NEXT FRONTIER FOR RIG ALARM SYSTEMS Drillers using computer vision, AI technologies to optimize alerts for performance, safety – p16 JULY/AUGUST 2023 Volume 79 • Number 4 Official magazine of the International Association of Drilling Contractors www.drillingcontractor.org www.iadc.org Industry building circular water economy as operators lean into recycling, reuse Expanded transport infrastructure, advances in water treatment help to reduce freshwater use – p30 ‘Walking’ tool anchors bit to rock to prevent stick/slip in geothermal drilling Prototype of new tool recently tested on Nabors land rig; market launch planned for 2024 – p36 CUSTOM API 6A & 16A PRODUCTS DESIGNED FOR THE DEMANDS OF OFFSHORE DRILLING WITHSTANDING OFFSHORE FOR OVER 50 YEARS Woodco USA® manufactures API licensed, high quality oilfield products designed for performance in critical environments. We leverage our technical expertise to develop solutions for your fleet that lower non-productive time, control costs, and deliver results when reliability is your top priority. WOODCO USA® PRODUCTS Flanges • Hubs • Adapters • Spools Crosses and Tees • Manifold Equipment Double Studded Adapters • Spacer Flanges Clamps • Custom Manufactured Products CONTACT US FOR YOUR ONSHORE & OFFSHORE OILFIELD PRODUCT NEEDS SALES@WOODCOUSA.COM • (713) 672-9491 WOODCOUSA.COM TAB LE OF CONTE NTS Official magazine of the International Association of Drilling Contractors JULY/AUGUST 2023 Volume 79 • Number 4 drillingcontractor.org iadc.org Drillers are increasingly using technologies like computer vision to enhance their ability to alert rig crews to potential hazards. Read about innovations with rig alarms on Page 16. Cover photo of Rig 515 in the Bakken courtesy of H&P. D I G ITAL TR AN S FO R MATI O N 16 Digitalization pushes rig alarm, alert systems into the next frontier Drillers are increasingly using AI, machine learning, computer vision to notify personnel of performance limiters, keep rig crews safe BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 20 Sensor advances enhance data accuracy, drive more automated workflows Industry finding innovative ways to improve data collection for applications like rig equipment monitoring and flow measurements while prolonging sensor durability in harsh environments BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 26 Chevron leverages smart alarms, multidisciplinary staff at support center to monitor process safety, develop fit-for-purpose solutions BY JESSICA WHITESIDE, CONTRIBUTOR 27 MIT-led project incorporates hard-to-measure data to develop digital twin for drilling risers BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 28 Supercomputers and CCS key to Petrobras’ efforts to build a low-carbon energy ecosystem BY STEPHEN WHITFIELD, ASSOCIATE EDITOR O I LFI E LD WATE R MANAG E M E NT 30 Industry builds circular water economy as it leans into recycling and reuse Water management companies investing heavily in treatment technologies and transport infrastructure as E&Ps continue to shift away from disposal wells, reduce reliance on freshwater BY STEPHEN FORRESTER, CONTRIBUTOR D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 3 TAB LE OF CONTE NTS GEOTHERMAL DRILLING 36 New ‘walking’ tool anchors the bit to the rock, aims to mitigate stick/slip by preventing buildup of reactive torque downhole I N N OVATI O N S I N D E E PWATE R 38 OTC panel: Deepwater’s low-cost, low-emission profile to keep it competitive in coming decades BY STEPHEN WHITFIELD, ASSOCIATE EDITOR BY STEPHEN WHITFIELD, ASSOCIATE EDITOR IADC CONNECTION 42 From the President: Our members make the industry an exceptional global community BY JASON MCFARLAND, IADC PRESIDENT 43 News Cuttings 44 Wirelines 45 Conference Calendar 46 Editorial Preview DEPARTMENTS 6 Drilling Ahead: To bust the asymptote, industry may have to fundamentally redefine safety 40 HSE&T Corner: Great Crew Change 2.0 – Better job-site engagement, competency assurance programs help to keep short-service employees safe BY LINDA HSIEH, EDITOR & PUBLISHER 7 D&C News BY JESSICA WHITESIDE, CONTRIBUTOR 9 D&C Tech Digest 47 People, Companies & Products 11 News Briefs: Environmental, 49 Advertisers Index Social and Governance 12 Oil & Gas Markets 50 Perspectives: Robert van Kuilenburg, 14 Videos BY STEPHEN WHITFIELD, ASSOCIATE EDITOR JULY/AUGUST 2023 Volume 79 • Number 4 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 Noble – Innovative thinking can push drilling into new frontiers complain, please contact the publisher. Our complaint policy is posted at www.drillingcontractor.org. Subscriptions are free to operational personnel employed by contract-drilling firms or by major, national or independent oil companies. Publisher reserves the right to refuse non-qualified subscriptions. Paid subscriptions are available at $260 per year, US; $320, outside the US. Single issues are $40. For advertising rates or information, call Drilling Contractor at +1-713-292-1945 or check our website at www.drillingcontractor.org. Postmaster: Please send address changes to Drilling Contractor magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042. © 2023 Drilling Contractor. All rights reserved. Printed in the USA. PUBLISHED BY IADC OFFICERS IADC 3657 Briarpark Drive Suite 200 Houston, Texas 77042 USA Chairman Andy Hendricks Phone: +1 713 292 1945 drilling.contractor@iadc.org www.drillingcontractor.org Secretary-Treasurer Scott McReaken EDITORIAL STAFF Vice President, Editor & Publisher Linda Hsieh Creative Director Brian C. Parks Associate Editor Stephen Whitfield Contributors Stephen Forrester, Jessica Whiteside Vice Chairman Leif Nelson Division VP North America Onshore Mike Garvin Division VP International Onshore Miguel Sanchez Division VP Offshore Brian Woodward Division VP Drilling Services Tim McGarity President Jason McFarland A full list of IADC staff is available here: www.iadc.org/about/staff J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DEPARTMENTS • DRILLING AHEAD DRILLINGCONTRACTOR.ORG VIRTUAL PANEL DISCUSSIONS VPDS “Optimizing Downhole Drilling for Peak Performance and Reservoir Insight” A IR DAT E: 24 AUGUS T 2 0 2 3 @ 9:00 HOUS T ON (GM T-5 ) Learn how SLB is leading the performance assurance charge — evolving drilling by combining its latest drill bit technologies, rotary steering systems and autonomous controls. These are crucial advances for building wells in the most efficient and consistent manner and enhancing real-time reservoir characterization for more precise trajectories that elevate well performance. On 24 August 9:00 CDT, Drilling Contractor will host a live Virtual Panel Discussion, sponsored by SLB: • Wiley Long, SLB Product Champion PDC Bits, will discuss the evolution of Smith Bits drill bits • Roberta Santana, SLB Product Champion PDC Bits, will highlight the SnapScan app and dull-grading digitalization • Ziad Akkaoui, SLB Digital Champion, will detail autonomous downhole tools • Stephen Whitfield, Drilling Contractor Associate Editor (moderator) Sponsored by drillingcontractor.org/ vpd-registration- optimizing-downhole- drilling 6 To bust the asymptote, industry may have to fundamentally redefine safety BY LINDA HSIEH, EDITOR & PUBLISHER In a 2008 head-on collision between a commuter train and a freight train in California that resulted in mass casualties, the ensuing NTSB investigation blamed the incident on the commuter train’s oper- ator. This individual caused the collision, it was concluded, because he had been distracted by text messages and missed a red signal warning him from entering a section of single track where the freight train had been given the right of way. That type of blame on the worker is exactly what renowned organization- al safety expert Todd Conklin preached against in his talk at the recent IADC HSE&T Conference in Houston. It was an eye-opening speech that shed a lot of light on the next steps that the upstream oil and gas industry must take in order to “bust that asymptote,” he said, quoting a former boss at Los Alamos National Laboratory. The industry has put in significant efforts over the past few decades to improve safety, resulting in a dramatic decline in injuries and fatalities. Yet, our safety curve has plateaued. “This is your story of safety. You’re in a classic asymp- totic relationship,” Dr Conklin told the con- ference attendees. “And doing more of the same is not getting you better results.” To move to the next stage of its safety journey, companies will need to think about safety differently. First, they must accept that every accident is not prevent- able. “This is something the automotive industry figured out, and you guys haven’t made the jump yet,” he said. Accidents are unintentional deviations from an expected outcome, which means they’re hard to pre- dict and, therefore, hard to prevent. “I don’t know how we drifted over time into this perfection model,” he said, where companies believe “there’s a perfect work environment and, if the worker is obedi- ent enough, problems will go away. That’s attractive, but it’s just wrong.” That type of thinking also leads companies to “focus on investigating how we failed to prevent the accident,” rather than investigating the accident itself. This doesn’t mean preven- tion isn’t important, but it’s not enough. To make the next step change in safety, he said, companies need to start defining safety not as the absence of accidents but as the presence of controls, or safeguards. The primary safety function of seat belts in a car, for example, is to position the humans in “survivable space,” where all the different safety systems of the car can function more effectively in case of a crash – and the automotive industry designs their cars assuming a 100% chance they will someday get into a crash. Similarly, the drilling industry must adopt that kind of mindset so that “when the system inevi- tably fails,” there are multiple layers of safeguards built in so it can fail safely. “The most profound message I can give you is never have a worker one safeguard away from a failure. You have to have mul- tiple controls in the system.” Dr Conklin also encouraged companies to adopt a “deliberate strategy” to improve. When an incident happens, “you can choose to either blame and punish, or learn and improve, but you don’t get to do both,” he said. “If you choose to blame, you’re going to shut down learning. Absolutely, I promise you. And if you choose to learn, then you really can’t punish.” When investigating incidents or any kind of operational upset, start by asking about the “what” instead of the “who,” he urged. Stop trying to seek behavior that can be labeled as somehow deficient and the cause of the problem. “Workers are really smart, and we have to stop seeing them as the problem and start seeing them as the solution to draw from,” he said. “Don’t go out and look for places where workers deviate, because you will always find deviation in your indus- try. Go out and look for places where con- trols are effective, and repeat that every chance you get.” DC See Page 14 for a link to watch DC’s interview with Dr Conklin. J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DRILLING & COMPLETION NEWS • DEPARTMENTS $12.7 billion Uaru development in Guyana with 10 drill centers, 44 wells gets green light Hess Corp and ExxonMobil have made a final investment decision to proceed with Uaru, the fifth development on the Stabroek Block in Guyana, after receiv- ing government and regulatory approvals. Uaru will have a production capacity of approximately 250,000 gross bbl/day of oil , with production targeted to start in 2026. The $12.7 billion Uaru development will target an estimated resource base of more than 800 million bbl of oil and include up to 10 drill centers and 44 production and injection wells. MODEC is constructing the floating production, storage and offload- ing (FPSO) vessel for Uaru, which will be called Errea Wittu . Guyana's Liza Phases 1 and 2 production average d 375,000 gross bbl/day in Q1. The third and fourth sanctioned developments , Payara and Yellowtail, are targeted for startup in Q4 and in 2025, respectively . A sixth development, Whiptail, is expected to be submitted for government and regula- tory approval later this year. ADNOC Drilling to add 2 jackups to its fleet as part of continued expansion Equinor is planning to drill 10 new wells on the upgraded Njord . Image source: Even Kleppa and Lizette Bertelsen/Equinor. Equinor aims to double field life and production from reinvigorated Njord field The Njord field in the Norwegian Sea was officially reopened on 15 May after extensive upgrades were made to the platform and floating storage and offloading vessel (FSO) to double the field's life – and more than double its production. The Njord field started production in 1997 and was originally supposed to produce until 2013. However, systematic work with increased recovery means that there are still large volumes of oil and gas left. New discoveries in the area can also be produced and exported via Njord. In 2016, the platform and FSO were disconnected from the field and towed to shore for upgrades. On 27 December 2022, produc- tion resumed from the Njord field. “This is the first time a platform and an FSO have been discon- nected from the field, upgraded and towed back offshore. We have now doubled the field life,” said Grete B. Haaland, Equinor Senior Vice President for Exploration and Production North. Equinor says it aims to produce approximately the same vol- ume from Njord as the company has already produced so far, around 250 million BOE. Ten new wells will be drilled on Njord from an upgraded drilling facility, and more exploration will be carried out close to the field. In addition, two new subsea fields have already been tied back to Njord. Combined recoverable volumes from the Bauge and Fenja fields, which both started production in April, are 110 mil- lion BOE. ADNOC Drilling has signed an agreement to acquire two premium high-specification Gusto MSC CJ46 design jackups . The rigs will be delivered into Abu Dhabi waters and become operational during Q4 . With this $220 million combined rig acquisition, the com- pany will have almost doubled its jackup fleet since early 2021, and further significant expansion is still expected from now until the end of 2024. ADNOC Drilling's overall rig fleet has grown from 95 in October 2021 to 115 as of 31 March. "The acquisition of these premium jackup rigs will sup- port one of our major customers, ADNOC Offshore, with its drilling and completion services requirements, as it delivers accelerated production capacity," said Abdulrahman Abdulla Al Seiari, Chief Executive Officer of ADNOC Drilling. " These rigs further cement our position as one of the world’s largest offshore jackup rig fleet owners and supports our plan to grow our overall fleet to 142 owned rigs by 2024.” Multiple new contracts announced for offshore rigs from Shelf, Odfjell, Stena ■ Shelf Drilling has secured a contract for the Shelf Drilling Barsk jackup with Equinor for operations at the Sleipner Vest field, located on the Norwegian Continental Shelf. The firm term of the contract is two wells, approximating to 270 days. The contract value for the firm period, excluding certain inte- grated services, is approximately $61 million. The contract also includes options for two additional wells, and the planned startup of operations is between May and July 2024. ■ Separately, Shelf also secured a short-term contract for the Adriatic I jackup for operations offshore Nigeria, with a firm term of 90 days and an estimated contract value of $11 million, excluding revenues for mobilization and demobilization. The contract is scheduled to start in early May 2023 ■ DNO Norge, Aker BP