit studies, predictive software BY STEPHEN WHITFIELD, ASSOCIATE EDITOR I n operators’ quest to maximize the value they get from each well by drilling longer and more complex bores, they’re also having to deal with a higher risk of encountering downhole dysfunctions, such as high-frequency torsional oscillation (HFTO) or lateral shock. Such events can potentially lead to damage in the BHA and other downhole tools, adding time and cost if they have to be pulled prematurely. Understanding the nature of these dysfunctions has, therefore, become more important than ever. “In the industry, we’re always chasing ROP, trying to get the best drilling performance we can. But getting the best performance is not always tied to ROP,” said Raju Gandikota, Co-Founder and Chief of Innovations at MindMesh, an engineering software and technology development company. “It’s about managing the tool Highlights Testing of various sensors and their placement showed that HFTO cannot be detected from the surface. Bit wear and cutter placement were found to be among drivers of HFTO vibration magnitude. Near-real-time data streams can be integrated with predictive models in a digital twin to see how dysfunctions occur as the drill string moves downhole. 22 life, having vibration control and maintaining the effectiveness of your tools so that you can actually reach total depth.” To better anticipate downhole dysfunctions and stave off their more destructive effects, some companies are testing different sensor types and various placement to see how they can more effectively detect HFTO, while others are studying the relationship between different bit designs and HFTO. Predictive software is also poised to provide the industry with more information needed for better decision making to prevent or mitigate downhole dys- functions. While these approaches differ, the common goal is to understand the source of damaging vibrations so that downhole tools can become more durable and stay in the hole longer. “How many times does a customer come to us and say, hey, we are losing expensive downhole tools?” asked Prabhakaran Centala, Engineering Manager for PDC Cutter Technology at NOV. “If they bring these failures to the table, then we have to figure out the best way to mitigate that. There are so many intricate details that can help us bring about a different level of performance altogether.” Understanding and identifying HFTO HFTO, which is characterized by torsional oscillations of the drill string or BHA that fall within the 100-300 Hz frequency, can be particularly difficult to measure and quantify compared with other types of vibrations, like stick/slip and bit bounce. If left undetected, HFTO can lead to downhole tool failures, such as twist-offs, connection cracks in the BHA, washouts and prema- ture bit dulling. “Nowadays, rotary steerable tools are much more sensitive, with moving mechanical parts and electrical compo- nents. Because of this sensitivity and their complexity in nature, we’re more susceptible to tool failures because of HFTO,” said John Rodriguez, Drilling Engineer at Occidental Petroleum (Oxy). M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G Dysfunctions such as high-frequency torsional oscillation (HFTO) and lateral shock can cause costly problems like washouts, twist-offs and connection cracks at the BHA. Through different approaches, companies are trying to better understand the source of damaging vibrations so the life of downhole tools can be improved and they can stay in the hole longer. To attain a better understanding of HFTO, Oxy conducted tests in the Delaware Basin from 2018 to 2020 utilizing commercially available high-frequency downhole sensors in various positions along the BHA, as well as an anti-stick/slip tool. These tests also aimed to determine the ideal sensor types and placement of the sensors for identifying HFTO. “When you’re losing the BHA downhole, that’s something that’s worth millions of dollars. These types of serious NPT events prompted us to investigate HFTO. We wanted to do some field testing to get an understanding of what was going on downhole,” Mr Rodriguez said. Oxy has shared results from some of the tests that were con- ducted. In these tests, it looked at three sensor types – a high- frequency “puck” sensor with a vibration sampling frequency of 800 Hz placed in the shank of a 6.75-in. bit; a high-frequency sensor with a vibration sampling frequency of 1,024 Hz that was designed to be run above the RSS on a directional BHA; and an ultra-high-frequency sensor (vibration sampling frequency of 1,500 Hz) installed in a carrier sub run above the MWD. The data from each sensor was measured against data from the surface. However, the sensors were not necessarily measured against each other in every test. Some tests were conducted to measure the performance of downhole tools that could help miti- gate HFTO. One test compared the performance of the low-frequency and high-frequency sensors on a 6.75-in. BHA with no anti-stick/slip tool. While the low-frequency sensor in the RSS recorded consis- tent RPM throughout the test, ranging between 100-200 RPM, the high-frequency sensor that was placed above the RSS measured significantly greater variations, between 0-400 RPM, on multiple occasions. Each variation in RPM coincided with an HFTO event recorded during the run, the last of which led to a tool failure. Meanwhile, the surface drilling data stayed consistent throughout the run. The mechanical specific energy (MSE) remained low, top drive torque remained steady, and top drive RPM stayed constant at 175 RPM. The results from this test led to two understandings, Mr Rodriguez said. First, vibration data from a standard sensor in the RSS cannot capture HFTO events, and second, HFTO cannot be detected from the surface. “HFTO happens within a pretty short time frame and distance. It doesn’t travel all the way to the surface like LFTO. Because it’s a high-frequency event, the travel distance is just within the BHA. We saw in our data sets that you can’t identify it in real time while drilling. Your MSE and your ROP don’t really change. You could be drilling fast and see stable drill- ing indicators at the surface, but downhole it could be an entirely different picture.” Another test measured the high-frequency “puck” sensor in a 6.75-in. bit shank and compared it against surface data. For this test, Oxy utilized a 4.75-in. motor above the RSS in two separate runs, one with and one without an anti-stick/slip tool, a device placed above the RSS/MWD and below the motor that D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 23 I N NOVATI N G WH I LE DR I LLI N G Finding links between HFTO, bit features Oxy conducted a field test comparing the performance of a low-frequency sensor in the RSS and a high-frequency sensor placed above the RSS in a 6.75-in. BHA. During the HFTO events recorded in the test, the high-frequency sensor measured significant variations in RPM, while the low-frequency sensor measured consistent RPM. This indicated that HFTO could not be captured by RSS vibration data. is designed to prevent excess torque from traveling up the drill string. Mr Rodriguez noted some additional findings from this test. First, the high-frequency sensor in the drill bit detected instances of HFTO early in the first run, although the tangential accelera- tions were less than 20G-acceleration. The bit was pulled for slow ROP and was damaged beyond repair once tangential accelera- tions exceeded 100G-accelerations. Second, the anti-stick/slip tool used in the second run reduced the level of tangential accelerations measured at the bit, where tangential accelerations averaged less than 20G-acceleration for the entire run. This indicated that the anti-stick/slip tool could help reduce the level of tangential accelerations at the bit. While this does not eliminate HFTO, it can help mitigate its most dam- aging effects. Oxy said it paused this series of HFTO testing in March 2020 following the oil price downturn but plans to resume this project in the future. 24 For the past couple of years, NOV has been exploring the relationship between bit design and HFTO, hoping to eventually create a new bit design that could help minimize the downhole dysfunction. In particular, the company worked to identify what links observable HFTO with bit design metrics or features, develop- ing tests based on four hypotheses that came out of previous field observations and other studies on HFTO. The first theory NOV considered was around worn cutters. As worn cutters are more susceptible to low-frequency torsional vibration, they could potentially be more susceptible to HFTO, as well. Second, tracking PDC cutters are less efficient than non- tracking cutters, primarily because of the shape of the cut that the PDC makes when interacting with the rock. “Tracking” and “non-tracking” cutters refer to the placement of a backup row of PDC cutters directly behind the primary cutters. These secondary cutters, which help enhance the durability of fixed cutter bits, can be placed either at the same radius as the primary cutters (track- ing) or in between (non-tracking). A tracking cutter will engage with the formation over a long portion of the cut shape with a small depth of cut (DOC); a small DOC is associated with a high MSE. A large shear length to shear area ratio indicates an inefficient cutting shape with a small DOC and potentially contributes to HFTO. Third, diamond-impregnated secondary components could help reduce vibratons. NOV noted that overly sharp, freshly ground PDC cutters are more likely to cause the vibrations indica- tive of HFTO compared with cutters that have been slightly used. However, the company noted no instances of HFTO when using impregnated bits, even though they commonly drill at very small DOC in hard rock. This was because rock fails through grinding, rather than shearing, as the cutting face of the impregnated bit slides against the rock with little risk of overengagement. Part of NOV’s testing studied whether it was possible to manu- facture cylindrical components shaped like a cutter made from the same material as the impregnated bits and placed in a sec- ondary cutting location on the face of a PDC bit. This combination of shearing and grinding rock failure could mitigate HFTO. The fourth hypothesis pertains to the effective back rake angles of the cutter placement on the bit. As the effective back rake angle increases, it tends to limit the DOC and can lead to a greater risk of HFTO occurring. To test these theories, NOV conducted several experiments at its pressurized drilling laboratory in Conroe, Texas, over the past year. Two 216-mm bits with seven blades and 16-mm cutters were used. The bits were tested on rock cores under different drilling conditions to simulate field tests. Bit A had 32 face cutters and 18 tracking secondary cutters. Each element of the bit design was chosen to test the theoretical connections between bit design and HFTO: cutter wear, the ratio of shear length to shear area, the choice of secondary cutter mate- rial and effective back rake angles. The back rake angles on the face of the cutter were between 19° and 20°. When first used, this bit had wear as received from field testing; the cutters were worn, and the gauge pad had suffered some wear. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G In lab testing, NOV examined the relationship between bit wear and HFTO. Configuration 1 (dull cutter) showed greater average HFTO amplitude than Configuration 2 (new cutter), with the difference becoming more pronounced at lower RPMs. Bit B, a new design, had 30 face cutters with the shape alter- nating between chisel and full round. Further, the cutters were laid out in a star spiral order, with the shape alternating between chisel and full round. The alternating shape and star layout was chosen to improve the ratio of shear length to shear area. There were 10 secondary cutters in Bit B made from the same material as a diamond impregnated cutter. These secondary cut- ters were placed in a tracking location. The back rake angles of the face cutters varied from 15° in the cone to 20° near the gauge. The bits were tested in five separate configurations. The first configuration was used to examine the effect of bit wear on HFTO, with successive configurations changing different elements of the bit to isolate which parameters had the most significant impact. Configuration 1 involved the use of Bit A directly from the field, already having dull and broken round cutters on its primary and secondary blades. Configuration 2 involved the replacement of the dull and damaged cutters on Bit A with undamaged 16-mm round cutters on the primary and secondary blades. Configuration 3 involved the use of non-planar cutters to increase back rake angles. Configuration 4 involved replacing the secondary cutters with cylindrical diamond impregnated material. Configuration 5 involved the use of Bit B. Each configuration was tested at 10 separate combinations of weight on bit (WOB) and RPM. Before testing a configuration, the hole was prepared by drilling 130 mm into the rock to generate the bottomhole pattern, ensuring that all tests start with similar formation engagement. Testing of Configuration 1 compared with Configuration 2 showed that worn cutters increase the risk for HFTO. At 100 RPM, the new cutters in Configuration 2 led to a 53% reduction in the amplitude of HFTO. The disparity in amplitude increased as RPM decreased – Configuration 2 saw an 82% drop at 75 RPM and a 97% drop at 50 RPM. This indicated that the PDC cutters should be cho- sen for longevity and durability in areas where HFTO is a concern. Configuration 3 had a 39% decrease in HFTO amplitude com- pared with Configuration 2, indicating that higher back rake angles – the angles of the face away from the end cutting edge of the drill bit – can reduce HFTO for a given WOB and RPM. However, the average ROP also increased 23% from Configuration 2 to Configuration 3. The use of diamond impregnated cutters (Configuration 4) in place of the secondary cutters showed a 12% reduction in amplitude and an 11% increase in ROP. The differences in back rake angle proved less significant than the other factors tested in determining the risk for HFTO. The data did not support the theory that increased back rake angle would worsen HFTO – in fact, Configuration 3 showed the 39% decrease in HFTO amplitude despite having an increased back rake com- pared with