and Longboat Energy have contracted Odfjell Drilling's Deepsea Yantai semisubmersible to drill the Lotus (Kjøttkake) exploration well in Norway. Drilling is expected to commence in Q3 2024 . Licence PL1182S lies in the prolific Northern North Sea, 4 km southeast of the recent Kveikje discovery . ■ Shell has contracted Stena Drilling's Stena Evolution drill- ship to operate in the US Gulf of Mexico starting in Q2 2024 for a primary term of five years . D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 7 DEPARTMENTS • DRILLING & COMPLETION NEWS Equinor and partners take $9 billion decision to invest in Brazil's BM-C-33 project A second highly deviated deep well has been spudded as part of Utah FORGE's continued efforts to commercially scale Enhanced Geothermal Systems tech- nologies. Temperature at total depth is expected to reach 440°F. Utah FORGE spuds 2nd highly deviated deep well The Utah Frontier Observatory for Research in Geothermal Energy (FORGE), funded by the US Department of Energy, recently commenced the drilling of its second highly deviated deep well . This second well will serve as the produc- tion well of a two-well doublet and will mirror the existing injection well, which was drilled between October 2020 and February 2021. The new well will be located approximately 300 ft from the injection well. Like the injection well, the upper part of this well will be drilled vertically through approximately 4,550 ft of sedi- ments, at which point it will penetrate into hard crystalline granite. At about 5,600 ft, the well will be gradually steered at 5°/100 ft until it reaches an inclination of 65° . The total length of the well will be approximately 10,700 ft, with the toe reaching a vertical depth of 8,265 ft. The temperature at this depth will be 440°F. “This is a crucial next step in the Utah FORGE project’s goal of de-risking the tools and technologies required for mak- ing Enhanced Geothermal Systems (EGS) technologies commercially viable," said Joseph Moore, Principal Investigator of Utah FORGE. “ In the future, water will be pumped into the injection well, travel through the reservoir of tiny fractures that we previously opened, absorb the heat from the hard, hot crystalline gran- ite, and then be pumped up through this new production well to the surface ." Once the well is completed, tests will be run to continue facilitating the development of the EGS reservoir and its long-term connectivity. Additional tests will also include determining the stress conditions through short-term injection experiments, during which microseis- micity will be monitored. BSEE tests subsea blowout preparedness with GOM drills The US Bureau of Safety and Environmental Enforcement (BSEE) completed two unannounced drills in May to evaluate the industry's prepared- ness to respond to a subsea blowout. Each drill lasted between three and five days . During the two drills, with Beacon Offshore Energy and Chevron, each company was required to deploy a cap- ping stack from their respective storage locations to separate areas in the Gulf of 8 Mexico . Once onsite, each operator low- ered a capping stack onto a simulated well head on the ocean floor in about 6,000 ft of water, connected the capping stack to the wellhead, and pressurized the system to 12,500 lb/sq in to simulate well pressure. BSEE said initial observations indi- cate the drills met requirements for deploying source control equipment but will i ssue a formal report later this year with a full evaluation . Equinor , Repsol Sinopec Brasil and Petrobras have taken the approximately $9 billion investment decision to develop the BM-C-33 project in Brazil. Located in the Campos Basin, BM-C-33 comprises three pre-salt discoveries – Pão de Açúcar, Gávea and Seat – contain- ing natural gas and oil/condensate recov- erable reserves surpassing 1 billion BOE. The concept selected for BM-C-33 is based on a floating production, storage and offloating unit (FPSO) capable of pro- cessing gas and oil/condensate and spec- ifying these resources for sale without a need for further onshore processing, a first in the country. FPSO production capacity will be 16 million cu m/day of gas , with startup planned for 2028. The FPSO will be Equinor’s second in Brazil using combined cycle gas turbines, significantly reducing carbon emissions during operations. The technology, which will also be applied in Bacalhau in the Santos Basin, combines a gas turbine with a steam turbine to take advantage of the excess heat that would otherwise be lost. By implementing this technology, the average CO 2 intensity of BM-C-33 over its lifetime will be lower than 6 kg/BOE. BM-C-33 is one of Brazil's main projects to develop new supplies of domestic gas . It's expected that gas exported from the project could represent 15% of the total Brazilian gas demand at startup. Its devel- opment will also contribute to the coun- try's economic development . Neptune boosts production from Adorf field in Germany Neptune Energy announced first pro- duction from its operated Adorf Z17 gas well in the municipality of Georgsdorf in northwestern Germany. The well is expected to increase Neptune’s production from the Adorf licence to around 6,300 BOED. Construction of a dedicated processing plant at the site for treatment of the gas was also completed earlier this year. Drilling of another well, Adorf Z18, reached a final depth of 4,773 m in April and is due to begin production in Q3. J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DRILLING & COMPLETION TECH DIGEST • DEPARTMENTS Transocean Encourage drills its first fully automated hole section The Transocean Encourage recently drilled its first fully automated hole sec- tions while working for Equinor in Norway. Transocean, Equinor and HMH worked together to complete the autonomous oper- ation at the Heidrun field in April. The goal was to automate routine opera- tions, reducing the potential for human errors and driving efficiency. “Thus, giv- ing the drillers more time to focus on what really matters, like well construction challenges and red zone management,” said Francesco Ferri, Operations Manager, Europe & Mediterranean for Transocean. To enable this operation, the semi- submersible was equipped with several “smart modules” that are designed to: ■ Establish well protection parameters, which are set either manually by the user (static mode) or detected by the digital twin of the well (dynamic mode); ■ Optimize torque adjustments to improve the rate of penetration (ROP) and reduce wear and tear on the bottomhole assembly (BHA) and drill bit; ■ Optimize weight on bit (WOB), achieved in combination with the use of an active heave compensator to minimize the weight variations; ■ Improve human-machine interface to better visualize the main drilling param- eters and easily control the equipment on the rig floor; ■ Facilitate automatic tripping in and out of hole. This allows a reduction in the number of buttons to be clicked, from 18 with two operators down to just three confirmations from one operator. Tripping speed is optimized automatically to meet the values of surge and swab simulated in real time; and ■ Provide for automatic drilling connec- tion sequences, including “off-bottom” activities like connections and pipe han- dling, as well as tagging bottom and auto- drilling. The hole sections were drilled by designing automatic sequences for trip- ping and drilling and for making up drill- ing connections. Automatic controls on torque and WOB optimized the ROP and increased the operating window . “The focus is not only on performance and consistency but, most importantly, The Transocean Encourage recently deployed a new drilling assistance module, working in concert with other smart modules on the rig, to drill a fully automated hole section on a well at the Heidrun fi eld in Norway. on incident prevention, through automatic protections that allow improved response time to critical conditions, e.g., hookload protection, pack-off protection, flow limi- tations, etc,” Mr Ferri said. “Such protections are enhanced by real-time simulations of characteristic parameters of the well to automatically adapt the ongoing operations, for exam- ple, optimized tripping speed accounting for continuous surge and swab simula- tions, or automatic mud pump startup sequences.” Finally, he added, the integration of downhole real-time data collection and topside automation allows a “closed-loop” system to move from automatic to autono- mous. Data analytics to enable further fine tuning On Cat D rigs like the Transocean Encourage, which are specialized for the harsh environments of offshore Norway, work on automatic drilling technologies has been in progress since summer 2017, Mr Ferri said, with the goal of moving por- tions of the drilling process from automa- tion toward autonomous operations. In April this year, the Transocean Encourage tested for the first time the use of a new drilling assistance module in combination with the relevant smart modules. The ongoing operation was drill- ing the 16-in. and 12 ¼ -in. hole sections on the F-4 well at the Heidrun field operated by Equinor. The rig team executed a total of 51 con- nections with a median slip-to-slip (S2S) time of 3.14 min, all without intervention from the driller. The best S2S time was 2.88 min, while the best weight-to-weight time was 4.16 min. Even though the Transocean Encourage was the first rig to demonstrate the per- formance of the smart modules working together, the results from this first deploy- ment were already competitive with results achieved manually, Mr Ferri said. “Further fine-tuning will be implemented through the learnings extrapolated with data analytics,” he added. The Transocean Encourage is on an eight-year contract with Equinor that had been set to expire in December. In March, Equinor extended the rig’s contract for nine additional wells. On other rigs in its fleet, Transocean has been working to deploy an automation solution from InteliWell. The independent joint venture, in which Transocean has partial ownership, offers similar automa- tion functionality, Mr Ferri said, and initial results have been promising. D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 9 DEPARTMENTS • DRILLING & COMPLETION TECH DIGEST 20,000-psi open-water shear, seal valves to support GOM HPHT campaign The RizeRdillo Advanced Jetting Tool allows for higher pump fl ow rates for BOP cleaning, enabling a larger volume of fl uid with less pump pressure. No damage was seen with the BOP by using the higher pump rates during the trial period. Jetting tool enables higher pump rate for BOP cleaning on Johan Sverdrup, reducing time by half Odfjell Technology recently trialed a new procedure for BOP cleaning on the Johan Sverdrup platform in Norway, achieving a 50% time reduction during the six-month test period. The new pro- cedure involved increasing the pump rate to allow more water flow into the BOP cavities to aid debris removal. The annular and variable rams were flushed with two passes at the new rec- ommended flow rates to remove debris, then the BOP stack was flushed at the same rate using the RizeRdillo Advanced Jetting Tool. The flow rates went from 1,500 liters per minute (LPM) to 5,500 LPM while flushing the annular and from 3,000 LPM to 5,500 LPM while flushing the BOP. Results from the test period proved that no damage occurred to the BOP and annular with the recom- mended pump rates, and between six and 12 hours of time could be saved using this new procedure. Separately, Odfjell Technology also announced deployment of a rigless plug and abandonment (P&A) unit for a geo- thermal pilot project in Tromsø, Norway. The project aimed to progress an underground heat storage concept . The key objective was to create a network of subsurface fractures between a center injector well, along with surrounding production wells. All wells had been pre-drilled down to 300-m depth. Odfjell ’s rigless P&A unit deployed a hydraulic stimulation assembly, sand jetting and fracturing the formation every 5-7 m from 70- to 270-m depth. After the frac- tures were established, an injection test confirmed significant flow communica- tion between the injector well and the producers . With this fracture system in place, Kvitebjørn Varme, the company oper- ating the district heating facility in Tromsø, can use the excessive heat pro- duced from its plant during summer to warm up water, circulating hot water down the injector well into the fracture network and up through the producer wells. Heat is transferred from the hot water to the formation, heating the rock over time. During winter, cold water will be circulated into the fracture system, transferring the stored heat to the cold water. Hot water is produced from the production wells, ready to be distributed directly into the district heating network. NOV bit sets field record in Colombia’s Acordionero field NOV and Gran Tierra Energy recently worked together to deploy the Tektonic Fuego drill bit technology in Colombia’s Acordionero field, setting a field record with the Acordionero 98 well. A 12 ¼-in. TK59 bit equipped with ION cutters was run on a downhole motor assembly for a total of 2,446 ft in 2.25 10 hrs, resulting in an ROP of 1,087.1 ft/ hr. Previous PDC bits deployed in the 12 ¼-in. section, which is composed of claystone and sand, had shown broken and chipped damage on PDC cutters and severe erosion on the steel body. The previous record in the field was 983.2 ft/hr. Subsea intervention technology special- ist Interventek is set to supply a complete set of fully qualified 20,000-psi open-water well intervention shear and seal valves to Trendsetter Engineering later this year. The agreement allows Trendsetter exclu- sive rights to deploy the 20K, 5 ⅛ -in., open- water valves for five years . These 20K Revolution valves are designed as a compact, modular addition for lightweight subsea intervention sys- tems. They will provide the well control function within Trendsetter’s new 20K TRIDENT Subsea Intervention System, which will first be deployed on a high- pressure, high-temperature (HPHT) subsea completion and intervention campaign in the Gulf of Mexico. Subsea intervention in an HPHT envi- ronment would normally use hydraulic gate valves or rams as a well control solution, but these are larger, heavier and slower to operate . Interventek’s shear and seal mechanism uses separate internal components and rotary actuators to shear through a range of wireline or coil-tubing conveyance systems and seal the wellbore in a single operation. This also allows size and weight reduction of the assembly . Interventek previously introduced the first 20K-rated in-riser safety valve in 2017, so the open-water variant is a natural pro- gression, the company said. 46th GOM well intervention, 3 riserless zone perforations under C-Innovation’s belt C-Innovation recently completed its 46th well intervention in the Gulf of Mexico , as well as three new riserless zone perforations . The company’s well intervention program has performed 31 hydraulic interventions and 15 mechanical interventions since 2017. The mechani- cal interventions included 85 successful wireline runs, both e-line and slickline. C-Innovation also recently completed its longest mechanical intervention onboard the vessel Island Venture. With 79 days offshore, the operation included 22 e-line and slickline runs, as well as 22,205 bar- rels of fluid pumped into the well. J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R ENVIRONMENT, SOCIAL AND GOVERNANCE • DEPARTMENTS Study touts low carbon intensity of US Gulf of Mexico oil production compared with other parts of the world A new study indicates that the green- house gas intensity of US oil production, particularly in the Gulf of Mexico (GOM), is significantly lower compared with most other regions around the world. The study, commissioned by the National Ocean Industries Association (NOIA), found that total US oil production has a carbon intensity 23% lower than the international average outside the US and Canada . Further, the US Gulf has a carbon intensity 46% lower than the global aver- age outside of the US and Canada, out- performing nations like Russia, China, Brazil, Iran, Iraq and Nigeria. Using the largest crude category from the GOM (API Gravity 37.5), instead of similar crudes from outside the US and Canada, could halve the average interna- tional carbon intensity, the study stated. The report includes a sensitivity analy- sis of global methane emissions, indicat- ing that US production, especially in the GOM, performs much better relative to the global average in terms of emissions intensity even when measured using other methane estimation methodolo- gies. “The world needs both climate solu- tions and a growing amount of energy, and we don’t have to choose between the two,” NOIA President Erik Milito said. “ The Gulf of Mexico produces a massive amount of energy with a remarkably small footprint, and its continued suc- cess is critical for our energy security, national security and energy affordabil- ity. This study validates the importance of the US Gulf of Mexico as a source of energy with demonstrably lower carbon intensity barrels.” Scan me to access “ GHG Emissions Intensity of Crude Oil and Condensate Production.” bit.ly/3X4tSNP Competition launched to reshape global energy In May, ADNOC launched the Decarbonization Technology Challenge, a global competition to find innovations that will help to reshape the global energy landscape. Ten finalists will be invited to pitch their innovations to a panel of judges in December . Winners will receive up to $1 million in piloting opportunities with ADNOC, as well as access to state-of-the- art research and innovation facilities in Abu Dhabi. Below are examples of specialization areas being sought for the competition: ■ Carbon capture, utilization and storage ; ■ New energies like hydrogen, geothermal and energy storage; ■ Oil and gas emissions reduction, includ- ing emissions detection and monitoring and other technologies for decarbonizing operations; ■ Digital applications; ■ Advanced materials for decarboniza- tion, and ■ Nature-based solutions . The competition is being delivered in partnership with the Net Zero Technology Center and is supported by AWS, BP and Hub71. Scan me to access the competition website and entry criteria. Deadline is 11 August. bit.ly/3X0SnLQ ADNOC and Baker Hughes signed an agreement at the UAE Climate Tech in May to collaborate on hydrogen. From left are Chris Barkey, Baker Hughes Chief Tech- nology Offi cer for IET; Lorenzo Simonelli, Baker Hughes Chairman/CEO; Musab- beh Al Kaabi, ADNOC Executive Director, Low Carbon Solutions and International Growth Directorate; and Sophie Hildebrand, ADNOC Chief Technology Offi cer. ADNOC, Baker Hughes to advance hydrogen technology ADNOC and Baker Hughes signed an agreement to collaborate on the devel- opment and commercialization of tech- nology solutions for green and low- carbon hydrogen, as well as graphene . The agreement includes exploring the application of three emerging technolo- gies that Baker Hughes has invested in: ■ Piloting next-generation electrolyzer technology to explore the possibility of installing and operating an electrolyzer at the ADNOC Research and Innovation Center in Abu Dhabi ; ■ Field-testing methane plasma tech- nology to capture carbon in the form of high-quality graphene and hydrogen in ADNOC Gas facilities ; ■ Testing the use of growth stage meth- ane pyrolysis technology to produce low- GHG intensity hydrogen. DNV to support EGPC with sustainability program DNV signed a Memorandum of Understanding with the Egyptian General Petroleum Corp (EGPC) to support the lat- ter in its effort to set science-based targets for net-zero goals. EGPC is setting these targets within the framework of the “Egypt Vision 2030” national plan to reach the country’s sustainable development goals , in line with the 1.5°C pathway of the Paris Climate Agreement. Both parties will identify the economic, social and environmental risks, opportuni- ties and impacts of EGPC’s activities for all relevant stakeholders . D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 11 DEPARTMENTS • OIL & GAS MARKETS Latin America’s natural gas deficit forecast to grow, lead to need for more imports With rigs continuing to leave, utilization in the Asia Pacifi c region has risen. Drill- ships are fully utilized, and the jackup segment is close to selling out, at 97%. Westwood analysis show rig supply is shrinking in Asia Pacific while dayrates continue to rise Offshore rigs continue to leave the Asia Pacific (APAC) for other markets , accord- ing to recent analysis by Westwood Energy’s Senior Rig Analyst Paul Ezekiel. A total of 14 units have left the region in the past year, although there is one more semi in APAC now compared with the same period last year. In Singapore, only six jackups remain , but they’re all bound for the Persian Gulf. At the same time, Mr Ezekiel pointed out that utilization and dayrates have increased significantly even though Brent prices dropped by approximately 25% between May 2022 and May 2023. The lower supply, especially in the jackup and drillship segments, has aided utilization recovery across most rig types over the year. The jackup segment is now close to sold out at 97%, while drillships are fully utilized. Tender-assist utiliza- tion dropped by 5% year-on-year, while increased supply and lower demand in the semi segment has resulted in decreased utilization of around 22 % com- pared with a year earlier. Dayrates are trending upwards, with rigs typically being secured at higher rates than their previous commitments . Jackups have been fixed at as much as $67,000/day more than their previ- ous or current deals, while one drillship was fixed at $240,000/day more than its 12 previous contract. Semis have also wit- nessed the same trend, with new fixtures being secured at up to $113,000/day more than prior deals. Meanwhile, between May 2022 and May 2023, Westwood recorded a 10% increase in average rolling jackup dayrates, 28% increase in drillship dayrates and a 7% increase in tender-assist rig dayrates. Another indicator that market dynam- ics have changed is reduced contract award activity. Between January 2022 and May 2022, there were 34 contract awards in the APAC region for all rig types . For the same period in 2023, there were only 13 awards. This reduced pace naturally occurs when there is less avail- ability and operators want to lock in rigs on longer deals before prices rise further. Westwood’s RigLogix currently holds 21 requirements in Southeast Asia or Australia already at a tender stage, total- ling over 14 years of potential demand. Of this total, 73% is for jackup campaigns and the remaining tenders are for semis. Westwood expects current utilization levels to hold steady or rise further in the next 12 months. Dayrates have not pla- teaued yet, according to Mr Ezekiel, but the pushback on rates from operators will continue. In this environment, operators will be considering further rig-sharing campaigns and more direct negotiations. Wood Mackenzie is forecasting that the gas supply in Latin America will be unable to keep up with demand in the next decade due to challenges with gas development. This will drive the need for expanded imports . Over the next 10 years, natural gas demand in the region is expected to rise by an average of 1.4% per year , stabiliz- ing at approximately 25 billion cu ft/day . Within the same time frame, gas supply is expected to decline at a rate of 5.6% . “There are significant challenges with infrastructure restrictions and unfavor- able exploration incentives. The likely result will be a steady increase of imports in the region,” said Adrian Lara, Principal Research Analyst, Latin America Upstream Oil and Gas for Wood Mackenzie. Imports could range between 7 to 12 bcfd by 2035 to meet demand. In 2022, net imports were 4.9 billion cu ft/day, and Wood Mackenzie’s 2023 forecast projects 5.2 billion cu ft/day. Countries in the mid-continent will be most challenged with gas integration, while countries like Argentina, with its strong reserves, may find opportunities to supply neighboring countries. “Colombia’s gas production needs to off- set declines of at least 300 million cubic feet per day by 2030, or else it will require a higher level of gas imports,” Mr Lara said. “Venezuela has a significant amount of undeveloped gas resources in the Mariscal Sucre offshore assets, estimated at 13.6 trillion cu ft, and some of which could be jointly developed with Trinidad and Tobago. Peru also has discovered unde- veloped resources in the Camisea region, accounting for approximately 3.7 trillion cu ft. The question remains which of these resources can become more attractive to operators and whether the infrastructure and market restrictions can be overcome in a timely manner.” “As many countries shift away from oil and coal in favor of gas to support the energy transition, demand will continue to grow in the next decade,” Mr Lara said. “For Latin America countries, the chal- lenge will be meeting this demand while their own production declines.” J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R OIL & GAS MARKETS • DEPARTMENTS Energy Council’s 2023 Global Industry Survey finds energy transition at top of strategic priorities list The energy transition topped the list of strategic priorities for the next year, according to an Energy Council survey of more than 500 people. M&A, financing and cost reduction followed as the next priorities in the 2023 Global Industry Survey. More than 40% of participants in the survey were from oil and gas com- panies, while other participants came from a mix of consultancy/law firms, non-financial service providers, inves- tors, power/utility companies, and gov- ernment/NOC. One question the survey asked was whether participants were expecting any revenue from green initiatives in 2023. Nearly 50% said no , while approximately 35% said less than half of their revenue will come from green initiatives and 10% said they expect more half will be from green initiatives. When it comes to growth inhibitors for their organizations, the biggest per- centage of participants (25%) said it was lack of access to capital, while the next- largest percentage (21%) said regulatory change. Additionally, 15% of people cited talent as an inhibiting factor . Oil and gas companies were also asked where they were most likely to get their financing from in 2023, and 31% said private equity. The next top answers were debt financing and insti- tutional lenders. When it comes to exploration, the sur- vey also found that approximately 65% of respondents believe exploration will What are your strategic priorities over the next 12 months? 10% 3% Digital technologies Other 21% 11% Exploration Explor ation Ener gy TrTrTransition ansition Energy 16% 12% JV /Str ategic JV/Str Allian ces ce s Alliance 13% Cost r eduction M&A/ A&D Activi Activitytyty 14% Raising Finance e Financ The largest percentage of respon- dents (21%) cited the energy transition as a strategic priority for their organi- zation over the next year. play a key role in their businesses. That’s an increase of 13% compared with the 2021 survey and up 6% compared with 2022. For the third year in a row, West Africa and South America were the top spots where respondents saw the biggest E&P opportunities. Looking at the future of oil prices, the biggest percentage of respondents (nearly 60%) said they expect pricing to stay between $75-100, up from about 50% last year. Fewer people this year (13%) said they believe prices will exceed $100, compared with nearly 25% last year. Europe may need 55 bcm cut in gas demand to avoid risks from supply reductions Failure to immediately reduce gas demand by 55 billion cu m (bcm) could put Europe at substantial risk from a rebound in Asian demand or reductions in Russian imports, according to McKinsey & Co. A total cessation of Russian imports could reduce Europe’s supply by 25 bcm, and renewed Asian LNG demand could soak up 35 bcm of supply while a colder winter in 2023 could boost demand by 15 bcm. The research indicates that 57% of EU manufacturers would not be able to further reduce gas consumption while maintain- ing output over the next two years, indi- cating that further gas rationing measures could substantially impact the economy. Even if Europe meets targets to reduce gas consumption , volatile gas prices and potential supply disruptions still pose a risk to many economic sectors. McKinsey projects that Europe may need to delay the phase-out of coal, extend the lifetime of nuclear plants and accelerate the expan- sion of renewable energy sources to reduce reliance on gas as a baseload . “Our analysis shows there is little bandwidth to further reduce Europe’s gas demand without substantial economic damage,” said Namit Sharma, McKinsey Senior Partner . “ The many variables at play will produce significant uncertainty, and Europe’s businesses may need to pre- pare to mitigate these risks. This may require businesses to consider diversify- ing their energy sourcing and managing demand, investing in natural gas substi- tutes or storage, and closely monitoring movements in the energy market.” Texas Petro Index down amid weak oil and gas pricing, falling value of production The Texas Petro Index (TPI) declined for the third straight month in April, retreat- ing to 176.9 for the month. This is down from 177.8 in March, but up by 12.3% com- pared with the April 2022 TPI of 157.6. Weak pricing for crude oil and natural gas are largely responsible for the decline, with downward pressure on the index coming from prices themselves, as well as the falling value of crude oil and natural gas production. Drilling permits also reg- istered year-over-year negatives for April . Nominal (unadjusted for inflation) crude oil prices averaged $75.22 for the month. This is down 23% compared with year-ago levels. In real ( inflation-adjuste d) terms, the April crude oil average is down by nearly 27% year-over-year. Nominal natu- ral gas prices are down a sharp 71% in April compared with year-ago levels, and in real terms were off by close to 73%. That means that, even though production continues to climb, the real value of that production is down by over 20% for crude oil and nearly 60% for natural gas through the first four months of the year. “Declining prices, followed by a decline in drilling permits, suggests that the rig count will weaken in the coming months ,” said Karr Ingham, creator of the TPI analy- sis. “At some point, employment will fol- low suit. We can hope that the economy shrugs off a recession and that growing domestic and global demand will begin to stabilize prices and return some optimism to the oil patch in 2023.” D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 13 DEPARTMENTS • DRILLING & COMPLETION VIDEOS DC Videos » Lamberto Nonno – Baker Hughes bit.ly/3NryZV5 More videos on DrillingContractor.org » Carolina Leão – Tenaris » Manless Rig Floor – NOV Springett Technology Center » Davide Scotti – Saipem 14 bit.ly/42L1emk » Curt Braun – BP J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R bit.ly/3p9jckp bit.ly/3qKjA9n bit.ly/3P9YoEf DRILLING & COMPLETION VIDEOS • DEPARTMENTS » Cody Ashley – Latshaw Drilling bit.ly/42AIfuA » Matt Fitzsimmons – Rystad Energy bit.ly/43A6lXr » Patrick McKeever – Oil States Energy Services » OTC Energy Workshop for Texas Teachers » Enhanced Drilling Showcase bit.ly/3qFzqlU bit.ly/43F7vB6 bit.ly/3JbrEX4 » Todd Conklin D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 bit.ly/3X6vBlZ 15 DI G ITAL TR AN S FOR MATION Digitalization pushes rig alarm, alert systems into the next frontier Drillers are increasingly using AI, machine learning, computer vision to notify personnel of performance limiters, keep rig crews safe BY STEPHEN WHITFIELD, EDITOR & PUBLISHER A s wells become more complex and new automation tech- nologies are added to drilling processes, rig crews have become increasingly reliant on alarm systems – both to keep people safe from hazards like dropped objects and to help them manage the plethora of data coming in from various sensors on surface equipment and in the wellbore. With safety-related alarms, recent advances have propelled computer vision technologies to the forefront, primarily by enabling continuous, dynamic monitoring of the areas where Highlights As more safety-related alerts are added to its Rules Engine Exchange system, Patterson-UTI is working to install REX engines directly at the rig site to reduce latency and speed up alert delivery. As part of its dropped objects focus, H&P is using computer vision technology to help keep crews away from the pipe delivery system during high-risk activities. Seadrill is also deploying a computer vision-based system to monitor for PPE on rig crews in the red zone. The tool has been installed on three drillships working in Brazil. 