Configuration 2. The results from the study indicated that the optimal bit design to limit HFTO vibration magnitude requires the use of durable cut- ters with either non-tracking secondary PDC cutters or diamond- impregnated cutters and a low back rake angle. While NOV said it has no imminent plans to turn the learnings from this study into a new product, the company’s ReedHycalog business unit does hope to have a roadmap by the end of this year for developing a product line of bits designed specifically for miti- gating HFTO. “Our next goal is to develop an agenda where we can go to our customers and tell them how we’re going to bring about a bit that will help the industry reduce HFTO at the source. We don’t have a product line solely dedicated to HFTO right now, but we do have an agenda,” Mr Centala said. Predicting dysfunctions with a digital twin Computer-based well planning and drilling dynamics model- ing is a standard practice for improving drilling performance. However, it has its limitations. Primarily, conventional well planning software produces static models of the downhole, which are not useful in analyzing down- hole behavior over a period of time. That is key to identifying the risk of dysfunctions, said Mr Gandikota of MindMesh. “What we are missing with the static model is the interaction of the drill bit cutting rock, and how the BHA interacts with the hole while D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 25 I N NOVATI N G WH I LE DR I LLI N G MindMesh has added real-time prediction of downhole dysfunctions and drilling dynamics to its digital twin. In the simulations shown here, an operator used the platform to identify ways it could drill with higher ROP without inducing lateral shock. we’re drilling. Can we take a snapshot and use that to explain a movie that’s two hours long, or 10 days long? That’s what we’ve been trying to do.” Last year, MindMesh updated its RiMo digital twin platform to incorporate real-time prediction of drilling mechanics and down- hole dysfunctions. RiMo is a time-domain model, meaning that it analyzes the behavior of the BHA and the drill string as it moves downhole. It integrates predictive models with a near-real-time data stream through a WITSML feed, as well as parallel comput- ing capabilities, so it can update the digital twin during drilling while predicting potential dysfunctions downhole. Users can build a workflow that automatically recognizes drilling rig states and records quantifiable drilling parameters like shock and vibration, downhole MSE and ROP in near-real time. These events then act as cues for the predictive model. For instance, if predicted bit RPM, downhole MSE and ROP reach a certain threshold indicative of stick/slip, the predictive model will alert users of a potential incident. The model then runs a simulation, known as a “drill-off test,” where users can adjust various operating parameters to see how it affects performance indicators and adjust them at the rig. Mr Gandikota touted the system’s ease of use, noting that few inputs from the user are required. “As soon as you input the BHA, all you have to do is set up a dashboard. We’ve tried to make this more visual and easier to map with the real-time surface data. At the end of the day, once you’ve installed it, it becomes a routine process. All the information is standardized. All you have to input is what type of bit you’re using and what type of formation you’re looking at, and then you’re ready to go.” In 2020, an operator in the Permian used the software to improve its drilling operations. The operator was experiencing high frequencies of lateral shock, where the lateral motion of the BHA reaches a high enough amplitude to force the BHA to bounce against the wellbore. This was occurring whenever ROP reached 100 ft/hr, so the operator used the digital twin to examine how it could increase ROP while keeping lateral vibration low. The predictive model analyzed instances of lateral shock 26 as ROP approached 100 ft/hr, and the operator chose to test the impact of WOB and top-drive RPM on ROP and lateral vibration. The model then ran two optimization scenarios in a drill-off test, one in which the WOB was increased in 10% intervals from the initial WOB measured at the 100 ft/hr ROP, and top-drive RPM was decreased, also in 10% intervals. As WOB was increased, the ROP increased from 100 ft/hr in the initial scenario to 160 ft/hr in the first optimization and 190 ft/hr in the second optimization. The operator used lateral shock counts above a threshold to indicate severity in vibration over a time interval. In the initial measurement at 100 ft/hr ROP, the model measured 40 lateral shocks. It then predicted 37 lateral shocks in the first optimization scenario and 24 lateral shocks in the second scenario. The operator was persuaded to increase WOB and decrease top-drive RPM to help increase ROP and reduce lateral shocks. The digital twin platform is currently being used by two opera- tors and two directional drilling companies, all in the Permian Basin. Two drilling contractors are also trialing the platform ahead of potential full-time deployment on their rig fleets later this year, according to Mr Gandikota. DC Click here to watch a video with MindMesh’s Raju Gandikota discussing the company’s digital twin. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G Multilayer mapping-while-drilling service delivers real-time insights to optimize reservoir exposure Deployments in Australian CSG and offshore China demonstrate service’s ability to provide precise boundary, layer detection for better steering BY VERA KRISSETIAWATI WIBOWO AND HAIFENG WANG, SCHLUMBERGER To overcome structural complexity, poor seismic coverage and technology limita- tions that can lead to extended drilling time, multiple runs or additional logging, drillers require technology with capabili- ties to map more than one boundary and accurately estimate reserves in areas of geological uncertainty. Conventional boundary mapping-while-drilling technol- ogy with a limited depth of investigation has driven industry demand for technol- ogy that improves reservoir identification, enhances decision making while drilling and helps drillers stay in the reservoir as long as possible. Drillers in Australia and offshore China have doubled the depth of detection range using the PeriScope Edge multilayer map- ping-while-drilling service . The service provides deep resistivity measurements, higher resolution and a high-definition inversion process, providing continuity, definition and certainty that improves accuracy of multilayer mapping while drilling. Multilayer technology The multilayer mapping-while-drilling service combines advanced inversion with measurements coming from axial, tilted and transverse antenna, which pro- vide faster and higher delineation of reser- voir layers and formation evaluation while drilling. The antennas measure resistivity and anisotropy deep into the surround- ing formation, providing high-resolution measurements and enabling Rh and Rv mapping of each formation layer, which is supported by end-to-end workflows in a digital environment to work out the accurate multilayer mapping around the wellbore while drilling. The technology has six transmitters with four receivers that operate at three frequencies, enabling complete geosteering multilayer mapping and formation evaluation. By delivering real-time ultra-high reso- lution, the service provides precise bound- ary and layer detection for better steer- ing direction in various reservoir types, including complex thinly bedded and compartmentalized reservoirs. Gamma ray, propagation resistivity and deep direc- tional resistivity measurements provide accurate input for formation evaluation while drilling, helping the operator place the well in the best part of the reservoir and extend reservoir exposure, ultimately improving production. The service reveals up to eight layers and provides mapping beyond a 25-ft radius, delivering accu- rate geosteering in reservoirs where mul- tiple thin layers could not previously be mapped. With remote capabilities, the service promotes a digital collaboration for faster decision making while navigating produc- tion zones within complex reservoirs. Case study: Australian operator drills long dual-lateral wells within very tight boundaries in unmapped formation Overview of the second dual-lateral well drilled with the multilayer mapping-while- drilling service. The upper lateral set several onshore records for the operator as the highest ERD-ratio well and the longest onshore lateral length from heel to toe (2,300 m). It was also the longest lateral drilled in Bowen Basin, Australia. As coal-seam gas (CSG) production con- tinues to increase in Eastern Australia, conventional CSG development methods present multiple geosteering and drilling challenges. A common concept for CSG development includes drilling surface-to- inseam (SIS) wells, but this process con- sists of drilling horizontal multilaterals to intercept a vertical well and often requires multiple attempts. The horizontal laterals stay in seam to maximize coal-seam expo- sure. After drilling, water is pumped out of the intercept well, causing gas to come out after the pressure has been reduced. The thin, 1–2-m seams create steering chal- lenges, especially when drillers use low- end reactive geosteering tools. Structural D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 27 I N NOVATI N G WH I LE DR I LLI N G The multilayer mapping-while-drilling service doubles the depth of detection range compared with conventional bed boundary mapping technology. The service detected coal from 4 m away when drilling in the interburden and simultaneously mapped the top and the base of the seam . complexities including faults, fractures and coal splits are often not characterized by seismic data, resulting in sidetracks that are especially challenging in coal. Wellbore stability also becomes a chal- lenge when the hole is open a long time for drilling, logging and multiple trips. Drillers must use measurements obtained by crossing the litho-boundary, which requires reactive steering. In a geologically complex reservoir in southwest Queensland, Australia, an operator faced these and other unique challenges for developing a CSG reser- voir. The target formation was at the base of a mountain, and because of restricted mountain access, no seismic shooting was allowed. The operator planned to drill pilot holes for each dual lateral, but this did not miti- gate risks linked with faults and structural uncertainties. The restricted access also prevented the company from drilling a vertical intercept well. Instead, the project required drilling a deviated intercept well and intercepting the deviated wells from both horizontal laterals. The operator had an objective to drill dual-lateral wells at least 1,000 m within the seam boundaries, where there existed a possibility of encountering faults with unknown throws. The previous conven- 28 tional approach the operator used in the area consisted of bottomhole assembly (BHA) components including a motor, a bed boundary mapping service, and an integrated measurement-while-drilling (MWD) platform. However, the conven- tional reservoir mapping-while-drilling technology had a limited depth of inves- tigation of 2–3 m and only mapped one boundary most of the time. Because the area lacked existing wells, the technology limited value for landing and exploring the area. To improve the depth of detection, the operator used a BHA that included the multilayer mapping-while-drilling ser- vice, which detected coal from 4 m away when drilling in the interburden and simultaneously mapped the top and the base of the seam. The BHA also included the ShortPulse integrated MWD platform, which provided direction and inclination and gamma ray measurements, and the PowerDrive Orbit rotary steerable system, which provided near-bit gamma ray, incli- nation and azimuth. As a result, the operator achieved the objective of drilling a first dual-lateral well in seam without wellbore stability issues. The technology enabled the operator to navigate back to seams despite several encountered faults. The laterals were 2,200 m long, and the wells landed at 829.5 m and 988 m in seam. The operator inter- cepted the deviated well successfully in one attempt and ran completions without issues. In the second dual-lateral well, the oper- ator set the company’s onshore records for the highest extended-reach drilling (ERD) ratio and the longest lateral length from heel to toe. The technology also enabled the operator to drill the longest lateral in the Bowen Basin. The multilayer map- ping-while-drilling service helped gather information farther out than originally planned, giving insight for exploring a complex area where doing so was previ- ously considered impossible. By improving detection range and reso- lution, the service enabled the operator to efficiently develop the challenging CSG field. Continuous improvements enabled the company to drive down the cost per foot, contributing to significant savings. Overall, the operator improved footage drilled per day by 80% and reduced cost per foot by 31%. As CSG continues to be a significant part of the Australian gas industry, the successful operation pres- ents opportunities for drilling laterals in seam and improving structure mapping and geosteering in CSG fields. Case study: Doubling the detection range offshore China An operator drilling two wells in the Chenghai Block in Bohai Bay, China, faced challenges where development wells shift from targeting the center of the sand body to the end. In two previous wells, because of large sedimentary changes and sand body discontinuities, the net-to-gross (NTG) ratios were lower than expected. The average thickness of the sand bod- ies is approximately 8 m. With previous technology, the depth of investigation was around 2-3 m, making clear depiction of the whole sand body difficult. The rapidly changing reservoir structure made geo- steering and staying within the sand body more challenging. Using the multilayer mapping-while- drilling service, the operator increased the depth of investigation to 6 m, doubling the detection range in the field compared with previous-generation technology. The tool mapped the whole sand body, increased M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G reservoir understanding, and enabled the operator to make informed decisions for maximizing the NTG