16 heavy drilling equipment operates and the risk of serious injury or fatality is the highest. By combining artificial intelligence (AI) and machine learning with cameras installed in hazardous areas, these systems are helping to mitigate the potential blind spots and errors that come from humans monitoring the rig floor. “Our primary objective is keeping our crews safe, and we’ll uti- lize whatever tool we can – video analytics, AI, machine learning – to help us meet that objective,” said Richard McConomy, Manager of Seadrill’s PLATO digital platform, which helps the company leverage large data sets for better decision making. “Video analyt- ics powered by AI is an efficient tool for detecting and managing safety issues in real time by sending alerts to prevent accidents.” For alarms related more to equipment and operational perfor- mance, companies are focused on leveraging advanced data ana- lytics, which can involve moving data processing from the cloud to the rig site, so alerts can go out as early as possible. “We want to get notified of those moments where we’re leav- ing performance on the table as they happen, instead of getting a post-well analysis where we realize we were limiting,” said Trevor Olson, Drilling Optimization Manager at Patterson-UTI. “If a mud pump goes offline and we’re not able to get enough flow rate in a certain section, we’re not performing as efficiently as we want. We want to be able to see that as it happens and be proac- tive about addressing those limiting factors.” Maximizing performance Last year, Patterson-UTI started rolling out its Rules Engine Exchange (REX), a cloud-based real-time alerting system for monitoring equipment and maximizing performance. It uses data J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DI G ITAL TR AN S FOR MATION Above: Patterson-UTI's Rules Engine Ex- change (REX) alerts rig personnel to potential issues that may be limiting performance on the rig so they can take action. The company plans to complete a pilot installation of the sys- tem on 10 rigs by the end of this year. Right: Patterson-UTI has 83 alerts vali- dated and available on its REX system. An additional 30 newer alerts, focused more on safety and hazardous events, are undergoing validation. from electronic drilling recorders, rig control systems, morning reports and real-time models calculated at the rig site to deliver alerts of operational events in near-real time via text messaging, e-mail and an online interface. Users can customize the system to their own needs by sub- scribing to specific types of alerts or even creating new alerts for themselves. Three categories of alerts are available: simple opera- tional events, such as when a rig started or completed a trip or reached a well’s total depth; equipment alerts, which notify users when specific pieces of equipment have entered a fault or warn- ing state; and data quality alerts, which tell users when a sensor on a given rig is returning improper values. Patterson-UTI finished the first stage of REX’s development last year – building its backend infrastructure and user interface, installing it over a cloud computing network and completing field trials validating the system’s effectiveness. Since then, the com- pany has been working on the next development stage, which involves adding alerts to cover additional performance-limiting scenarios and equipment issues, as well as installing the REX engine directly onto servers housed on Patterson-UTI’s rigs . The company intends to have the system fully installed on all rigs by the end of this year. Building infrastructure for the REX system to run directly on the rigs will allow the company to deploy alerts locally instead of through the cloud-based infrastructure, Mr Olson said. By install- ing the system on the company’s CORTEX KEY edge servers, which are housed on each rig and connected to the rig control system and the electronic drilling recorder, the company believes D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 17 DI G ITAL TR AN S FOR MATION H&P’s PDS Redzone computer vision system breaks down in- dividual frames of camera footage taken around the red zone of the pipe delivery system, sending an audible alarm if it detects anyone in the red zone when the PDS is activated. it will be able to reduce the time needed to process data and get alerts out to the rig crews. “Right now, the main hindrance with the cloud is that we’re only as fast as the slowest data that we have coming in,” Mr Olson said. “We can get the rig control system data basically in real time, but we get the EDR data in five-minute packets from our service provider, so we have to run the rig alert system at least five minutes after. Then, it takes a couple of minutes to run code and deliver the alert. By housing all of this in CORTEX KEY, there’s going to be zero time to get the data in there. Instead of getting notifications out in five or seven minutes, we will be able to get them within one minute.” This reduced latency will become important for Patterson-UTI as it incorporates more alerts dealing specifically with the poten- tial for loss of well control into the REX system, Mr Olson said. The company currently has 83 alerts validated and available on the REX system, with an additional 30 alerts under consideration. New alerts, which have focused more on safety and hazardous event detection, have tended to be more complex than the initial alerts developed for the system and must be validated for effi- ciency over a set of sample data sets. Examples of the new alerts include identifying potential rig blackouts, mud pump expendable failures, stuck pipe and well control procedural compliance. New alerts like these have been a key driver for installing REX directly on the rig’s servers, Mr Olson said. “For almost all the alerts we have on REX, the latency doesn’t necessarily affect the quality of the system. It’s not diminished because, for the most part, these alerts are not for things that you need to know the sec- ond they happen. But as we’re getting more in depth with things like well control alerts, we want to know things the second it hap- pens so that we can take quick action.” Patterson-UTI says it expects to complete a pilot installation of REX on 10 rigs in Q4 2023, then install it on all rigs by Q1 2024. Addressing dropped object risk Like with the rest of the drilling industry, alarm systems are nothing new for Helmerich & Payne (H&P). The company has inte- 18 grated numerous custom alarms measuring various performance objectives for its customers. It has an alarm system monitoring excess engine use, which aims to conserve engine power on the rig. It also has alarm systems for avoiding wellbore collisions downhole. However, some of the technologies and systems the company has been developing recently have centered around the mitiga- tion of dropped object risk. One such technology H&P is set to launch is aimed at keeping people away from the pipe delivery system (PDS) during high-risk activities: PDS Redzone. “We’re approaching this from our most vulnerable areas,” said Mike Lennox, H&P Senior Vice President, US Land . “Where’s our greatest opportunity? That’s around the PDS and the rig floor. That’s our greatest exposure.” Existing procedures are already in place to reduce the likeli- hood of serious injury in the PDS area: using proper buffer zones and barricades, equipment inspections, and thorough pre-job planning to ensure all equipment components are in good work- ing order and safety procedures are followed. Still, there remains a risk of serious injury or fatality (SIF) from a dropped tubular in the red zone, which H&P defines as a 45-ft radius from the PDS rack. The PDS Redzone computer vision system uses a neural net- work to break the individual frames of the incoming video into smaller parts and detect essential features. The neural network is trained on large data sets containing images or videos annotated with the positions of critical points, such as the top of the PDS or features of a human body. It learns to detect and associate these key points with specific body parts or features, enabling it to esti- mate the position and movement of an object or person in new, unseen images. When the PDS is activated, and operational conditions satisfy the specified logic criteria for detecting a person or persons, the system automatically triggers an audible alarm and strobe to alert the individual of entry into the exclusion zone and simultane- ously stops the PDS hydraulics. Improvements to the system have been made as a result of field testing on rigs in the Permian Basin. Refactoring the PDS Redzone code has resulted in a 150% frame rate increase, wider field of view, and four times more pixels per image. The camera system also was relocated from under the rig floor to near the winch on the back of the PDS to primarily focus on the top of the PDS. Further , H&P aims to establish an extended management pro- tocol for the exclusion zones beyond the red zone atop the PDS, aligning with existing practices of employing physical barricades and buffers. “We want to set it up so that there’s a buffer on all sides of the pipe delivery system. Instead of just monitoring the area in the immediate vicinity of the PDS, we want to monitor further out because the exposure of tubulars is still great,” Mr Lennox said, adding that the company plans to fully launch the app throughout its fleet sometime in the next year. Another H&P app, Rough Drilling, was also designed to mitigate the risk of dropped objects during periods where the level of vibra- tion of the drillstring downhole exceeds anticipated levels . The company defines “rough drilling” based on standard devia- tions of hookload and torque. The app calculates these deviations in real time: If it detects that the deviations are significant enough J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DI G ITAL TR AN S FOR MATION Seadrill has worked with Brazilian technology developer Altave on installing the Altave Harpia PPE detection and red-zone monitoring system on its three drillships working offshore Brazi l, including the West Tellus. Using cameras installed at high- traffic areas such as the pipe deck , the footage captured is processed by AI and machine learning algorithms within the system to detect the absence of PPE among rig personnel. The driller is alerted if the system detects such an absence. to potentially cause severe vibrations – the thresholds for “rough drilling” depend on the rig and the formation being drilled – it dis- plays a red placard on a monitor in the driller’s cabin and sounds an alarm alerting the driller to clear the rig floor. If that alarm goes past a predetermined period of time, another alarm will call for an inspection of the traveling equipment and mast to identify any potential issues requiring intervention. “ Even though we may not be able to eliminate rough drilling, we can prevent the exposure by ensuring our employees are aware of the hazard and stay off the rig floor during these activi- ties. We have to keep our employees’ safety in mind and remove those exposures,” Mr Lennox said. The Rough Drilling App was launched in 2021 and is currently available on all H&P rigs. Monitoring for absence of PPE Over the past year, Seadrill has deployed three of its drillships to Petrobras’ Búzios field offshore Brazil for exploration work: the West Carina and West Tellus in September 2022 and the West Jupiter in February this year. For all three rigs, both operator and contractor agreed to install Altave Harpia, a Brazil-developed PPE detection and red zone management system that alerts drillers of potential accident risk in the red zone. The technology utilizes computer vision to interpret data gathered from six cameras connected to terminals, which are hardware systems that handle the input and output of data . The cameras are installed on the pipe deck, rig floor and the riser deck – all high-traffic areas with a lot of moving equipment. AI and machine learning algorithms built into the software are used to detect the absence of PPE on people located within a red zone. In case that is detected, the software sends an alert to the driller, who can then decide on an appropriate course of action. Besides a pop-up alert in the driller’s cabin, alerts can also be seen on monitors installed at the bridge, the companyman’s office, the toolpusher’s office, deck pusher’s office, HSE office and at each crane located on the rig. A camera-based system like Altave Harpia allows Seadrill to have better granularity in analysis compared with previous monitoring systems. This can improve monitoring efficiency, Mr McConomy said, as it minimizes the errors derived from human interpretation of data. “Because the camera system is powered by AI, it’s an efficient tool for detecting and managing safety issues in real time and for sending alerts to prevent accidents. Machine vision with AI is what’s allowing for certain patterns to be automatically detected, like differentiating a hand with gloves from one without, or deter- mining if a person is in the red zone. Tracking and trending com- mon alerts provides us with simple opportunities to improve our operations planning,” he said. While Seadrill has not released any safety metrics from the Brazil rigs, Mr McConomy said he’s confident that computer vision technology will become an important tool in the driller’s safety toolbox. “I’m a firm believer that cameras will play a huge role as the sensors of the future. We’re just scratching the surface of their capabilities and the technological advancements in not only cam- era quality but also processing power. Brazil is currently our test bed for this particular technology, but the quality of the system is continuously improving. We could benefit from standardizing this system across our rig fleet,” he said. DC D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 19 DI G ITAL TR AN S FOR MATION Sensor advances enhance data accuracy, drive more automated workflows Industry finding innovative ways to improve data collection for applications like rig equipment monitoring and flow measurements while prolonging sensor durability in harsh environments BY STEPHEN WHITFIELD, ASSOCIATE EDITOR A mid the digitalization boom in drilling, the deployment of accurate and effective sensor technology has become cru- cial to companies’ efforts to monitor specific operational parameters, whether for equipment maintenance on the rig or as an enabler for increasingly data-dependent automation tools. “Our drilling automation services fundamentally hinge on robust measurement, interpretation and control systems, all orchestrated to enhance well construction,” said Matthias Gatzen, Well Construction Segment Digital Director at Baker Hughes. Highlights Battery-powered tri-axial sensors will be tested on an ultra-deepwater drillship in the US Gulf to automate vibration data gathering, streamlining the equipment condition monitoring process. Manufacturers are deploying new materials in sensor technologies to improve light output and sensitivity, which enable faster and more accurate measurements. NBIR light sources, already used in things like night vision goggles, have recently been adopted for gas imaging and are enabling better gas detection systems in the oilfield. 20 “Utilizing the right sensors, whether they’re proprietary sensors that we design or third-party sensors that we select, allow us to collect precise data at the right time and place. That’s essential for marrying practical field operations with the advanced techno- logical solutions we’re seeing more and more of in the industry.” Sensors also play a valuable role in keeping people safe at the rig site. New systems have been developed, for instance, to better detect harmful gases that could be present on the rig, allowing drillers to quickly investigate and prevent fires or explosions. “In situations involving hazardous gases, it’s critical for facili- ties to respond quickly to incidents, from detecting gas leaks as they happen to making informed decisions and mitigating risks wherever possible,” said Jessica Wood, VP and General Manager – Industrial Processing and Safety at Honeywell. “If these leaks are not detected, they could result in devastating injuries. It’s really important for site managers to implement a layered gas detection system in which independent, yet interrelated, layers of protection work together through various technologies, including sensors.” In this story, DC speaks with sensor manufacturers and an offshore drilling contractor about new sensing technologies and how their boundaries are being tested. Automating data collection from primary load path drilling equipment Vibration is one of many types of data Seadrill uses within its Asset Lifecycle Management (ALCM) platform to validate equip- ment condition and identify when a major overhaul is required. Currently, however, getting that data is a labor-intensive, manual J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DI G ITAL TR AN S FOR MATION Above: Seadrill plans to conduct a proof-of-concept trial with a third-party engineering firm on battery-powered tri- axial vibration sensors on its West Neptune drillship . The sen- sors will gather vibration data from the rig’s primary load path equipment, which Seadrill’s Asset Lifecycle Manage- ment platform can use to look for patterns that align with equipment malfunction. Currently the data is taken manually by rig crews, so automating the process will help to reduce the workload of those personnel. Right: Reuter-Stokes, a division of Baker Hughes, offers gam- ma-ray sensing solutions utilizing scintillators filled with ce- rium bromide and lanthanum halide crystals. These crystals provide better light output, enabling faster data acquisition with more accurate measurements. process that can often disrupt the operation of primary load path drilling equipment. Automating that measurement process will be critical, both in helping to mitigate the potential negative impacts of those disrup- tions and to improve the ALCM platform, said John Dady, Director of Technical Services at Seadrill. “We need to eliminate the need for unnecessary manual data collection. That’s going to be big in freeing up the rig crew to handle more critical preventative and corrective maintenance tasks.” To measure vibration specifically, Seadrill has been working with a third-party engineering firm on a proof-of-concept trial of a battery-powered tri-axial vibration sensor. The sensors can be activated to take a sample vibration measurement via an RPM setpoint detection algorithm. The vibration data gathered by the sensors are first sent over a conventional Wi-Fi network to the engineering firm’s cloud computing network for display and status reporting, then to Seadrill’s cloud for analysis within the ALCM platform. As the platform is directly connected to the D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 21 DI G ITAL TR AN S FOR MATION Eni pilots software mapping emissions, fuel use to specific activities STEPHEN WHITFIELD, ASSOCIATE EDITOR In drilling operations, reducing the fuel consumption of diesel generators at the rig site has become a major focus for both operators and drilling contractors alike, which means obtain- ing accurate consumption and emissions data is critical to fully understanding a rig’s carbon footprint. Last year, Eni and Kwantis, a digital services provider , devel- oped a greenhouse gas (GHG) software to track and map the CO 2 -equivalent emissions associated with the fuel consump- tion on Eni-operated rigs. The tool collects and analyzes data from sensors placed at high-emissions points throughout the rig and outputs the data in near-real time. “The main purpose was to analyze the emissions per- formance of the well construction process,” Daniele Farina, Technology Innovation Project Engineer at Eni, said in a pre- sentation at the 2023 Offshore Technology Conference in May. “Let’s compare the monitoring systems for emissions that our contractors use with this one so we can get a better overall picture of the greenhouse gases coming from the rig and from constructing the well. This will help us find the most emis- sions-intense activities in our drilling operations.” The software was installed as a module on the data analyt- ics platform Eni uses to aggregate and analyze data from its operated rigs. The system relies on the aggregation of high-fre- quency data gathered daily from sensors placed on rig equip- ment to provide an overall picture of the rig’s fuel consumption and emissions. It collects fuel consumption data from the rig’s engine on a given day, along with sensor data measuring power consumption of various pieces of rig equipment, and combines Daniele Farina, Technology Innovation Project Engineer at Eni, talked at the 2023 OTC about a project aiming to iden- tify the most emissions-intense activities on a rig. Continued on page 23 22 “We need to eliminate the need for unnecessary manual data collection. That’s going to be big in freeing up the rig crew to handle more critical preventative and corrective maintenance tasks.” - John Dady, Seadrill rig control system, it will automatically send a corrective work order to the driller if it recognizes vibration patterns that align with equipment malfunction, indicating a need to inspect the equipment. “The sensor has been extensively deployed in other industrial sectors, managing remote sites that necessitate the use of equip- ment that can handle rigorous daily operations in rough environ- ments, but they have not been used on an offshore rig,” Mr Dady said. “We think that, because they’ve shown durability working in different environments, they’re an ideal choice for offshore since that environment demands robust and dependable equipment.” The pilot project will be conducted on the West Neptune drill- ship, which Mr Dady said was selected because of its location. The rig is working in the US Gulf of Mexico, close to the Seadrill’s Houston office. Installation of the sensors on the rig, as well as any necessary ISIT (information systems and information tech- nology) upgrades to support the sensors, is expected to be com- plete by the end of this year. However, that time line will depend on Seadrill’s ability to access the primary load path drilling equipment, which includes the drawworks, crown block, traveling block and top drive. This can only be done during maintenance periods when the BOP is brought to the surface between wells and changed out with another BOP. Once the sensors are installed, the pilot will run for three months, during which time the vibration data gathered from the sensors will be measured against manual measurements. If the sensors prove reliable, Seadrill plans to install them across its rig fleet over the course of 2024. “The time frame we set for this project should give us an idea of how well the sensors and system as a whole performs,” Mr Dady said. “The sensors are giving us much more data than the manual measurements do, with the major benefit of not having to take time out of service and take the measurements. That said, I believe the biggest benefit is the fact that we won’t need the rig crew to go out and take these measurements anymore, reducing the burden on them.” Improving sensor material quality Baker Hughes has multiple brands, including Druck, Panametrics and Reuter-Stokes, devoted to designing sensors for the tools it uses to gather and process data for the monitoring systems its customers use in the oilfield. J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DI G ITAL TR AN S FOR MATION Continued from page 22 Honeywell’s Searchline Excel Plus gas detector is designed to identify leaks of combustible and volatile hydrocarbon gases, which can negatively impact safety on the rig. Through its Reuter-Stokes division, the company has devel- oped gamma ray sensors that provide greater light output, energy resolution and sensitivity compared with previous models. These sensors, along with third-party sensors, are used to collect and feed data into Baker Hughes’ automation solutions, wireline log- ging tools and intelligent production systems. They can also aid in directional drilling, which requires powerful detection systems that can withstand high temperatures, shock and vibration. “Our drilling services require high-precision sensors for a comprehensive understanding of downhole environments and formation characteristics. The better our sensors are, the more we can help our clients optimize their processes, maintain critical margins and see noticeable time and cost savings in their opera- tions,” said Ricardo Tirado, IPS Product Line Director. As drillers and operators seek to drill deeper, faster wells while achieving precise wellbore placement, the limitations of these sensors have become more apparent. To improve sensor quality, Baker Hughes has looked to improving their material . Sodium iodide crystals are commonly used in gamma ray sen- sors. The crystals absorb gamma radiation and emit a burst of light, which is collected and turned into a signal by a photomul- tiplier tube. The detector’s electronics then grab that signal and store it for transmission. However, sodium iodide gamma sensors increase light loss and slow pulse response times when operating in elevated temperatures. them with daily drilling report (DDR) data input by rig crews. This allows the system to correlate the fuel usage and power consumption with a given operation listed on the DDR. This combination of DDR data, equipment power usage and fuel consumption data trains the software to automatically discriminate between different operations, such as tripping, drilling, circulating and reaming. Effectively, the system associ- ates fuel consumption and equipment power usage with a given operation, allowing it to identify the rig state in real time. This data is displayed on an interface along with the power con- sumption and fuel usage. An algorithm built within the software converts the fuel consumption to GHG emissions, and the sys- tem can then associate the emissions to given equipment and activity on the rig. The emissions calculation is also displayed in real time. In 2021, Eni and Kwantis conducted a field trial covering 12 wells from seven workover rigs and two wells from two land drilling rigs operated by Eni. The average GHG emissions of each well was measured and compared against baseline averages using historical data for the same rigs in 2020. The two sets of values matched closely enough to confirm the consistency of the tool in assessing emissions coming from operated rig activities. A second field trial was conducted on a jackup in the US Gulf of Mexico in 2022. For this trial, the companies sought to test the tool’s accuracy in allocating GHG emissions to a given activity. Six categories of activities were devised – drilling, drilling connection, reaming/washing, casing run, tripping and other – and combined rig sensor data with power metering to calculate the amount of energy required during each activity category. These values were compared against emissions and fuel consumption estimates provided by the drilling contractor. The data gathered from the emissions tool in the second field trial showed a 4.8% increase in GHG emissions compared with the drilling contractor estimates, which Mr Farina said was a “reasonable” discrepancy and confirmed the consistency of the emissions tool. The tool also showed that tripping operations accounted for around 75% of the overall emissions, even though only 40% of this trial period was spent on tripping activities. Mr Farina said this was mainly due to several weather-induced operational stops, which impacted tripping at restarts. Eni and Kwantis are currently evaluating the results of the field tests and determining how to move forward with incor- porating the tool into Eni’s operations. Mr Farina said the companies are looking to increase the frequency with which it can acquire fuel consumption data – the sensors used in the field tests processed fuel usage in 5-second intervals – as well as algorithms that can connect the types of fuel blends used for engines with emissions. “This is continuous work that we’re doing on this system today,” he said. “Our focus right now is on trying to improve the system so we can improve the quality of the operation itself.” DC D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 23 DI G ITAL TR AN S FOR MATION “In situations involving hazardous gases, it’s critical for facilities to respond quickly to incidents, from detecting gas leaks as they happen to making informed decisions and mitigating risks wherever possible.” - Jessica Wood, Honeywell Siemens’ FS230 clamp-on ultrasonic flow system, launched in 2020, was developed to improve the accuracy in liquid and gas flow measurements, even in harsh conditions. To combat those limitations, the company developed gamma ray scintillator sensors with lanthanum halide and cerium bro- mide crystals, materials that have a higher density than sodium iodide. The higher density levels improve the sensitivity and spectral resolution of the sensors, enabling faster data acquisi- tion with more accurate spectroscopic measurements. They also increase the sensor’s life by reducing high-voltage requirements. Baker Hughes currently offers the crystal combinations in cus- tomizable sensor configurations, with different options for crystal size and aspect ratio, optical interfaces design and construction and various mechanical interfaces. The company noted that, while lanthanum halide offers better light output than cerium bromide and sodium iodide, lanthanum has a naturally occurring radioactive lanthanum isotope close to that of potassium . In certain applications, this can contribute to background radiation. Cerium bromide has less sensitivity than lanthanum halide, but background radiation is not an issue. Siemens’ Sitrans FSS200 Widebeam clamp-on sensors are attached to pipe walls to capture ultrasonic signals gener- ated from fluid flow. A digital sensor link built into the sensor sends the data to a transmitter for processing. 