ratio for each well, thus improving the productivity of the wells. By providing higher-resolution mapping, the service revealed the internal layering and quality variation within the reservoir, optimizing the well path and production. The PowerDrive Archer high build rate RSS enabled the operator to effectively steer the horizontal section of the wells to handle the abrupt structure changes and target multiple sand bodies in one well. The operator used the multilayer map- ping-while-drilling service in well A to map the top of the target sand 2.1 m away and the base of the target sand 5.2 m away as soon as it came out of the casing shoe. The service mapped the top and the base of the sand body throughout the section, clearly showing the pinchout of the sand body. The well was drilled for 256 m inside the sand body, with 50 m/hr average ROP while achieving 100% NTG. Well B was drilled in an area lack- ing control wells, causing uncertainties about the thickness and dip of the reser- voir structure. At 2,960-m MD, the service mapped the abrupt upward dip change of the base of the current sand body, enabling the operator to build inclination of the well path and avoid drilling out of the current good-quality sand. At 3,030-m MD, the ser- vice mapped the top of the sand body and a poor-quality layer at the upper part of the The multilayer mapping-while-drilling service mapped the top and the base of a sand body in China, clearly showing the pinchout. The well was drilled for 256 m inside the sand body, with 50 m/hr average ROP while achieving 100% NTG. reservoir. The geosteering team dropped the inclination and avoided drilling into the poor-quality zone at the top. At 3,123-m MD, the service inversion showed that the formation dip changed from 0.5° down- ward to 8.5° upward. The operator called for total depth (TD) based on this informa- tion. For this well, the team achieved a 91.5% NTG ratio, drilling 215 m in sand for the total horizontal section of 235 m. Conclusion The ability to double the depth of detec- tion range compared with previous bed boundary detection services has helped operators deliver clearer boundary delin- eation, enabling more precise real-time steering and faster turnaround time. By landing the well more precisely, operators can avoid drilling out to nonproductive sand and reduce costs and risks associ- ated with drilling in complex formations. Since deployment, the multilayer map- ping-while-drilling service has drilled and steered more than 700,000 ft in over 200 runs and 10,000 operating hours. In addi- tion to Australia and China, it has helped operators in the United States, South America and the Middle East place the well in the best part of the reservoir, lead- ing to improved production, reduced cost and risk, and consistent performance. DC PeriScope Edge, ShortPulse, PowerDrive Orbit and PowerDrive Archer are marks of Schlumberger. The service mapped the abrupt upward dip change of the base of the current sand body, enabling the operator to build inclination of the well path and avoid drilling out of the current good-quality sand. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 29 IMPROVING FRACKING POWER & EFFICIENCY Power quest: Innovations in frac equipment push horsepower boundaries As 5,000-hp becomes the norm, manufacturers focus on delivering pumps and engines with higher power density, durability BY STEPHEN WHITFIELD, ASSOCIATE EDITOR I n US unconventionals, pressures to reduce well costs while maintaining or improving production remain high. In the frac sector, pressure pumpers and engine manufacturers real- ize that they must design more durable and higher-horsepower systems, even as the definition of “high horsepower” continues to change. Manufacturers of frac pumps and engines are now mov- ing past 2,500 and 3,000 hp, and 5,000-hp pumps are becoming the norm. These new systems allow for increases in power density – meaning that they can maintain the same level of power, or Highlights To run frac operations longer without straining equipment, demand for horsepower is moving past 2,500-3,000 hp into the 5,000-hp realm. Combining battery systems with natural gas gensets, along with an automated microgrid controller, can increase load capacity while optimizing fuel consumption. New equipment coating, longer pump stroke lengths, modular, simpler and multimotor designs, and curved power frames are among new equipment features. 30 increase power as needed, within a smaller physical footprint. A high-horsepower system also allows operators and directional drillers to run frac operations for longer continuous periods, with- out maxing out on capacity and straining their equipment. “Companies want the most reliable fleets in the industry. Even if they’re looking to run a lower-horsepower operation, they still want the 5,000 horsepower because they know that thing is designed to run well above what they want,” said Turner Hall, Engineering Manager – New Product Development at GD Energy Products. “It’s all about extending the life of a system well beyond what a traditional 2,500- or 3,000-horsepower system can do.” Manufacturers are also touting that their high-horsepower systems can reduce fuel consumption, lower maintenance costs and enable longer continuous runtimes. Such benefits are key as operators stay focused on capital discipline. “In the past, when the industry ran on higher margins, we weren’t forced to be efficient. Customers weren’t talking about running our engines at their most efficient point,” said Scott Woodruff, VP of the Oil & Gas/Mining Business at Rolls-Royce Power Systems. “But especially since this last downturn, well services companies and drillers have become super focused on being efficient. We want to get the most work out of each stage fracked as we possibly can.” Designing the 5,000-hp pump GD Energy Products entered the high-horsepower space in 2019 with its first 5,000-hp pump, the Thunder 5000 HP Quintuplex frac pump. It can cut the size of a frac spread by 30% compared with a 3,000-hp pump, according to the company. With fewer pumps, transmissions and engines to maintain, the system also reduces M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R IMPROVING FRACKING POWER & EFFICIENCY The Thunder 5000 HP Quintuplex Pump, the first 5,000-hp offering from GD Energy Products, can reduce the size of a frac spread by 30% compared with a 3,000-hp pump. To compensate for the increased stress that a 5,000-hp pump places on its components, the design features a longer stroke length and a harder lubricant to reduce scuffing and friction. potential points of failure at the frac site, minimizing the need for maintenance. “Your power density is greater when you run one 5,000-hp pump versus two 2,500-hp pumps,” Mr Hall said. “Instead of needing 12 pumps on location, you only need six. That gets you efficiencies from a manpower and a safety standpoint. You have fewer pumps operating over a smaller area, so you’ve got less of a chance for issues to pop up.” A 5,000-hp pump can also generate higher flow rates at equiva- lent pressures to a lower-horsepower pump, helping companies boost production without increasing run time. Whereas running a 3,000-hp pump at 12,000 psi will get you approximately 9.2 bbl/ min, Mr Hall explained, running a 5,000-hp pump at the same pressure will get you 15.3 bbl/min. One of the bigger challenges in operating a 5,000-hp pump is the potential for increased stress on the pump’s components. Mr Hall estimated that a typical 5,000-hp pump “essentially cuts in half” the life of its components when operating continuously at maximum capacity. With that in mind, GD Energy Products pri- oritized durability in the design of the Thunder 5000 to ensure it can have the same uptime as a lower-horsepower pump. To reduce scuffing, friction and adhesive wear, the company developed a proprietary dry-film lubricant. The corrosion-resis- tant coating is harder and denser than the base steel used to build the frame of the pump, so it increases the load-bearing capacity of the bearings. The lubricant also helps prevent the pump from overheating when it operates at a higher horsepower. “When you’re going to a higher horsepower, it’s not necessarily just the stress of the components that you have to deal with but also the speed at which that pump is turning,” Mr Hall said. “At 5,000 horsepower, that pump is spinning faster than it tradition- ally has before, so you run the risk of a lot of heat generation. That has a big impact on pump performance. It was important for us to redesign our lubrication system so that we could pull that extra heat that’s generated by the faster speeds out of the pump.” The pump also features an 11-in. stroke length – the distance traveled by each piston in an pump cycle – which is 3 in. longer than the typical stroke length for a frac pump. The longer stroke length enables frac fleets to extend consum- able life while delivering the same horsepower, pressures and flow rates but at slower speeds. While a shorter stroke length enables a pump to accelerate to full power faster, it also shortens the life of the pistons, increasing the need for maintenance. Moreover, the new pump provides 37% more flow rate capacity than a typical 8-in. stroke pump, which keeps both the pump’s velocity and pump speed lower. This, in turn, slows the accumu- lation of fatigue and consumable cycles, extending the life of the pump and consumable components while outputting more vol- ume per revolution, according to GD Energy Products. “Essentially, this gets back to the total cost of ownership,” Mr Hall said. “Where D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 31 IMPROVING FRACKING POWER & EFFICIENCY Rolls-Royce Power Solutions’ MTU hybrid e-frac system features a modular design. Users can customize the system with any combination of the company’s battery storage systems and natural gas generators to suit the specific power needs of a frac operation. The battery systems also feature a proprietary microgrid controller, which automates the coordination of energy storage and demand between the battery system and the generators. the savings really comes from is on the consumable in the fluid end. I’m getting 37% more work out of the 11-in. stroke than I am out of the 8-in. stroke.” During validation testing in 2019, the pump was subjected to a 2 million cycle endurance test at a 250,000-lb rod load for the entire test. After 450 hours of testing, the pump exhibited no cracks in the frame, no bearing failures and minimal damage to the cross- heads and general bearings. The pump is now commercially deployed in several basins across North America. Hybrid e-frac systems Rolls-Royce Power Solutions, through its MTU brand of power systems, launched its hybrid electric fracturing (e-frac) power solution in 2021. It integrates a natural gas reciprocating engine with a battery energy storage system. Compared with a conven- tional turbine e-frac setup, this hybrid system can tailor opera- tional needs based on the load requirements of a specific opera- tion, allowing power to be utilized more efficiently. The system was also designed to be modular. Users can cus- tomize the system to generate as much, or as little, power as they 32 need. Any combination of MTU’s EnergyPack battery storage systems – which range in capacities from 70 kWh to 2,200 kWh – and natural gas generator set can be mixed and matched. Last year, Rolls-Royce used simulation software to highlight the potential energy efficiencies possible with its hybrid e-frac setup versus a turbine e-frac setup. The company simulated a frac operation using a turbine setup with a baseline load of 18-20 Megawatts electric (MWe) and a peak demand of 20-21 MWe. It then simulated the same operation with a hybrid system using 10 2.5-MWe gas gensets and two 2-MWe battery energy storage systems. The conventional e-frac setup with one gas turbine generator was only able to run between 50% and 65% load capacity during the simulated operation. On the other hand, the hybrid e-frac sys- tem was able to run at 80% capacity without needing to use all 10 gensets – eight gensets ran throughout the simulation while two served as backups. One of the keys to this increase in load capacity was the com- pany’s proprietary microgrid controller, which is installed in the battery energy storage system. Microgrids are small-scale local M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R IMPROVING FRACKING POWER & EFFICIENCY Above: To improve system durability, Liberty’s digiFrac elec- tric pump features a power frame with a curved internal ge- ometry that the company believes will improve laminar flow and reduce the risk of cavitation. Right: Liberty plans to commercially launch its digiFrac sys- tem later this year. The company believes the new technol- ogy can produce twice as much horsepower per unit as a conventional pressure pump, even as its multimotor design allows each motor to run at a lower horsepower. power networks in which various energy sources and storage systems are managed automatically through a master controller. The MTU microgrid automates the coordination of energy stor- age and demand between the battery system and the generators in the hybrid e-frac system, turning them on and off as needed to optimize fuel efficiency and emissions. “Getting the engine to its optimal range is pretty simple with the energy storage. We’re able to move the engine up to a more efficient load management situation – when you’re going from 50% to 80%, you’re generating more work per gallon of fuel from that engine,” Mr Woodruff said. He called the microgrid/EnergyPack combination a “whole new technology platform” in the e-frac space. Beyond the batteries, an EnergyPack houses an electronic control unit, transformers and cooling equipment, making it a self-contained energy storage unit. By connecting its control system to the MTU microgrid, users can ensure a continuous and efficient distribution of power throughout a frac run. “The automation feature helps us optimize fuel consumption, and that has other benefits when it comes to emissions and asset utilization,” Mr Woodruff said. “We’re creating a system where Click here to watch a video interview with Scott Woodruff about Rolls-Royce Power Solutions’ MTU e-frac. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 33 IMPROVING FRACKING POWER & EFFICIENCY Field trials demonstrate e-frac efficiencies STEPHEN WHITFIELD, ASSOCIATE EDITOR Last year, NOV conducted an eight-month field trial of its Ideal electric fracturing (e-frac) technology across several reservoirs in Texas and New Mexico. The tests, completed in collaboration with NexTier Oilfield Solutions, focused on measuring the efficiency gains that can be generated by using an e-frac system. The tests also aimed to demonstrate that the Ideal technology can help operators maintain high- horsepower operations without putting excessive strain on the frac motor. “What we wanted to focus on was, how do we harness the electrical capability in the e-frac system to drive better fracturing performance, lower NPT and improve efficiency on location?” said Travis Bolt, Product Development Manager and Head of R&D for Pressure Pumping Equipment at NOV. “The cost of fracturing continues to be high. We’re seeing an increase in complexity around frac operations. We’re all con- verging on that question of, what’s the next step for fracturing equipment?” At the 2022 SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, on 3 February, Mr Bolt discussed both the general efficiencies that can be realized from an e-frac system, which uses a natural gas reciprocating engine as its primary power source, as well as more specific field testing results for the Ideal system. Control of equipment to improve reliability was a major focus of the field testing. This primarily involved examining the turndown ratios of the motors, or the ratio of a motor’s speed relative to the base speed at which it can be operated safely at 100% torque without suffering thermal damage. An e-frac system typically has a 100:1 turndown ratio, meaning that it can operate safely at 100% torque while running at 1% of its base speed. As an example, Mr Bolt noted that for an e-frac system nominally rated to run at 1,800 rev/min, a 100:1 turn- down ratio means that the engine can operate safely at 100% torque while running at 18 rev/min. This ability to generate torque at low motor speeds means that operators can more easily apply torque in a controlled Continued on page 35 At the 2022 SPE Hydraulic Fracturing Technical Con- ference on 3 February, NOV’s Travis Bolt discussed the efficiency gains that were seen during field trials conducted last year of the company’s e-frac system. 34 we have much more visibility to steer these efficiencies even further.” Electric frac pumps Later this year, Liberty expects to commercially launch a new electric pump system featuring a multimotor design. The compa- ny says the digiFrac system will have twice as much horsepower per unit than conventional pressure-pumping technologies. The system’s power frame is flanked on either side by a pod housing five individual electric motors, each of which can generate up to 400 hp continuously or 550 hp at peak. This design eliminates the transmission, drive shaft and pinion found in conventional diesel frac systems and replaces it with a planetary gear system. The planetary system utilizes a center gear – known as a sun gear – that serves as the driver of the system. Three exterior gears – referred to as planets – rotate around the sun gear. Because the planet gears are evenly distributed around the sun gear, the system provides higher torque compared with the standard trans- mission used in a diesel frac system. Removing the transmission from digiFrac is an example of improving efficiency at the margins, said Ron Gusek, President of Liberty. Shifting gears under load using a standard transmis- sion introduces stress at potential failure points in a conventional frac pump, increasing the need for maintenance and decreasing runtime. “If you’ve ever driven a car with a manual transmission, shifting gears can be a little clunky. Every time you have to shift gears, there’s a little shock to the system, and that vibration can be hard on components,” Mr Gusek said. “When we’re changing gears on a frac pump, it’s no different. With an electric pump, we have a smooth system where it’s quite literally turning a dial to ramp up the speed of the pump.” With the 10 motors working in unison, each pump will pro- duce up to 4,000 hp continuously, or 5,500 hp intermittently. This allows operators to remove up to 50% of their pumping trailers per application. Combining this level of output with tight packaging, which is enabled by removing the transmission, provides substantial power density on the well pad. The result is high horsepower delivered within a small physical footprint. “If you look at a traditional frac pump, you would see the radiator system at the front of the trailer, then a 12-cylinder diesel engine, then the transmission, and then the pump at the very back. That entire assembly is around 45 feet long,” Mr Gusek explained. “If you look at digiFrac, all you have are a pump and the electric motors attached to the sides of that pump. The foot- print for that 5,500-horsepower pump takes up a space of 8 by 13 feet.” The footprint to deliver double the horsepower is effectively halved, he added. Additionally, with 10 motors operating individually at a lower horsepower, the digiFrac system is better suited to maintain con- tinuous high horsepower throughout a run, even in the event of an equipment failure. “If you have one large motor running and something happens to that motor, you’re out an entire piece of equipment,” Mr Gusek said. “But if we have 10 small motors and something happens to one motor? No problem. We still have nine more motors. That’s M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R IMPROVING FRACKING POWER & EFFICIENCY part of our whole design philosophy: What can we do to maximize our equipment hours as much as possible with as minimum an amount of maintenance as possible?” To improve system durability, the power frame was designed with an internal geometry that improves its resistance to flex and wear. Instead of creating a bore that is full of straight lines, Liberty designed it with curves from top to bottom and front to back to make the flow laminar and reduce the chance of cavitation. Cavitation occurs when small, liquid-free bubbles form within the liquid in low-pressure areas. When the pressure increases, the bubbles collapse and generate shock waves that gradually wear out the pump. The digiFrac system will utilize Rolls Royce’s MTU 2.6-MWe gas generator sets as its primary power source, effectively creat- ing a hybrid system. This will allow for emissions reductions – an estimated 25% in CO2 emissions compared with other off- grid power sources – due to the gensets’ high thermal efficiency, which helps reduce fuel usage. “Rolls-Royce has done a lot of work with us to understand how much fuel we were going to be consuming and how that would affect the performance of the engine,” Mr Gusek said. “If we’re going to deliver an electric frac fleet to a location for our customer, we have to be confident that we’re going to dramatically reduce the emissions footprint over the best available technology. Gas turbines are great at delivering a huge amount of power into a small pack- age, but the natural gas engine offers that opportunity of delivering an efficient footprint that is better than the best available.” Through a comprehensive testing program that included dura- bility testing and four field trials completed in Q2-Q3 2021, the system registered approximately 1,500 hours of operation in the yard and on four pads – two in the Permian Basin and two in the Denver-Julesburg Basin. While Liberty has not released details from those field tests, it said results “affirmed confidence for com- mercial production.” In its Q3 2021 earnings call, Liberty had announced multi-year agreements to commercially deploy the digiFrac technology in 2022 with two of its field-trial partners. Then, in the most recent earnings call on 9 February, the company said it plans to start deploying digiFrac pump systems into its frac fleets in early Q2 this year. DC Click here to watch a video interview with Turner Hall about GD Energy Products’ Thunder 5000 HP pump. Continued from page 34 manner, progressively increasing it over a period of time instead of applying maximum torque all at once, which could place unnecessary stress on the motor and pump. It also allows users to increase pressure from the frac pump without overstressing the system. The ability to apply torque in a controlled manner, com- bined with an electric motor’s ability to generate torque values greater than 100% for short periods of time, can help minimize the need for manual intervention on downhole issues. To dem- onstrate this capability with the Ideal system, one of the tests during the field trials focused on stuck augers. A 12-in. auger was run on a 45° angle with both the e-frac and a conventional frac system. Support testing prior to the field test showed that the motor required between 225% and 275% torque to break the auger free without manual intervention. Testers applied torque progressively to the e-frac system, reaching 260% torque in 3s. As a conventional diesel frac sys- tem is unable to attain that level of torque, manual intervention is typically required when the auger becomes stuck. By providing the ability to address a downhole issue without stopping operations, “we’ve prevented a person from having to go out into the field and manually interact with a piece of equipment,” Mr Bolt said. Another focus area of the testing was the process of con- verting raw fuel into energy applied at the wellhead, and its impact on horsepower and engine efficiency, defined as the ratio of work performed to the heat provided by an engine. Electricity is subject to the Joule effect and magnetic losses as it’s transported within a conventional system. These losses can account for up to a 2.5% loss in overhead line transmission. Another loss in the electrical system is the inefficiency of the step-up and step-down transformer, which typically ranges from 1% to 2%. An e-frac system can mitigate the losses typically seen in a conventional system, primarily because it consumes the same amount of power as it generates, Mr Bolt said. NOV and NexTier found that an e-frac system powered by natural gas internal combustion generators can achieve a 4% increase in efficiency over conventional systems. “With mechanical systems, we have to worry about the ini- tial energy conversion process of diesel fuel into mechanical energy through a transmission, or through a pump,” Mr Bolt said. “Typically, you have inefficiency at the generator source. You lose energy at the transmission due to magnetic losses, and then you have more inefficiency when you drop down in torque. But when we looked at the data from our tests, what we found was that, due to the initial efficiency gains that you have with natural gas-powered systems, we’re seeing an increase in efficiency versus a conventional system. In the world of efficiencies, a 3-4% increase is a big deal.” NOV and NexTier have said they expect to deploy the Ideal fleet in the first half of 2022. DC D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 35 IMPROVING FRACKING POWER & EFFICIENCY Automated predictive frac control system taps operator’s machine-learning model to improve completion execution Hess, Halliburton partner on Bakken pilot pairing automation with a predictive model to optimize for new surface efficiencies BY JESSICA WHITESIDE, CONTRIBUTOR The technology behind what Hess called a “push-button frac” pilot is complex – com- bining automated hydraulic fracturing with predictive machine learning – but the potential payoff is as simple as it gets: a faster frac with better economics. “What we are using this specific model for is surface efficiency optimiza- tion. Overall, we want to reduce time and material costs,” said Erin Butler, Senior Specialist Engineer for Hess, which con- ducted a pilot in the Bakken in partnership with Halliburton in 2021. The project demonstrated the ability to upgrade completion performance with minimal human intervention by using the operator’s machine-learning model to accept data from, and provide tailored frac design guidance to, the service provider’s automated fracking system. In a presentation at the SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, on 2 February, the proj- ect team described the venture as “the first time a hydraulic fracture was conducted via automation with algorithmic integrat- ed design improvement.” According to Ms Butler, the successful pilot provides “the groundwork for opera- tors and service companies to progress toward automation of hydraulic fracturing operations” and make further step-change improvements in frac design and execu- tion. “The overall vision of automation in hydraulic fracturing isn’t going to be tack- led in one fell swoop,” she said. “It’s going 36 to take small incremental steps to get there and really capture value from automation.” Removing human bias Traditionally, decisions to modify frac design during a job are made by engi- neers or supervisors on location. However, this can lead to inconsistent execution because, in addition to subsurface hetero- geneity, these decisions are influenced by variability in the experiences and capabili- ties of the individuals and crews involved. It can also be challenging for these profes- sionals to gain approval for modifications in a timely manner, leading to missed optimization opportunities. Pairing automation with machine-learn- ing models that can run 24/7 and process more data more quickly than possible for a human could avoid some of these pitfalls. “Automating hydraulic fracturing pro- cesses can add value by driving consis- tency, removing human bias, reducing our EHS risk, eliminating waste and even enhancing our well performance,” Ms Butler said. Automation and digital workflows are still relatively new to hydraulic fractur- ing, with testing of automated equip- ment beginning in the initial breakdown stage of completions in 2016. By 2020, Halliburton had introduced an automated fracturing system that the company says is capable of running completions from beginning to end. The system is described as a “co-pilot” that uses subsurface sen- sors, 3D visualization and other features to provide operators with greater control over fracture placement through “intel- ligent automation.” The system provides real-time diagnostic insights into factors such as pressure, rate and proppant con- centration and enables automatic changes to fracking equipment, such as the blender and hydraulic pumps. What Hess wanted to determine through the 2021 pilot, however, was whether the Halliburton system