24 Gas detection devices Different types of gases, such as toxic, combustible or volatile gases, can create hazards for workers on the rig, which means gas detection is a crucial part of the safety regimen on a rig. Early detection helps field personnel find and repair leaks quickly, reducing the risk of major accidents. The technology for communicating gas hazards has improved over the years, with real-time monitoring now commonly avail- able. In addition, the sensor networks that measure environmen- tal factors are becoming more connected to one another, which helps onsite leaders identify problems sooner . This connectivity is a key feature in a line of gas detection sensing technologies launched by Honeywell in late 2021, the Searchline Excel Plus and Searchline Excel Edge. These open-path gas detectors have improved ability to stay online in adverse weather conditions. Open path gas detectors are designed to identify the presence of combustible levels of hydrocarbon gases in open areas. They consist of an infrared source that transmits a focused beam of infrared light across an area to be monitored into a detector located some distance away. Gases passing between the trans- mitter and the detector interfere with the infrared beam, and the detector uses this drop in energy to determine that gas is present – the amount of energy decrease is proportional to the level of gas present. “Open path gas leak detection creates this invisible line that senses the presence of flammable and toxic gas passing between the transmitter and receiver. With these detectors, we’re utilizing improvements in optical coupling between the transmitter and receiver to help these devices maintain consistent operational uptime at long distances and in tough conditions,” Ms Wood said. Unlike a conventional point gas detector that measures the amount of gas present in a specific area, an open path detector measures the quantity of gas in an area that covers the distance between the transmitter and receiver. This allows a single open path detector to monitor larger areas than point gas detectors. Since the open path detector relies on its ability to measure light intensity, harsh weather conditions can affect the visibility of the source light. A standard open path detector uses a non-dis- persive infrared light source, which analyzes the concentration of target gases based on their characteristic infrared absorption. These light sources are not filtered, so when the light beam passes through and interacts with the sample gases in a chamber, only a portion of the optical energy is absorbed by the gases at their J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DI G ITAL TR AN S FOR MATION characteristic absorption wavelength. In harsh weather condi- tions, where light visibility can be limited, this makes it more difficult to detect the presence of gases . The Searchline detectors use a near-band infrared (NBIR) light source, which requires less absorption and scattering to detect the concentration of gases. NBIR light sources are used in a variety of applications, including thermal imaging, fiber optic commu- nications and night vision goggles, but only recently have been adopted for gas imaging. The detectors also feature Bluetooth connectivity, which allow for quicker device maintenance and calibration for rig crews. Field personnel can also connect the detectors to Honeywell’s Fixed Platform app from 60 ft away to run performance checks, reducing the need for them to climb to high locations to check devices if they are located off the ground. Flow measurement accuracy Achieving repeatable and accurate flow measurements at the wellsite – for instance, measuring the flow of hydraulic fracturing fluid as it goes downhole and the flowback that comes up from the well at the wellhead – is a critical but challenging function. Traditionally, turbine meters are used to measure flow rate, but their moving parts do not mix well with grit or sand, and the sen- sors within them can often show wear, reducing measurement accuracy and increasing nonproductive time. Siemens has worked to minimize durability issues in flow measurement by designing electronic flow meters, launching its FS230 flow meter in 2020 for hydrocarbons. At the heart of the meter is the Sitrans FSS200 Widebeam clamp-on sensor, a Lamb wave transit-time sensor developed for flow measurement. Widebeam sensors use an FS-DSL (digital sensor link) electronic module that captures ultrasonic signals generated from the fluid flowing through pipe. Those signals are then evaluated by the sensors and recorded as measured values. The analog values are then digitized and sent to a transmitter, which processes, corrects and saves the data. “With Widebeam, we’re really looking to improve the accuracy in liquid and gas flow measurement, even in difficult conditions,” said Paul Limpitlaw, Head of Business Development – Oil & Gas, Minerals Measurement Intelligence at Siemens. “We’re intelli- gently integrating the pipe wall into the measuring system, and that’s going to lead to significantly stronger sound waves spread out over a broad section of the flow profile. The sensors’ ability to transmit waves that are individually adapted to the resonance range of the pipe for each measurement is really key to acquiring the data needed for high-precision measurements.” Different versions of the flow meter can measure either oil or gas. The gas meter is applicable for things like check metering and flow survey verifications, while the oil version can be applied to things like process control metering and leak detection. DC 55 THE C O N N E C T I O N ADVANTAGE AD 4 4-1/4" -1/1/1 4/4/ " ID IDIDI L LARGEST LA A RGE G ES GE E S T ID IDIDI O ON N T THE TH H HE E MARKET M RKE MA K T KE 51,800 51,1,1 8 00 FT-LBS* FT-T-T LBS* MAKE M K KE E UP MA U TORQUE T RQUE TO U UE CAPACITY C A PA P CICIC TY CA SERVICE S ER SE E R VIVIV CE C & REPAIR REP E PA EP P A IRIRI CENTERS C EN CE E N TE T ER E R S www.drillpipe www.drillpipe.com (832) 230-8228 IN ININI YOUR Y UR YO U PLAY P LA PL L A Y *Based on 1.00 FF @ 60% Yield Strength D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 25 DI G ITAL TR AN S FOR MATION Chevron leverages smart alarms, multidisciplinary staff at support center to monitor process safety, develop fit-for-purpose solutions Wells Decision Support Center, enabled by advances in real-time data and digital tools, can provide ‘infinite’ support for field personnel BY JESSICA WHITESIDE, CONTRIBUTOR At Chevron, the primary responsibility for maintaining well control is placed on indi- viduals at the rig site. But the company has a critical second line of defense: its Wells Decision Support Center (DSC) in Houston. The DSC uses advanced digital tools and pods of cross-functional teams to monitor and analyze real-time data from wells that may be thousands of miles away to help field personnel make bet- ter decisions affecting process safety and performance. “Ultimately, with continuous improve- ment in our data quality and our digi- tal tools, the support that the DSC can provide truly is infinite,” Alexa Baker, Drill Site Manager for Chevron, said in a presentation at the Offshore Technology Conference in Houston on 1 May. Chevron formed the DSC in 2011 to help prevent catastrophic safety events in deep- water and complex wells. In the years since, the growth of the company’s uncon- ventional business in shale and tight rock plays, combined with advancements in data and digital capabilities, has created opportunities for DSC support to be applied more broadly. Today, the center’s remit encompasses wells operations across all of Chevron’s asset classes, and the DSC teams strive not only to help manage process safety but also to develop workflows and solutions that improve operational efficiency. The center also performs remote directional drilling and can drill multiple wells simul- taneously. DSC staff have diverse background s encompassing wells operations, engineer- ing, IT and geolog y and geophysic s. Their co-location within the DSC, typically five or six individuals to a pod, has led to significantly more collaboration oppor- tunities, Ms Baker said, and has resulted in reduced costs and improved safety by reducing headcount on the rigs. The DSC pods are also organized by asset class, facilitating the sharing of applicable lessons learned, she added. Further, stan- dardization of data – whether time or depth based – has aided collaboration by making it easier to pool data across business units . Real-time monitoring In unconventional operations, geosteer- ing specialists provide 24/7 support, and engineers rely on smart alarms to monitor for process safety. For deepwater and com- plex wells, the DSC has real-time opera- tors (RTOs) providing 24/7 monitoring of live data during all phases of operations. RTOs, who all have rig and mud logging experience, look for kick indicators and communicate with rig crews about any abnormalities. Their work is complement- ed by pore pressure specialists who flag changes that might indicate an upcoming well control event. Smart alarms are also available as an additional line of defense for well control. To improve monitoring capabilities, the DSC developed a comprehensive sys- tem of process safety smart alarms to replace traditional high/low alarms that produced too many false positives. The smart system, which enables a single DSC professional to monitor kick indicators on multiple rigs at a time, can read real-time data and eliminate any explainable events, reducing false alarms and improving reli- ability, Ms Baker said. To help monitor process safety at Chevron’s Wells Decision Support Center, smart alarms have replaced traditional high/low alarms, which had produced too many false positives, said Alexa Baker, Drill Site Manager, at the 2023 OTC in May. 26 J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R “Chevron support center” continued on page 29 DI G ITAL TR AN S FOR MATION MIT-led project incorporates hard-to-measure data to develop digital twin for drilling risers ABS becomes project’s newest member as consortium begins to build demo twins that will improve motion prediction, extend asset life BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Vortices, or closed circular flows of air or water, are the primary cause of motion for marine drilling risers. Understanding when these vortices may occur, as well as the potential force of vortex-induced vibrations (VIVs), is important in predict- ing potential fatigue damage to the riser. However, VIVs are still difficult to antici- pate due to the geometric complexity of the riser configuration, as well as the sheared and unsteady nature of ocean currents. Over the past five years, research- ers from the Massachusetts Institute of Technology (MIT) and Brown University have been working with a consortium of operators, drilling contractors and ser- vice companies to create a digital twin applicable to marine risers, DigiMaR. The twin was trained using a variety of data like field sensor data, computational flow dynamic simulations and existing data- bases, and has semi-empirical codes that incorporate various assumptions about the data to predict VIVs. The result is an accu- rate reconstruction of riser motion and prediction of fatigue damage, which can help to optimize the placement of sensors on the risers and extend their field life. “Artificial intelligence has become an essential tool for the design and opera- tion of complex systems, and digital twins provide an unprecedented capa- bility to explore the parametric space,” said Michael Triantafyllou, Professor of Mechanical and Ocean Engineering at MIT. The digital twin utilizes a parametric representation of the data characterizing VIV behavior in a series of databases, which Dr Triantafyllou said would provide a comprehensive view of how VIVs affect riser motion. The twin takes streaming data from physical marine risers and their environ- ment and feeds it into AI predictive mod- els and neural networks. Once the data is assessed and interpreted, the twin outputs information characterizing the magnitude of parameters like the riser’s displacement, velocity and acceleration. Those outputs can then be used to predict the potential fatigue damage of the structure. Additional machine learning algorithms within the digital twin also predict optimal times for servicing of the riser. During the 2023 Offshore Technology Conference (OTC) in Houston on 2 May, the American Bureau of Shipping (ABS) announced it had joined the project to provide third-party classification services for the design of the digital twin, which is now being incorporated into the work- flows of major operators. “As a safety- focused organization, we’re able to share the insight we have learned with MIT to help support the adoption of new tools and systems that can improve safety and per- formance,” said Patrick Ryan, ABS Senior VP and Chief Technology Officer. The consortium includes operators Petrobras, ExxonMobil and Shell, as well as drilling contractor Saipem. Digital twin design process Algorithms used in the digital twin were developed under a three-pronged approach. First, active learning algorithms were used to enhance the capabilities of the codes typically used to build a model of a marine riser. Digital twins of marine risers usually rely on the data captured from the field that measure the motion of fluids and the forces, such as VIVs, acting on solid bodies immersed in fluid, also known as hydrodynamic data. This data is stored into a database, while a separate database houses data modeling the geom- etry of the riser. Because this method is not comprehen- sive enough to adequately measure riser motion, Dr Triantafyllou said, other param- eters such as the Reynolds number (a ratio that helps predict fluid flow patterns in different situations), surface roughness of the riser and external turbulence were included into the database. Additionally, long-term issues that can affect riser motion, such as biofouling and the impact of equipment age on structural integrity, are impossible to measure in a hydrodynamic database, making long- term prediction and monitoring even more challenging. To handle this challenge of incorpo- rating hard-to-measure data in the digi- tal twin, the MIT-led team developed an active learning neural network that uses algorithms that can interact with a user to sort unlabeled data. By interacting with the user, the network learned how to asso- ciate certain unlabeled data with certain parameter labels, eventually taking over the task by itself. MIT also developed the Intelligent Towing Tank (ITT), a robot that is capable of learning about complex fluid-struc- ture phenomena, to test the validity of the active learning network. The robot designed, performed and analyzed experi- ments, using field data, to explore and map the complex forces that govern VIVs. An “explore-and-exploit” methodology also helped to reduce the number of experi- ments needed, improving the efficiency of the active learning network. The second prong of the algorithm devel- opment involved creating a neural network (LSTM-ModNet) that could use sensor measurements to construct and analyze the motion of a riser in deepwater. The net- work allowed the researchers to combine different types of sensor measurements, D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 “Digital twin” continued on page 29 27 DI G ITAL TR AN S FOR MATION Supercomputers and CCS key to Petrobras’ efforts to build a low-carbon energy ecosystem NOC