could be configured to accept inputs and direction remotely from an external source – a machine-learning model developed by Hess that would ana- lyze both historical and real-time data from the job. The model is designed to assess pump curve characteristics and make on-the-fly recommendations for design changes to improve the frac based on specific optimization targets (e.g., reduce time or execution cost, maximize rate, etc). The model would then need to communicate these changes directly to the intelligent automation system for execution. Hess trained its optimizer model on a data set of more than 150 Bakken wells. The model retrains itself with real-time data it receives during the completions process, improving its performance and prediction accuracy as the frac progresses. With this model, Ms Butler said, you can better capture why and when a decision was made and use that information in additional analytics. Developing data workflows The companies worked together to develop a data architecture that facili- tated the secure delivery of data between the operator’s model in the office and the service provider’s system at the frac site. The resulting automated process feeds the frac equipment with the updated design change recommendations from the machine-learning model at an agreed- upon frequency. “What we had to develop was a transla- tion on how to take this prediction table and put it into a format that was digestible by the intelligent fracturing service,” Ms Butler said. While the project team had intended for this process to happen autonomously, time constraints during the trial meant they weren’t able to get to the point where there M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R IMPROVING FRACKING POWER & EFFICIENCY was no human intervention to accept the model’s design suggestions. “What we did get to was that we were able to stream the model outputs to the user interface of the intelligent fracturing system so it was just a quick acceptance and a copy-paste to the blender outputs,” Ms Butler said. Future iterations of the technology will remove that human step to enable seamless, closed-loop communi- cation between the operator and service- provider systems. To ensure that the optimizer model was functioning correctly, the pilot required human oversight of the design change protocols recommended by the model. This oversight involved a sign-off from the field supervisor and the engineer, who con- ducted a “final check that we were adher- ing to our boundary conditions and that there was no outlandish suggestion by the model,” Ms Butler said. “Then we gave the nod to the operator to adopt these model changes.” Such manual requirements would be phased out in future iterations following further vetting of the data archi- tecture and boundary condition adherence. Because the project used a joint service company-operator data stream, an impor- tant feature of the data architecture was the ability for both parties to maintain the security of their respective networks. “Integration of the operator’s model with the service company’s automation- enabling equipment was developed with- out risk to either party in terms of security or the loss of intellectual property, provid- ing mutual benefit,” Ms Butler said. Proving the technology The 2021 pilot took place on a four-well pad operated by Hess in the Bakken. For the first two wells, the team tested only the functionality of the Halliburton automated fracking system, without activating the machine-learning model. The automat- ed system successfully and consistently placed the Hess fracs. For the second two wells, tested in July 2021, the team brought the integrated machine-learning model into play and met the project’s goals of ensuring that the intelligent fracturing system received the model’s outputs at the designated fre- quency and under established boundary conditions. They also met another key A pilot project conducted last year in the Bakken used the operator’s machine- learning model to provide tailored frac design guidance to the service provider’s automated fracking system. Erin Butler, Senior Specialist Engineer for Hess, discussed the project in a presentation at the SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, on 2 February. goal: to avoid any downtime associated with the modeling process and acceptance of design changes. A secondary goal of the pilot project was to better understand the machine-learning model’s performance and how it achieved the optimization targets. That analysis is now under way, Ms Butler said. “Right now, we are investigating a few hypotheses that we have for why the model is behaving in the ways it did, and then we would like to take steps to fine- tune this optimization tool – the run times, the frequencies, the methodology – to best achieve our operational efficiency targets.” Change, she added, is the only constant when it comes to developing automation. “Things that work well are going to stick, and things that don’t work well we need to learn from quickly and move on to our next task.” She noted that there is no set meth- odology for hydraulic fracturing automa- tion, and different operators pursuing the vision of a push-button frac might order their processes or data flows differently depending on their value drivers. However, she advised that necessary capabilities should include digital workflows, real- time data aggregation, edge devices and cloud computing, machine learning and artificial intelligence tool development, AI-enabled equipment controls and an integrated operations center. Efficiencies like those emerging from this pilot align with Hess’ strategy for gen- erating cash flow from its Bakken assets, which remain a critical component of its portfolio. Hess produced approximately 155 MBOED from its Bakken assets in 2021, and its 2022 production budget includes $790 million to fund a three-rig program in the Bakken. With those funds, the com- pany expects to drill approximately 85 gross-operated wells and bring online approximately 85 wells this year. DC D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 37 IMPROVING FRACKING POWER & EFFICIENCY Integrated platform aims to improve real-time decision making in frac operations Technology gives engineers actionable insights for optimization while aiming for balance between frac efficiency and effectiveness BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Recent breakthroughs in connectivity and digital technologies are enabling the mon- itoring and analyses of hydraulic frac- turing operations in real time through data streaming and analytics. While most third-party frac monitoring solutions offer things like real-time frac treatment data charts, post-stage frac analytics and key operational efficiency metrics , there was still a need for software that could identify opportunities for frac optimization in real time , augmenting and improving real-time decision making at the frac site. At the 2022 SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, on 2 February, Shell presented a software platform it developed to host and execute an ensemble of third-party frac models and visualizations. It com- municates actionable insights within minutes of identifying a potential event during a frac stage. The platform is a plug- Somnath Mondal, Research Production Technologist at Shell, discussed a software platform for frac optimization at the 2022 SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, on 2 February. The platform makes use of third-party analytics to interpret data about ongoing frac operations and provide actionable insights for on-site engineers. 38 and-play system, where users can insert and remove third-party models measur- ing different variables at a frac site, said Somnath Mondal, Research Production Technologist at Shell. “Everyone wants to pump the best frac that we can at every stage, but a good frac is not just about pumping away a given volume of water or sand at the lowest cost, but also to get effective stimulation distribution. We’re trying to get a balance of efficiency and effectiveness at every stage,” Dr Mondal said. “We’ve made a tremendous amount of progress in getting real-time data acquisition and running analytics on it, but most market solutions are still not there.” The platform is based on a fairly sim- ple framework: Real-time sensor data is fed into software for processing and then transferred into third-party models for visualization. To limit the number of vari- ables during lab testing and initial field testing, only models for measuring injec- tion rate and sand concentration were used. However, Dr Mondal said multiple models can be executed simultaneously within the platform. Users can even estab- lish a hierarchical optimization for the whole system based on priority. The platform identifies potential oper- ating states for optimization by taking the output from the third-party models and running it through a separate model designed to predict a given action’s impact on pump pressure. This model looks for points where sufficient pressure head- room is available and the pressure trend is favorable, to ensure that any action taken would not increase the pressure outside an acceptable limit for the well. It then identifies the valid operating states that can result from a given change to different variables, and assigns a score. Another model utilizes historical data to estimate an action’s impact on the comple- tion time and simulates a stage under the assumption of pre-determined control variables. From that simulation, the plat- form can estimate the cost for each pos- sible operating state and recommend an operating state that is most optimal. The platform’s recommendations are stored in a data lake, and notifications are sent to engineers about potential events. The recommended actions are presented M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R IMPROVING FRACKING POWER & EFFICIENCY Top: This fl owchart illustrates the steps for optimizing a frac operation using Shell’s integrated platform . Bottom: A recommendation “card” displays the suggested change along with contextual information to assist engineers in real-time decision making . Additional details about the system are available in SPE 209127, “Effi ciency and Effectiveness – A Fine Balance: An Integrated System to Improve Deci- sions in Real-Time Hydraulic Fracturing Operations.” in the form of a “card” that can be dis- played on the user interface. This card includes the suggested change, as well as contextual information to assist engineers in decision making, such as average pres- sure, predicted pressure and estimated savings. While he did not provide exact figures, Dr Mondal said the estimated sav- ings is typically in the thousands of dollars per recommendation. The platform restricts the frequency of recommendations given within a particu- lar time frame, both to ensure engineers have time to implement the recommenda- tions already given and to see the response to any optimization action taken before a new one is generated. Dr Mondal stressed that the model is purely a recommendation tool. Engineers at the frac site must decide whether to implement the optimization action. “The idea here is not to replace the human. It’s to provide the human making the decision with the tools they need and the data they need to make the best decision without having to rely solely on experience or recall at a given moment,” he said. System limitations While specific results from initial field testing were not discussed, Dr Mondal said the software has consistently identified optimization opportunities and augment- ed decision making that led to cost sav- ings while preserving frac effectiveness. However, there are limitations. Frequently, the team saw scenarios during testing where the pressure became negatively correlated to the proppant or showed non- linear dynamics due to wellbore complexi- S tep 1 Identify potential operating states S tep 5 S tep 2 Generate Estimate optimization pressure response S tep 4 S tep 3 Calculate Select cost/time impact valid states ty. Since the pressure response model used in testing was a linear model, the system’s ability to predict effectively became lim- ited under those scenarios. When the team increased the prediction time frame from 1 minute to 3 minutes during these sce- narios, the model became insufficient at modeling the complexities of the system. To help remedy this issue, the team explored the possibility of incorporating a gradient boosting, or “learning tree,” model into the pressure response. In a gradi- ent boosting model, a base model trains additional models sequentially to try to reduce error. This model leverages histori- cal data and contextual data, such as stage depth. Shell structured the model to input all variables available at a given time and contextual information about the well and stage, such as the depth or formation type. This model showed impressive predic- tive power, Dr Mondal said, as it was able to predict the pressure response up to 3 minutes ahead of an event with reasonable accuracy. However, like with the linear model, this model struggled to accurately predict an event in the early ramp phase of the frac stage because there was too much variability. Shell is currently investigating how to integrate a gradient boosting model into the software platform, which is a challeng- ing task because a large gradient boosting model requires hosting a sizeable number of parameters associated with it. A host would also need to be developed that can cover all possible well types, which is an exhaustive process. “This model is computationally very heavy,” Dr Mondal said. “You have to keep an evergreen training set, which is very time consuming, and this set needs to con- stantly update the model. We are trying to keep a balance between the practical implementation challenges and having optimal model accuracy.” DC D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 39 D E PA R TM E NT S • H S E&T CO RN ER New study highlights impact of COVID-19 on mental health of offshore workers in Australia Employees cited lack of access to social support, difficulties getting to work and returning home, and higher workloads among key stress drivers BY STEPHEN WHITFIELD, ASSOCIATE EDITOR The impacts that the COVID-19 virus can have on people’s physical health have been obvious, but the pandemic’s impacts on people’s mental health – while less out- wardly obvious – are significant, as well. Offshore