relying on powerful data processing to reduce number of wells drilled while seeking regulatory support to develop industrial CCS BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Meeting the demands of the energy transi- tion will require operators both to adopt new technologies that can improve effi- ciency in oil and gas E&P and to deploy low-carbon solutions like carbon capture and storage (CCS). Petrobras is aiming to reduce its envi- ronmental impact by combining low-car- bon energy development with comput- ing systems designed to reduce geologi- cal uncertainties in exploration and, thus, reduce the number of wells needed to develop new fields. This will lead to sig- nificant cuts in emissions while enabling increased efficiencies, which will allow the company to continue exploring new offshore frontiers, said Joelson Mendes, E&P Executive Director at Petrobras. “In our vision, oil and gas is an enabler of the low-carbon economy,” Mr Mendes said. “We’re revisiting our strategy and bringing light to our priorities regarding the energy transition, but at the same time we’re reinforcing that oil and gas produc- tion is compatible with the energy transi- tion. A digital and data-driven exploration and production strategy will enable us to create positive results here.” During the 2023 Offshore Technology Conference in Houston on 2 May, Mr Mendes described Petrobras’ vision for a “low-carbon energy ecosystem,” or a busi- ness that integrates E&P in frontier areas, such as the Brazilian Equatorial Margin, with low-carbon energy sources such as offshore wind energy and hydrogen produc- tion, to reduce its environmental footprint. Data analytics and computing power are lynchpins to this ecosystem. Over 28 the past couple of years, Petrobras has launched a pair of new high-performance computers (HPCs), Pegasus and Dragon, that are running machine learning algo- rithms to process geological and geo- physical data. Pegasus has a processing capacity of 21 Petraflops, roughly equiva- lent to the processing power of 150,000 laptop computers, while Dragon provides 14 Petraflops. Pegasus and Dragon currently rank 35th and 73rd, respectively, on the Top500 proj- ect’s list of the most powerful non-dis- tributed computer systems in the world. Petrobras also has two older HPCs, Fenix and Atlas, that came out in 2019 and 2020, with less processing power. Because processing geophysical data to create seismic images involves complex mathematical equations, having these HPCs has led to a significant reduction in data processing times, Mr Mendes said. He also noted that the four HPCs provide Petrobras with enough processing power to deploy high-usage third-party software programs like EXP100, which uses AI and machine learning to predict the likeli- hood of hydrocarbons being present in a given reservoir. That reduces the number of exploration wells needed and, in turn, reduces the company’s emissions. “We have a database with 70 years of operations, a collection of a vast amount of data from different fields and develop- ments. Machine learning is necessary to help us capture and process all of this data that’s available to us, and it’s also impor- tant to have sufficient processing capacity. High-performance computing is a step- As Petrobras expands its CCS efforts, the NOC is seeking to establish a regu- latory framework in Brazil around eco- nomic activities related to CCS, said Joelson Mendes, E&P Executive Director. Mr Mendes spoke at the 2023 OTC on 2 May in Houston. ping stone to achieving greater efficien- cies in our operations. We’re foreseeing an increase in the use of predictive models that can help us reduce the number of wells we have to drill,” he said. Low-carbon energy efforts like CCS make up the other side of the business ecosystem that Petrobras is building for the energy transition. In its 2023-2027 Strategic Plan, the company outlined its ambition to store 80 million tons of CO 2 by 2025. In 2022, it stored 10.6 million tons of CO 2 , which accounted for approximately 25% of the CO 2 stored globally that year, according to the Global CCS Institute. Mr Mendes noted that Petrobras is studying the implementation of a CO 2 cap- ture and geological storage hub. The proj- ect would involve the construction of pipe- lines from industrial facilities and E&P projects into a saline aquifer reservoir with a potential storage capacity of 25 million tonnes/yr. A pilot project is under development near a Petrobras-owned natural gas pro- cessing facility in Cabiunas, Brazil, to sequester up to 100,000 tonnes/yr of CO 2 J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R DI G ITAL TR AN S FOR MATION over two years. This will serve as a testing ground for the viability of storing CO 2 in a saline aquifer and will involve geophysical studies of the drilling of injection wells in the aquifer. Petrobras says it anticipates receiving government approval to proceed with the project later this year. Because of projects like these, the regu- latory environment in Brazil will be crit- ical in helping Petrobras meet its CCS goals, Mr Mendes said. He noted that an expansion into industrial CCS represents a departure from the traditional role of the national oil company; as such, the company’s statute, which is established by the Brazilian government, does not include a regulatory framework or busi- ness model for CCS. The bulk of the CO 2 that Petrobras stored last year came from the development of pre-salt fields, but the CCS hub includes plans for the company to find industrial partners to provide CO 2 for storage. In 2022, Petrobras sponsored a bill that would regulate economic activities related to the permanent storage of carbon dioxide. That bill is still under discussion in the Brazilian Senate. “Collaboration is essential to a sustain- able energy transition,” Mr Mendes said. “By working together, businesses, gov- ernments and regulators can scale up the actions that enable the low-carbon energy ecosystem. Latin America is well positioned with regards to these energy projects. It’s a good location to develop energy ecosystems.” DC “Chevron support center,” continued from page 26 The DSC’s performance pods, formed in 2019, combine engineering support with data, digital tools and modeling software to develop performance-enhancing work- flows that target issues such as major nonproductive time. Ms Baker pointed to one example of a win for reduced cycle times in unconventional wells in the Permian Basin, when DSC analysis of longer lateral drilling found a direct correlation between friction factors while tripping out of the hole with a bottomhole assembly and the probability of getting casing to bottom. “Now our operations engineers are cre- ating the models, watching our real-time friction factors and communicating with the rig sites when our wellbore is clean enough that we know we will get casing to bottom,” Ms Baker said. “This is just one example of the type of fit-for-purpose engineering support that we can provide based on the challenges that we see in each business unit.” She cited another example of success in the deepwater space, where the DSC has been able to monitor high-temperature wells to determine which parameters are contributing the most to wellbore cooling efforts, and then create alarms around those parameters. This alerts opera- tions engineers when those thresholds approach. “Now they know what parameters they can effectively change to mitigate the tem- peratures,” Ms Baker said. “At the end of the day, we’re looking at each business unit and each asset class to develop solu- tions that fit those needs.” DC “Digital twin,” continued from page 27 twin that can accurately incorporate the complexities of riser motion. such as strain and acceleration, to recon- struct the motion of the riser, as well as fatigue, over time. The third prong involved using another neural network, DeepONet, to map a sepa- rate set of input parameters (inflow veloc- ity, riser bending, stiffness and tension as a function of water depth) against various output parameters (strain and amplitude). This network served as the predictive mechanism within the digital twin, actu- ally predicting the occurrence and ampli- tude of VIVs in a given environment. Taken together, the three-pronged approach demonstrate how machine learn- ing algorithms and deep learning neural networks can infer riser dynamics from disparate sources of data, Dr Triantafyllou said. This enables the creation of a digital Next steps “This is especially beneficial in our unconventional business units where rig counts are high and operations are not monitored by our real-time operators.” Fit-for-purpose engineering support The researchers are currently working with the operator members of the con- sortium to create demo digital twins of marine risers from current E&P projects, customizing the algorithms to fit each operator’s specific needs. “Every company involved here has a different niche application that they want the digital twin to address. You’ve got companies that are more interested in the artificial intelligence, and they want to see if the algorithms are suitable for other applications in addition to the marine ris- ers,” Dr Triantafyllou said. “Another com- pany is using instrumented risers, and they want to use the digital twin to update the predictive models that they’re using for those sensors. The demonstration will For more information, see SPE 32443, “Evolution of a Wells Decision Support Center as a Hub for Operational Excellence,” presented at the 2023 OTC on 1 May. give every stakeholder an opportunity to apply the digital twin the way they want.” ABS, which has published several guides and recommended practices on marine riser systems, will provide classification and technical services for the researchers as they customize the design of each riser in the digital twin. The goal is for each operator to begin using the algorithms in their workflows either by the end of this year or early next year. “The design and functionality of this digital twin has changed by the year, so we expect to see more changes as we talk to the companies and incorporate their designs into our system,” Dr Triantafyllou said, explaining that ABS will provide guidance to both the researchers and oper- ators on how to certify certain methodolo- gies that will be used to create the digital twins. “By the time this is ready, we should have something really powerful.” DC D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 29 OI LFI E LD WATE R MANAG E M E NT Industry builds circular water economy as it leans into recycling and reuse Water management companies investing heavily in treatment technologies and transport infrastructure as E&Ps continue to shift away from disposal wells, reduce reliance on freshwater BY STEPHEN FORRESTER, CONTRIBUTOR T he use of water in oil and gas operations has long been necessary, but water scarcity in many parts of the world — and growing scrutiny on environmental and social considerations for energy companies — has led the indus- try to refocus its attention on minimizing freshwater use and finding better ways to work with produced water sourcing and delivery. Fortunately, the industry is well-positioned to take advantage of advanced technology and engineering solutions, which are already a critical piece of their operational success, to Highlights Establishing extensive pipeline network and treatment facilities is a key step to creating a circular economy of water management, where water disposal is only a last resort. While still in early stages, beneficial reuse for produced water in applications such as farming has potential to mitigate the impact of droughts in places like West Texas. Automated solutions are helping companies to optimize monitoring and management of water treatment and transport while reducing HSE exposure. 30 improve water sustainability and optimize water efficiency. In doing so, there is outsized potential to strengthen the industry’s public perception and relationship with stakeholders. Eliminating freshwater use by expanding water recycling XRI, a full-cycle water management and produced water midstream company founded in 2013, began installing its first long-distance buried pipeline infrastructure in 2014. In the years since, the company has seen broad growth within the water management sector, said Vice Chairman and Chief Sustainability Officer John Durand. “We’ve been watching as the market has transitioned away from water management as a function largely handled internally by E&P operating companies,” he remarked. For the industry to continue to advance, Mr Durand said it must wean itself off freshwater. “After the difficult drought situation in West Texas from 2010 to 2015, there surprisingly were not a lot of people dedicated to using non-potable water to serve drill- ing and completions,” he explained. XRI, however, maintains its philosophy that the E&P sector must transition away from using freshwater for completion activities. “We believe that the future of produced water and the handling of produced water, in the Permian Basin and elsewhere, must lie in recycling and reuse,” he explained. “There is simply too much water resource being produced, between produced water and flowback, to not lean into efficient and cost-effective water recy- cling and reuse at scale.” This means a step-change was needed to build a circular water economy based on recycling and reuse, where an injection well would only be the last resort. J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R OI LFI E LD WATE R MANAG E M E NT Above: XRI has been building up its water treatment and re- cycling capabilities to better serve the drilling and comple- tion market. In February, the company brought its Evolution Pipeline into service in the Midland Basin, underwritten by long-term contracts with Chevron, XTO Energy and Pioneer. Right: By providing treated produced water at a lower cost per barrel than the injection of water into disposal wells, XRI says it hopes to provide financial incentives for E&P compa- nies to further move away from water disposal. Today, XRI handles almost 1.5 million bbl/day of produced water , which is treated at one of 30 large water recycling facilities through- out the Permian Basin. To help the industry achieve that change, XRI acquired Fountain Quail Water Management in 2019 and integrated that company’s treatment and recycling capabilities into its existing water distri- bution midstream infrastructure. Additionally, the company now has approximately 450 miles of permanent, large-diameter buried pipeline infrastructure throughout the Midland and Delaware Basins. In February, XRI also brought into service the Evolution Pipeline System in the Midland Basin. The system, which is underwritten by long-term contracts with Chevron, XTO Energy and Pioneer, is designed to alleviate overpressurization of deep disposal for- mations and mitigate seismicity risks throughout the basin. It maximizes produced water recycling and reuse by enabling E&P companies to tap into XRI’s interconnected water distribution D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 31 OI LFI E LD WATE R MANAG E M E NT Gravity’s Hull saltwater disposal (SWD), located in Howard County, Texas, can inject up to 50,000 bbl/day of produced water back into the earth. However, the company says it has been able to reduce the injection volumes needed at the Hull SWD to around 21,000 bbl/day thanks to increased produced water reuse projects with E&P companies. networks and large-scale recycling and water treatment facilities. Establishing an extensive network of pipelines and treatment facilities is a key step to creating that circular economy of water management, which can help to reduce the need to draw from freshwater aquifers. “What the Evolution Pipeline System allows XRI to do is move approximately 500,000 barrels of water per day from the central Midland Basin — where there remain seismic concerns and defined seismic response areas — down to Reagan County and Uptown counties, where XRI owns and operates full-cycle water infrastructure in the southern portion of the Midland Basin,” Mr Durand explained. “When we move water to those counties, where there’s been minimal disposal injection historically, we are trans- porting significant water quantities up and down XRI’s pipeline infrastructure, treating the produced water and moving treated recycled water to operators who want to minimize or avoid dis- posal throughout the basin.” The company is currently developing a similar set of projects in the Delaware Basin. Further, it also hopes to provide financial incentives for E&P companies to move away from water disposal, by providing treated produced water for its operator clients at a lower cost per barrel than the injection of water into disposal wells. “At XRI, we have always viewed disposal of water as a last resort only, and that philosophy and practice is not going to change,” Mr Durand stated. “It is critical that industry continues to embrace recycle and beneficial reuse as technologies continue to emerge.” Today, XRI handles almost 1.5 million bbl/day of produced water , which is treated at one of 30 water recycling facilities throughout the Permian Basin. “Disposal avoidance will continue to gain importance as a key metric of success,” he said. Disposal wells will likely still be important in foreseeable future Gravity personnel discuss operations at the Long 350 SWD in Howard County. The company says its field personnel now often see up to 100,000 bbl/day of produced water volumes being shifted back and forth between Gravity’s SWDs and ac- tive reuse projects, all located on the company’s 500,000 bbl/ day Howard County Super System. 