workers are no exception. In a recent study, the majority (64%) of offshore workers surveyed said they were experiencing either a moderate or high level of general psychological distress. Additionally, 13% reported very high or severe psychological distress, suggesting that they may be experiencing anxiety and/or depression. The report aims to provide insights to help organizations evolve the way they manage their offshore crews. It was com- missioned by Australia’s National Offshore Petroleum Safety and Environmental Agency (NOPSEMA), Offshore Alliance, and the Australian Petroleum Production and Exploration Association. Over the past two years, Australia has implemented stringent protocols, such as state border closures and self-isolation protocols, to try and contain the spread of COVID-19. From June to August 2021, researchers from Curtin University and the University of Western Australia gathered responses from 502 people working in Australia’s offshore oil and gas industry. Respondents answered questions about their mental health and wellbeing and provided details about influencing factors like their work schedules (roster), accommodations and travel arrangements. In their responses, workers specifically described feeling stress in relation to the uncertainty of getting to work on time, 40 returning home and whether a lockdown would happen while they were offshore. Survey participants described facing challenges such as a lack of access to social support, with some specifically cit- ing a lack of support from their employers. For instance, one respondent said “it’s been a constant battle to get living standards to an acceptable level.” Another worker noted that, due to state border closures, he had to live in temporary accommodations for much of his time off work over a 14-month period. In fact, he said he had only been back home once in that time frame. Nearly a third (32%) of respondents said they had encountered difficulties traveling home. Causes of distress The study also looked at the impact that different schedules had on workers’ men- tal health and wellbeing. While respon- dents reported 54 different schedules, six were found to be most common (Table 1). Comparisons of psychological distress across those six rosters showed no statis- tically significant differences. However, researchers did find the lowest wellbeing scores for the 21/28 schedule, although they couldn’t be sure why. Researchers also looked at the impact of other workplace factors. Of note, approxi- mately half of those surveyed said they had experienced work schedule changes since the start of the pandemic. Then, 60% of that half said there was little to no consultation, by employers with employ- ees, about those changes. This points to a “concerning” lack of clear communication by employers, researchers said. A total 63% of respondents also reported their company had seen staff reductions on offshore facilities since the pandemic began, and some noted longer working hours and an overall increase in workload and pressure. A large number of individual responses said they believe staff reductions and longer working hours are major drivers of psychological distress. Improving mental health To identify ways to help offshore work- ers improve mental health, the study also examined the connection of factors within family and social life, the worker’s job, his or her personal attributes, and the facility and organization for which they work. The study found that long and unpredictable work schedules, poor internet and communication facilities, and separation from family were factors strongly associated with negative mental health. Meanwhile, perceived line manager support, job satisfaction, satisfaction with food quality, regular communication with home, perceived priority given to mental health and wellbeing, and autonomy during the worker’s time off-shift were common factors protecting mental health. When asked to describe ideas for “quick wins” that would benefit mental health and wellbeing in the short term, they listed things like improved food quality; employers considering workers’ individual schedule preferences; boosting the quality of offshore internet/communication facilities; limiting room sharing offshore; increasing personal space on the facility; and providing recreation and leisure options to decompress after a shift. Researchers said a key message they want to emphasize is the need for “rela- tional repair” between offshore workers and employers. Sentiments reflected in the survey show that employers may have breached a “psychological contract” with their employees, or a set of unwritten mutual expectations characterized by respect, compassion, objectivity and trust. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R Scan me to access the full report on the NOPSEMA website. bit.ly/3prVo8v H S E&T CO RN ER • D E PA R TM E NT S To start on this relational repair, the researchers proposed five recommenda- tions. First, employers should make stron- ger efforts to provide social support to their workers. Social support, particularly from an organization’s leadership, is a key fac- tor for employees’ positive mental health and wellbeing. For example, employers could promote opportunities for workers to socially engage with one another while they’re on an offshore facility. Second, employers should support employees in their efforts to connect with families while offshore and to travel home when they’re off rotation. With some work- ers facing longer stretches of time between visits home, and in some instances having no possibility of getting home due to bor- der closures, workers reported a sense of struggle, stress and uncertainty. Attention to instances of poor internet and phone connections on site, and providing quick repairs, is also important so that workers feel better connected and can communi- cate daily with their families. DAYS ON DAYS OFF Schedule 1 14 14 Schedule 2 21 21 Schedule 3 28 28 Schedule 4 21 28 Schedule 5 28 56 Schedule 6 21 (1st hitch) / 28 (2nd hitch) 21 (1st hitch) / 35 (2nd hitch) Table 1: Among the six most commonly identifi ed rosters, researchers found the lowest wellbeing scores for the 21/28 schedule , although they couldn’t be sure why. Third, employers should give more con- sideration to the impact that workload, accommodations and COVID-19 proto- cols have on employees’ mental health. Researchers recommended that employers assess their employees’ current workload and pay more attention to accommodation factors, such as food quality and the avail- ability of social leisure options . Fourth, employers should communi- cate decisions with transparency. Finally, employers should engage their workers during the decision-making process. Not doing so can lead organizations to miss out on useful and important informa- tion, or more importantly, lead to workers feeling disengaged, undervalued and not respected. DC D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 41 IADC CONNECTION • EDITORIAL IADC, members keep focus on people, collaboration, industry value FROM THE PRESIDENT I believe in the long-term value of the oil and gas industry. This belief comes from the fact that energy directly impacts the goals of individuals, organizations and communities around the world. However, the industry is facing a number of obsta- cles, including those around regulatory and logistical constraints, market frag- mentation, and workforce recruitment and retention. While these near-term challeng- es are being addressed, it’s important to note that IADC and its members are also focused on the long game. Three primary thematic areas will help us stay the course in 2022 – collaboration, people, and indus- try value. Adapting to change through collaboration In his editorial in the last issue of this magazine, Jeremy Thigpen – IADC’s 2022 Chairman and CEO of Transocean – stressed the need for collaboration. “Our collective efforts can yield demonstrable results when we collaborate, share knowl- edge, tackle common problems and devel- op solutions to critical issues,” he stated. This is the idea behind IADC commit- tees – a pillar of the association through- out its 80-plus year existence. I’m proud to say that, not only did committee activity not cease during worldwide lockdowns , but the virtual aspect of committee meet- ings allowed new faces from around the world to start popping onto screens. We know the significant impact IADC com- mittees have made over the years, and we recognize the additional potential with increased access for all members. By pro- viding hybrid options for committee meet- ings, we will maximize members’ ability to collaborate and make an impact. 42 The past two years have taken their toll, but have also revealed inherent connec- tions within our industry. These connec- tions serve as a platform for broader and, in some cases, more non-traditional collabo- rations. A recent example is IADC’s recip- rocal membership with the International Petroleum Industry Environmental Conservation Association (IPIECA). With IADC’s growing sustainability efforts, this connection provides our members with the chance to align initiatives and col- laborate across upstream and downstream industries. IADC will continue to preserve existing connections in 2022 while also seeking new, non-traditional opportuni- ties to expand its network. Taking care of people In Mr Thigpen’s editorial, he also addressed the challenge of attracting tal- ent during this period of market recovery. “The opportunities for next-generation drilling professionals will be plentiful for those who are smart, ambitious and believe in the value this industry creates,” he said. IADC recognizes that the talent of tomorrow needs to be identified and nur- tured today. The energy and growth we’ve seen from our Young Professionals (YP) Committee and student chapters program signal that we are meeting an industry demand among its newest talent. Potential initiatives under consideration for YPs include a “Lunches with Leaders” series to facilitate cross-functional development and regional networking events where YP Committee members are based. Involving YPs and IADC student chapters in indus- try conferences, committee meetings and chapter activities creates additional oppor- tunities for engagement. If we nurture the best resource we have, they will be better informed and equipped to learn, lead and achieve future goals they have for them- selves and the industry. The challenge around people doesn’t stop there. Once they are in the industry, we must train and develop them in order to keep them in the industry. IADC has been accrediting training providers for decades, but offerings must adapt as the industry progresses. As such, we are developing new offerings in 2022 around H 2 S, ESG and IADC’s flagship WellSharp program. Jason McFarland, IADC President Demonstrating industry value with facts The fact is that hydrocarbon fuels solve a lot of problems for humanity. Mr Thigpen states that “one of the key chal- lenges we face is educating the public on hydrocarbons’ critical role within civiliza- tion – something we all take for granted.” Current conversation about the energy transition has a lot of the industry talking past each other. ESG is not a new paradigm, but the baselines and benchmarks are siloed among varying organizations in the energy, financial and regulatory sectors. The IADC Sustainability Committee will be stepping up efforts in this area, including addressing sustainability reporting guid- ance to help our industry be a resource as the slow, steady adoption of alternative energy sources continues. Additionally, the Energy Efficiency Subcommittee of the IADC Advanced Rig Technology Committee will offer opportunities for alignment on key topics between operators, drilling con- tractors, vendors and regulators. Whatever our goals are as individuals, as organizations or as communities big and small, there will be challenges and obsta- cles to overcome. As easy as it is for some consumers to flip a switch and access ener- gy, IADC members recognize that energy sources cannot be switched quite as easily. It will be a slow and gradual transition to alternative energy sources, and IADC and its members have an active role to play both during and after that transition. In a world where perception, at times, overshadows reality, the industry needs to stay focused, and IADC is committed to doing its part. I believe the key areas out- lined above will help the industry stay the course – something we must do to meet growing worldwide energy demand. DC M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R NEWS CUTTINGS • IADC CONNECTION IADC DrillingIN podcast highlights Well Integrity book In the first episode of IADC’s DrillingIN book review podcast, released 20 January, Fred Growcock, Chairman of the IADC Technical Publications Committee, spoke with author Les Skinner about “Well Integrity for Workovers and Recompletions.” Mr Skinner, Drilling and Operations Advisor at Eureka Energy Advisors, discussed some of the key content in the book, including insight into how to protect wells through the produc- tion, workover and recompletion cycle, from both an economic and a technical standpoint. The book outlines the steps needed to ensure that production wells can be reentered and modified to maximize pro- ductivity for long-term gain. Over the course of seven chapters and six appen- dices, it covers everything about the basics of well integrity, workovers and recompletions; recognition of symptoms and performance of diagnostic tests to determine well integrity and potential failure modes; and assess risk and eco- nomics. The book also features real-world examples, with quizzes at the end of each chapter. Click here to watch the DrillingIN video podcast in which Les Skinner (left) spoke with IADC Technical Publications Committee Chair Fred Growcock about Mr Skinner’s book, “Well Integrity for Workovers and Recompletions.” IADC, SPE student chapters hold joint CCUS workshop In late January, IADC and SPE stu- dent chapters at the University of North Dakota hosted a one-day workshop dedi- cated to discussing current initiatives and challenges related to carbon capture, utilization and storage (CCUS). More than 180 people attended the workshop. Topics discussed includ- ed subsurface geologic storage; CO 2 - enhanced hydrocarbon recovery; reser- voir monitoring and risk assessment; case studies; industry applications; economics, incentives and policy; infra- structure; and non-technical consider- ations. The student chapters hosted 12 talks, 10 speakers and 12 sessions at the work- shop, which gave participants a com- plete perspective on how, where and why CCUS could grow in the future. CCUS is an emerging field that involves the capture of CO 2 from fuel combustion or industrial processes, the transport of this CO 2 via ship or pipeline, and either its use to create valuable products or servic- es or its permanent storage underground in geological formations. Countries and industry leaders are actively supporting the R&D of CCUS technologies to achieve a goal of net-zero emissions. IADC committee, IPIECA engage on sustainability roadmap, reporting Isabel Miranda, Director of Sustainability and Social Performance at IPIECA, gave a guest presentation at a meeting of the IADC Sustainability Committee on 10 February. IPIECA, which IADC joined late last year, is a nonprofit association committed to improving the oil and gas industry’s ESG performance. Ms Miranda spoke about the group’s recent work in aligning industry stakeholders around sustainability. One recent initiative is the Sustainability Development Goals (SDGs) Roadmap, which IPIECA developed in collabora- tion with the World Business Council for Sustainable Development. The groups looked at the 17 United Nations SDGs and highlighted 10 where the oil and gas sector has the most influence by driving inno- vations. From there, the roadmap identi- fied eight “impact opportunities” under three themes: climate, nature and people. It outlines short-, medium- and long-term actions for IPIECA and the industry to maximize each opportunity, with a focus on scaling up good practices on climate action, environmental responsibility and social performance. Ms Miranda also presented updates to the Sustainability Reporting Guidance, which IPIECA published with API and the International Association of Oil & Gas Producers in 2020. Notably, a modular approach to reporting has been adopted: The guidance now includes 43 indicator categories, each with two revised tiers of reporting elements, core and addition- al. The updated guidance also has new “key points to address,” with practical rec- ommendations on developing a report’s narrative. The reporting of performance indicators related to climate change and industry has also been improved. The IPIECA Reporting Working Group has already begun new discussions and will likely begin formalizing additional updates toward the end of this year. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 Scan me to access the IADC Sustainability Committee webpage. bit.ly/37zvl62 43 IADC CONNECTION • WIRELINES IADC concerned over Bureau of Land Management’s missed Q1 lease sale deadline In an 18 February news release, IADC expressed its disappointment with the US Department of Interior (DOI) missing its 15 February deadline to schedule an onshore federal oil and gas lease sale for Q1 2022. Under the Mineral Leasing Act, the Bureau of Land Management (BLM) is required to hold federal onshore lease sales once per quarter and must provide at least a 45-day notice. Despite these well-defined requirements – as well as recent rulings in US federal court that further affirm these requirements – the Q1 deadline passed without a sale being scheduled. IADC remains deeply concerned that the DOI lacks a fundamental respect of the RRC launches database for flaring, venting applications The Texas Railroad Commission (RRC) launched a new online database of flar- ing and venting applications. The Flare/ Vent Exceptions Query is part of a years- long effort to improve public access to the RRC’s information. Updated nightly, the query makes available all applications for exception to Statewide Rule 32 (SWR 32) that have been filed electronically with the agency since 2 May 2021. SWR 32 specifies exempt and autho- rized flaring in which an operator can flare, including for safety reasons, without going through the application process to obtain an exception to the rule. Any other flaring request would go through the application for exception to the rule and be reviewed. The RRC published a new form, Form R-32, for operators to apply for an excep- tion to SWR 32. It provides specific guidance on when an exception to flare would be permissible, under which cir- cumstances and for how long. The online version of the form launched in May 2021. The RRC noted that less that 0.2% of natural gas produced in November was flared, which was a record low. Further, the amount of gas flared has been on a steady decline every month since June 2019. Scan me to access the Texas RRC Flare/Vent Exceptions Query. bit.ly/35FUVbv API appeals ruling invalidating 2021 federal lease sale In early February, the American Petroleum Institute (API) filed a notice of appeal with the US Court of Appeals for the DC Circuit of the decision by the DC District Court that invalidated the results of the only federal lease sale for natural gas and oil held in 2021. The sale generated more than $198 million in total bids, and the revenues received are directed to the US Treasury, state and local governments, the Land and Water Conservation Fund and the Historic Preservation Fund. “At a time of rising energy costs and heightened geopolitical tensions, the misguided decision to cancel the only lease sale held last year is contributing to significant uncertainty for US natu- ral gas and oil producers and limiting access to the affordable, reliable energy that’s needed here in the US and around 44 the world,” said Frank Macchiarola, API Senior Vice President for Policy, Economics and Regulatory Affairs. The notice also said the court’s ruling overlooked the comprehensive environ- mental analysis that the Bureau of Ocean and Energy Management had conducted as part of the National Environmental Policy Act process prior to the lease sale. API also cited a report issued in November 2016 by the US Bureau of Ocean Energy Management analyzing the effects of offshore leasing restric- tions, which found that US greenhouse gas emissions would be little affect- ed and could increase if more foreign imports are needed in the absence of new US offshore leasing and production. The report noted that increased produc- tion and transport of foreign oil would lead to higher greenhouse gas emissions. requirement to conduct federal lease sales in a timely manner. As the world faces growing energy demands and a rapid increase in fuel pric- es, the administration seems oblivious to the fact that holding regular federal lease sales is a tool the government can leverage to directly address those challenges. API comments on proposed EPA methane regulations On 31 January, the API submitted com- ments on the US Environmental Protection Agency’s (EPA) proposed methane regula- tions. The comments emphasized support for the direct regulation of methane for new and existing sources and highlighted the industry’s progress in reducing meth- ane emissions intensity from operations. The EPA has yet to publish the rule text for the proposed regulations, but the API based its comments on the preamble text and focused on the effectiveness of emission-reduction strategies, safety, fea- sibility, operability and cost. Where appro- priate, alternative approaches were recom- mended. The API also called on the EPA to publish the full text before setting the new source applicability date. DOE issues cyber notice amid Russia’s war in Ukraine On 23 February 2022, the US Department of Energy (DOE) issued a letter addressing increasing concerns for heightened cyber- security risks associated with the conflict in Eastern Europe. The DOE encourages organizations across the energy sector to evaluate their cybersecurity measures and implement a “shields up posture.” Organizations should: • Review the Cybersecurity and Infrastructure Security Agency’s “Shields Up” Guidance; • Verify or otherwise engage with one of the three energy Information Sharing and Analysis Centers (ISAC); • Ensure awareness, roles and responsi- bilities, and cross-functional processes for securing enterprise operations; and • Immediately report attempted or con- firmed cyber intrusions to ISAC points of contact and US government emergency response centers. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R UPCOMING IADC EVENTS • IADC CONNECTION Drilling Africa IADC IADC Drilling Onshore 2022 CONFERENCE & EXHIBITION CONFERENCE & EXHIBITION 19 MAY 2022 HYATT REGENCY HOUSTON WEST HOUSTON, TEXAS 31 MAY - 1 JUNE 2022 MÖVENPICK AMBASSADOR HOTEL ACCRA, GHANA IADC 9-10 JUNE 2022 RITZ CARLTON NEW ORLEANS, LOUISIANA International Tax SEMINAR SEMINAR World Drilling IADC 2022 CONFERENCE & EXHIBITION 21-22 JUNE 2022 PULLMAN TOUR EIFFEL HOTEL PARIS FRANCE IADC Advanced Rig Technology CONFERENCE & EXHIBITION Europe IADC HSE AND SUSTAINABILITY CO N FER EN CE & E XH I B ITI O N 30-31 AUGUST 2022 HYATT REGENCY AUSTIN HOTEL AUSTIN, TEXAS 14-15 SEPTEMBER 2022 APOLLO HOTEL AMSTERDAM, THE NETHERLANDS To register for these and other conferences please visit us online at www.iadc.org/conferences/upcoming. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 45 IADC CONNECTION • DRILLING CONTRACTOR DON’T MISS OUT ON OUR NEXT ISSUES! EDITORIAL PREVIEW OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS May/June WWW.DRILLINGCONTRACTOR.ORG WWW.IADC.ORG Bonus distribution: AD CLOSING: 4 APRIL MATERIALS DUE: 11 APRIL • OTC, 2-5 May, Houston, Texas • Unconventional Drilling: Equipment and Technologies for Next-level Performance • Offshore Technologies & Markets • Low-Carbon Drilling Solutions • IADC Drilling Onshore Conference, 19 May, Houston, Texas • IADC Drilling Africa Conference, 31 May – 1 June, Accra, Ghana • IADC World Drilling Conference, 21-22 June, Paris • Optimizing Well Intervention July/August Bonus distribution: AD CLOSING: 16 JUNE MATERIALS DUE: 23 JUNE • IADC Advanced Rig Technology Conference & Exhibition, 30-31 August, Austin, Texas • The Digital Transformation issue: • Applying Data Science in Drilling • Re-skilling Workers for Digital Workfl ows • Innovations from Tech Startups • Offshore Asset Integrity News Visit DrillingContractor.org for the latest drilling industry news and videos New research reveals cyber attackers are actively targeting OT/ICS environments ABSG Consulting has announced the results of a new survey from SANS Institute, “Threat-Informed Operational Technology Defense: Securing Data vs. Enabling Physics.” The ABS Group- sponsored research reveals that cyber attackers have demonstrated a robust... 46 ABS launches GHG Inventory and Carbon Accounting Service Neptune Energy aims for carbon negativity by 2030 ABS has launched Greenhouse Gas (GHG) Inventory and Carbon Accounting, enabling organizations to quantify their GHG emissions to understand their cli- mate impact and set goals to limit emis- sions, as well as define their footprint and contributions in Scope 1, 2 and 3 account- ing categories... Neptune Energy announced plans to store more carbon than is emitted from its operations and the use of its sold products by 2030. The company is currently progress- ing two carbon capture and storage (CCS) developments in the Dutch and UK sectors of the North Sea that could see... M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R PEOPLE, COMPANIES & PRODUCTS • DE PAR TM E NTS NOV acquires ADS to offer integrated MPD solutions NOV recently acquired the Advanced Drilling Solutions (ADS) business of AFGlobal. With this acquisition, NOV will be able to offer MPD packages with add- on services from its larger technology portfolio, including NOVOS and real-time monitoring, delivering full rig integration. Additionally, the company’s full MPD sys- tem will be integrated with its wired pipe and Max platform. Mark Mitchell, who had served as President of Oil and Gas for AFGlobal, is now Senior Vice President of MPD for NOV. Jindal, Hunting to build premium OCTG threading plant in India Jindal SAW has formed a joint venture (JV) with Hunting Energy Services to cre- ate India’s first premium OCTG threading facility in Nashik, India. The 130,000-sq-ft facility will enable India to supply OCTG products globally, providing an alternative source of OCTG products to companies engaged in drilling activities. In particular, the project aims to fill a gap in the US market for premium OCTG, accessories and chrome OCTG sup- plies. The facility is targeted to be operational by the end of 2022, with three thread- ing lines commissioned over time and an annual capacity of 50,000 metric tons. eDrilling, ACE to provide AI solution for well construction eDrilling and Automatic Control Engineering (ACE) have announced a part- nership to develop AI-based drilling tech- nologies for E&P companies in Southeast Europe. The companies will collaborate to help operators better plan, perform and optimize drilling operations using AI, machine learning and predictive analytics solutions, along with automation. Enteq launches new center to grow directional drilling tool LYTT, Weatherford sign collaboration agreement LYTT and Weatherford have signed a collaboration agreement combin- ing the former’s proprietary sens- ing insights with the latter’s exper- tise in distributed fiber-optic sensing. Together, the companies will deliver ForeSite Sense, Powered by LYTT. Daniels named to new sustainability role at Shell Shell has appointed Ed Daniels to the new role of Strategy, Sustainability and Corporate Relations Director. Mr Daniels has held roles in Shell’s Upstream, Integrated Gas, Downstream and Projects & Technology businesses. Trelleborg promotes Castleman to M&A Director Trelleborg Sealing Solutions has appointed Heather Castleman as Director, Mergers and Acquisitions (M&A) for Marketing Americas Industrial. She will also continue in her current role as Senior Director, Strategy and Marketing for Marketing Americas. Construction of the 3t EnerMech Guyana Training Center of Excellence is expected to be completed in June. Enteq Technologies has opened its new technology center in Andoversford, UK, to support continued development of its SABER tool, an alternative to traditional rotary steerable systems (RSS) for direc- tional drilling. The company recently con- ducted downhole and system testing of the technology and plans full commercializa- tion later this year. Located in Lusignan, the center is set to become the first regional Engineering Construction Industry Training Board- accredited training provider in Guyana. It will also deliver the country’s first OPITO- approved Basic Offshore Safety Induction and Emergency Training certification. Further, it will deliver scenario-based fire- fighting emergency response training. New training center to help build workforce in Guyana Waukesha achieves new ISO 45001:2018 certification A venture between 3t EnerMech and Orinduik Development Training Center aims to deliver Guyana’s first in-country, state-of-the-art training facility for the local oil and gas workforce. The center will combine in-classroom training facilities, blended learning soft- ware and technology, and fully immersive simulators. Waukesha Magnetic Bearings has achieved ISO 45001:2018 Occupational Health & Safety (OH&S) Management Systems Certification. The new standard is used to establish an effective OH&S management system for preventing work- related injury and illness and for proac- tively improving health and safety per- formance. McDermott names McKelvy as new President, CEO Michael McKelvy has been named President and CEO of McDermott. Lee McIntire, who had been serving as interim CEO since June 2021, will con- tinue as a member of McDermott’s Board of Directors. OEG signs distribution agreement with Blue Manta OEG Offshore has announced an exclusive distribution agreement with well completion installation solutions provider Blue Manta International. The agreement covers Blue Manta’s full range of packaged completion equip- ment across the Americas, Middle East, Africa and Asia Pacific regions. Borr selects IFS solutions IFS announced that Borr Drilling is upgrading its existing IT platforms to IFS Cloud, IFS Cloud Services and IFS Success Services, connecting data across the contractor’s maintenance, supply chain and finance functions. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 47 DE PAR TM E NTS • PEOPLE, COMPANIES & PRODUCTS Data Gumbo opens office in Saudi, signs contract with Equinor Data Gumbo recently launched an office in Khobar, Saudi Arabia, aiming to acceler- ate regional traction with leading indus- trial enterprises. In August 2021, Data Gumbo closed $7.7 million in Series B funding with continued participation from Saudi Aramco Energy Ventures, the corporate venture capital fund of Aramco Ventures. The funding has allowed Data Gumbo to expand global operations and enable accurate, on-time and automated invoicing and payments in additional use cases and verticals. The company had also recently signed a contract with Equinor to use GumboNet across the operator’s drilling and well ser- vices category. Rollouts will begin in the Norwegian Continental Shelf. ADNOC awards $1.94 billion in wireline, perforation deals Abu Dhabi National Oil Company (ADNOC) recently announced frame- work agreement awards valued at $1.94 billion for wireline and perforation ser- vices. The awards – given to ADNOC Drilling, Schlumberger, Halliburton and Weatherford – cover ADNOC’s onshore and offshore fields. Products Tenaris eliminates manual operations with connector’s anti-rotational keys activation Tenaris has launched the Automatic Anti-Rotational Keys (AARK) for its BlueDock premium weld-on connector, eliminating all manual operations associ- ated with the anti-rotational keys activa- tion. This is expected to reduce risks and improve running speeds. When not in use, the system occupies a fraction of the well site or deck space required for a standard slickline winch unit and PCE package. Pre-installed at Tenaris’ manufac- turing facilities and designed to allow multiple activations, the AARKs provide extra assurance against the connector’s break-out. In addition to the automatic and hands-free activation, the technology does not require special tools for removal. New frac plug, data analytics tool aim to improve frac efficiency GEODynamics recently launched a pair of tools that it says will help companies to improve productivity and efficiency at the frac site. The StageCoach data ana- lytics system is designed to ensure uni- form proppant distribution from cluster to cluster, integrating computational fluid dynamics modeling of proppant slurry movement with full-scale proppant trans- port surface test results into an engi- neering model. Meanwhile, its EVOLV composite frac plug reduces performance variables in horizontal completions by employing a shear ring design that can eliminate potential leak paths, erosion and pressure loss. DC’s Stephen Whitfield spoke with Santo Petitto, Sales Manager, and Steve Baumgartner, Senior Technical Advisor, to discuss the technologies at the 2022 SPE Hydraulic Fracturing Technical Conference in February. Click here to watch the video interview with GEODynamics. 48 TGT Diagnostics has launched its Horizontal Flow diagnostics platform with Cascade3 technology. Designed for horizontal wells, it uses tempera- ture and other well system data to model continuous reservoir flow pro- files. This capability provides asset teams with realistic flow modeling and accurate continuous flow profiles in a variety of completion and reservoir set- tings, including fractured formations. Web-based tool helps to calculate carbon footprint Lloyd’s Register updates AllAssets asset management software Lloyd’s Register is rolling out AllAssets 3.0, which allows businesses to quantify their risk exposure and prescribe effective inspection and maintenance plans. The cloud-based software has helped custom- ers reduce risk of failure by up to 95%. It also aims to eliminate data siloes and Flow diagnostics platform targets horizontal wells increase asset performance while opti- mizing inspection costs across assets. This latest update includes increased inspection data capability and tracking, improved data transfer to enhance usabil- ity of the risk-based inspection modules, and an updated security setup. McDermott International launched ArborXD, a web-based tool that pro- vides data collection, estimation and reporting on the potential car- bon impact of energy facilities before construction begins. The tool offers access to lifecycle footprint estimates, cost trade-off analyses, emission reduction pathways and environ- mental impact assessments. It can be applied throughout the project life cycle, including concept to procure- ment to construction and installation. M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R AD INDEX Abaco Drilling Technologies..................52 American Business Conferences........ 41 Nabors Drilling Solutions.............. DIGITAL Noble Corporation........................................49 IADC Advanced Rig Technology Conference & Exhibition...........................6 IADC World Drilling 2022 Conference & Exhibition......................... 51 Global Sales Manager For all sales inquiries regarding Drilling Contractor, official magazine of the International Association of Drilling Contractors, please contact: BILL KRULL Phone: +1-713-292-1954 Cell: +1-713-201-6155 bill.krull@iadc.org Schlumberger.....................................................2 Weatherford.........................................................5 Drilling Contractor / IADC Houston HQ LINDA HSIEH - Vice President, Editor & Publisher linda.hsieh@iadc.org STEPHEN WHITFIELD - Associate Editor stephen.whitfield@iadc.org BRIAN C. PARKS - Creative Director brian.parks@iadc.org ANTHONY GARWICK - Director – Web & IT Services anthony.garwick@iadc.org Find us online Stop by our LinkedIn page to join the conversation, keep up with news and conference updates on Facebook and Twitter, then check out our YouTube video channel! 7,010 + Followers 30,565 + Followers 5,240+ Followers 2.58K Subscribers 2,241,785 + Views D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 202 2 49 DEPARTMENTS • PERSPECTIVES Matt Isbell, Hess: Integration, standardization will help propel well construction performance to the next level BY LINDA HSIEH, EDITOR & PUBLISHER For some people, figuring out what they want to do in life can be a long process of self-discovery throughout their young adulthood or even into their 20s or 30s. But for others, like Matt Isbell, knowing that he wanted to be a mechanical engineer came like natural instinct, even at a young age. “From as old as I knew what a mechani- cal engineer was, that’s been my goal,” Mr Isbell, Senior Drilling Engineering Advisor for Hess, said. “I like to see how things work, and I love the idea of technologies and inventing new solutions.” It also helped that, through his dad’s job as a chemical engineer, he had many opportunities throughout his childhood to visit refineries and fertilizer plants around the US. Having the chance to see large machinery at work only fueled his curios- ity. “I knew mechanical engineers were the ones who got to design them. That was what I wanted – to work with big pieces of equipment and make them better.” Upon graduating from the University of Texas at Austin with a degree in mechani- cal engineering in the late ‘80s, Mr Isbell landed in the oil and gas industry, work- ing as an R&D engineer for what was then Hughes Tool Company. One of his first projects , he recalled, was to try and reinvent roller cone drill bits so they could outperform PDC bits in soft rock. PDC bits were still an emerging technology at the time. The effort went on for about three years before the engineers decided it couldn’t be done. Although the project wasn’t technically a success, it 50 turned out to be a valuable lesson for a young engineer like Mr Isbell was at the time: No matter how much time and effort you put into R&D, “you cannot defy the laws of physics,” he said. Over the next 23 years, Mr Isbell gained a wealth of drilling expertise through differ- ent positions with Hughes Tool Company and its various entities, including Hughes Christensen and Baker Hughes. His work included redesigning and upgrading the company’s drilling simulator, as well as observing field challenges around the world and developing laboratory tests to evaluate new drill bit designs and adapt- ing them to various applications. Along the way, he also added 28 patents and over 33 technical papers to his name. But the work that Mr Isbell said he’s most proud of from his time with Baker Hughes was actually around the manage- ment of people. He had helped to create a program for the company’s new-hire field engineers, focusing not so much on developing their engineering skills but on making sure they knew how to apply those skills out in the field. “The culture part is always the hard- est part to teach,” he said, adding that the program was designed to provide new engineers with an immersive learning experience. “Not only did they get to meet the company representatives and drillers, but they also got to see what a field sales- man does and the logistics of the drill bits. That did a great job of grounding them and prepared them for a career in the oilfield.” Focus on optimization, standardization In 2012, Mr Isbell joined Hess when he got the opportunity to help the company design and launch its drilling limiter pro- gram, SmartDrill. It focused on identifying the factors that limit drilling performance – whether it’s the drill bit, the motor or rock hardness – and then redesigning the drilling system to counter that limiter. In helping to deploy SmartDrill in the Bakken, Mr Isbell said he quickly realized that the drillers and company representa- tives out in the field knew the formations “like the back of their hands. They knew what the problem was; they just couldn’t tell you what the solution was.” So, instead of developing tools that helped them to As Chairman of the IADC Drilling Engi- neers Committee, Matt Isbell says he hopes to continue growing the group’s quarterly technology forums. The fi rst forum of 2022, scheduled for 30 March, will focus on developing the drilling workforce of the future. identify the limiters, the program focused on deploying new technologies to address those limiters they already knew about. This work pivoted Mr Isbell’s focus toward drilling optimization, process auto- mation, real-time systems and now to standardization, where the goal is to create value by removing variability in the well delivery process. Hess is now working on a system where its drilling contractors and service providers can input their standard procedures next to standardized, time- based objectives input by the operator. “You can’t improve what you can’t mea- sure. Standardization will allow everyone to have visibility into what the objectives are, so we can measure the delivery of the plan and sustainably improve it over time,” he said. A key piece of this improvement process will involve the industry’s ongoing work to integrate discrete automation technolo- gies. For example, you may already have a system for automated sliding and anoth- er system that automates coming off or going to bottom, but those systems are not fully integrated yet. “That’s the thing we’re working on today: How do you take a plan to drill a stand of pipe and then do that 200 times safely and efficiently to deliver a 20,000-ft well?” DC M A R C H/A P R I L 202 2 • D R I L L I N G C O N T R AC T O R World Drilling IADC 2022 CONFERENCE & EXHIBITION 21-22 JUNE 2022 PULLMAN TOUR EIFFEL HOTEL PARIS FRANCE DIAMOND SPONSOR PLATINUM SPONSOR TOTAL TOT_21_00008_TotalEnergies_Logo_CMYK JFB 30-34 Rue du Chemin Vert 75011 Paris +33 (0)1 85 56 97 00 www.carrenoir.com TONS RECOMMANDÉS CYAN MAGENTA Ce fichier est un document d’exécution créé sur Illustrator version CS6. Date : 26/05/2021 TECHNIQUE YELLOW SILVER SPONSOR EVENT SPONSOR www.iadc.org/event/iadc-world-drilling-2022-conference-exhibition For more information contact IADC The Netherlands by phone at +31.24.675.2252 or via email at europe@iadc.org OPTIFIT TM POWER SECTION STATORS Optimum Performance Through Innovation TM OPTIFIT is the latest engineering innovation from Abaco. This new stator design delivers an optimized fi t for all drilling applications. Single direction stators feature harder rubber with deviated profi les to address high power and high torque drilling stresses on the power section lower end. The variable fi t of the rotor and stator stabilizes the lower end to reduce frictional wear and overheating by balancing fl uid pressure distribution. This results in maximized performance and greater power section reliability, especially at high power, with a signifi cant reduction in fi eld failure rates. See OPTIFIT and all of our innovative power section technologies at Abacodrilling.com Patent Pending LEADING POWER SECTION TECHNOLOGY Abacodrilling.com © 2022 Abaco Drilling Technologies. All rights reserved.