32 Gravity Water Midstream is the water management business of Gravity Oilfield Services, which also runs a power rental solutions business. Its water management solutions include high-volume sourcing, pipeline transport, reuse and disposal through a net- work of fluid logistics assets and infrastructure. That includes fresh and brackish water storage pits, produced water gathering and freshwater sourcing pipelines, and saltwater disposal wells. The company owns almost 300 miles of pipeline, 53 saltwater disposal wells, and 12 fresh and brine water facilities with over 6 million bbl of storage capacity. Gravity also has multiple produced water recycling assets, some of which are mobile and can be moved around within its system based on E&P activity. The business is operated in three parts, said Trace Hight, Chief Commercial Officer of Water Infrastructure. The first is a sourcing segment that delivers frac water to the field; the second focuses J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R OI LFI E LD WATE R MANAG E M E NT on gathering produced water into a disposal network; and the third is a produced water reuse business. It’s the reuse business that is growing strongly, he said, with E&P customers requesting to recycle more of the produced water that Gravity gathers before treating and transporting it back to the field. In fact, that reuse business now constitutes more than half of all sourcing the company does. Year to date, 53% of the water the company has provided for hydraulic fracturing has been gathered and recycled by Gravity within its own systems before being piped back out to the field. The company says it is also working to maximize water usage between operators. “If we have additional water volumes in our systems where we can identify a beneficial use for that water with other customers, we will move those volumes to them instead of disposing of the water,” Mr Hight explained. “We are always trying to optimize that water within our systems before running out of options and having to inject it back into the formation.” Still, Mr Hight said he believes disposal wells will continue to be important for the foreseeable future. “Injection back into the formation is sometimes the most cost-effective solution for this water,” he noted. “With something like evaporation, for example, we can’t come close to managing the barrels we process each day. The more reuse we perform for our customers, the less freshwater that has to be pulled out of the ground for a hydraulic fracturing job or injected back into the ground. This is a win-win for every- one.” This doesn’t mean that the industry shouldn’t continue to examine beneficial reuse for produced water, a practice that is still in its early stages. “We continue to look for other ways we can use this water that are beneficial to all stakeholders,” he explained. “Can we, for example, treat the water sufficiently, recy- cle it and use it for irrigation for farming? As we look at droughts, water shortages and population growth in Texas, can we use this water to help with the state’s water problems?” A willingness to invest will be critical, as will open-minded- ness to looking at the water management discipline differently. “We need to find those opportunities to run pilot projects to fully gauge the impact and long-term viability of beneficial reuse,” he remarked. “It will be difficult to determine the economics of transporting the water from where it’s at to where it may be ben- eficially reused, and which party or parties are able to bear that financial burden.” The key for now, Mr Hight concluded, is finding a balance that allows E&P companies to advance sustainability while achieving their economic goals — mostly through lowering their drilling and completion costs — and rising to meet the ESG mandate of creat- ing positive impacts in the communities where they are active. Integrated water management process TETRA Technologies, an energy services and technology com- pany, believes that water management in the upstream oil and gas industry requires an integrated solution uniting capabilities in sand management, automated water treatment and recycling, and water transfer. One of the company’s patented technologies for water manage- ment is the TETRA SandStorm, an advanced cyclone technol- ogy that separates the solids and sands from the fluids during flowback. The proprietary design provides centrifugal action to accelerate and capture smaller particles while remaining under erosive velocities of the multiphase flow, with no flow restriction. Sand in the flow stream has long been an industry concern, as it can cause damage to everything from the casing to downhole equipment and even to downstream facilities, resulting in poten- tial loss of or delay in production. The technology is designed to increase the frac sand and solids capture with higher efficiency than traditional sand separators and cyclonic sand traps. It also captures much smaller particles, down to lower-single-digit micron size. “We’re eliminating over 99% of the sand and proppant that’s coming back from these produced wells using the TETRA SandStorm system,” explained Jon Malone, Director of Business Development. “This has a great benefit for our customers because, by significantly reducing that sand content, we’re effectively eliminating the risk of it damaging their production and topside equipment.” Further the system can be automated through a series of values and chokes to reduce personnel exposure and HSE risk by reducing the need to manually disconnect compo- nents and clean them. Another critical step of the integrated water management pro- cess is water reuse or recycling, which involves treating the pro- duced water to a certain key performance indicator so that it can be used during completions and hydraulic fracturing operations. Because of the industry’s need to reduce freshwater use and the wide variance in water quality and consistency across subsurface saline water, produced water and effluent water, the company has seen substantial growth in this business. In fact, it hit a milestone of 8 billion gallons of treated and recycled water within 2022. One technology that recycles and treats the produced water is the SwiftWater Automated Treatment system (SWAT). It encom- passes a combination of technologies and processes, including automated chemical injection into the influent produced water stream; a clarification process that uses dissolved air flotation technology to remove suspended matter from the water; and a low media consumption filtration technology that polishes the water. Once the produced water has sand removed and is treated, the company looks at how to transfer the water most effectively from the reuse facility to the completions site. Its TETRA Steel, a double-jacketed lay-flat hose that was introduced to the market in 2012, has a higher pressure rating than that of conventional lay- flat hoses to enable a faster rate of water transport. “TETRA Steel lay-flat hose was our entrant into that premium product space, as we saw that the industry was transferring more and more water via lay-flat hose versus buried pipeline infrastructure,” Mr Malone explained, noting the HSE benefits for operator personnel by eliminating the need to bury pipeline in the ground. The company is also working on new upgrades for the TETRA Steel hose to make it lighter and to make its couplings more resis- tant to corrosion. Additionally, construction of the hose material will be more robust and resistant to wear, Mr Malone said. “With more water being moved through lay-flat hose, we see that market growing, so we want to ensure we provide a technol- D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 33 OI LFI E LD WATE R MANAG E M E NT The TETRA SandStorm, pictured in the Vaca Muerta in Argentina, is a cyclone technology that separates the solids and the sands from the fluids during flowback. It can capture small particles down to lower-single-digit micron size. ogy that reduces operational and environmental risks for our customers .” The final piece of the puzzle is automation. The company has a web-based real-time monitoring and control system called BlueLinx that customers can use to view their treatment and recycling operations, providing immediate insight into chemi- cal processes and quality objectives. It is also used internally to monitor flowback operations and sand management for produced water recycling and treatment, as well as automated pumps that transfer water through the lay-flat hose. “All of that is integrated into the system, which is allowing operators to reduce safety risk and the occurrence of service qual- ity errors,” Mr Malone said. Upgrades are under way for the TETRA Steel, a double-jacket- ed lay-flat hose for water transport, to make it lighter and to make its couplings more resistant to corrosion. 34 BlueLinx will, for example, synchronize with the hydraulic pumps that are delivering water along the length of lay-flat hose, telling the pumps when to shut down if there are issues and opti- mizing individual pump performance for fuel consumption. Mr Malone highlighted that TETRA is working on integration with other companies’ systems and equipment, like water trans- fer pumps and valves used for emergency shutdowns, especially as operators look to bring disparate third-party service and tech- nology providers’ offerings into their own internal systems. The future of water management for TETRA, Mr Malone remarked, will involve the use of more and better technology solu- tions to ensure that more rigorous operational and financial per- formance metrics can be met. In addition, there will be nascent areas of innovation related to achieving ESG objectives. For example, the company has been vetting technologies for desalinization and has exclusive licensing agreements with KMX and Hyrec. KMX uses vacuum membrane distillation technol- ogy for high-total-dissolved-solids (TDS) levels, while Hyrec uses osmotically assisted reverse osmosis technology for lower-TDS applications. Both technologies are already commercial in other industries but are now undergoing field trials and lab-testing to determine how they can be scaled in oilfield applications. “We see the future of water management in oil and gas as being a multi-pronged approach,” Mr Malone said. “There will still be disposal wells, but we need to tackle issues like seismicity and overpressurization in the reservoir pore space. Treatment and recycling of water for completion operations will eventually allow the water to be reused for much longer, reducing the burden of disposal. “We also know that with water use increasing, drought condi- tions persisting and the need to minimize the use of freshwater resources, there will be a need for desalinization and the benefi- cial reuse of oilfield produced water moving forward.” DC J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R IADC DRILLING MIDDLE EAST Conference & Exhibition 14-15 NOVEMBER 2023 L E A L M É R I D I E N K H O B A R , A L S A U D I K H O BA R A R A B I A DIAMOND SPONSOR PLATINUM SPONSORS GOLD SPONSOR SILVER SPONSORS EVENT SPONSORS www.iadc.org/event/middle-east-2023 For more information, contact IADC by phone at +31.24.675.2252 or via email at europe@iadc.org GEOTHERMAL DRILLING New ‘walking’ tool anchors the bit to the rock, aims to mitigate stick/slip by preventing buildup of reactive torque downhole Technology is being developed primarily with geothermal drilling in mind; prototype was recently tested on Nabors land rig BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Geothermal energy is an increasingly pop- ular entry point into the renewable space for drilling contractors, as it can be accessed using conventional drilling rigs and equipment. However, deploying geo- thermal drilling at scale remains a chal- lenge because, in much of the world, the high-temperature rocks needed to produce geothermal energy are located too deep beneath the Earth’s surface for conven- tional drill bits to reach effectively. GA Drilling – which attracted $8 million in investment from Nabors Industries last year – has been working on a new tool to help drillers make deeper holes in hard formations with greater efficiency. The Anchorbit walking system aims to miti- gate stick/slip, which is a common factor hindering effective drilling in geothermal formations . “All the things we’re working on are aimed at the goal of drilling deeper into hotter rocks, where the higher energy is and which is typically igneous and met- amorphic rocks,” said Brad Ivie, VP of Engineering at GA Drilling. The Anchorbit system consists of two sets of extendable pistons installed above the mud motor that are designed to grip the formation as the bit moves downhole. Speaking at a demonstration of the Anchorbit tool, held at a Nabors facility in Houston on 25 April, Igor Kocis, CEO of GA Drilling, touted the tool’s ability to miti- gate stick/slip and, therefore, increase geothermal drilling efficiency. 36 Weight on bit is provided conventionally from the drillstring, and the pistons act in concert during drilling: While the lower set of pistons grips the wellbore wall, the upper set moves downhole. At the end of a stroke, the upper pistons extend and the lower pistons retract, essentially “walking” downhole. By effectively anchoring the bit to the rock, the tool absorbs the reactive torque generated by the bit and prevents it from building up in the drillstring – stick/slip occurs when that reactive torque releases, causing the drillstring to unwind and the bit RPM to speed up. The tool also keeps drillers from having to decrease the weight on bit, a common method to mitigate stick/slip, Mr Ivie said. “If we’re going to drill in these hard rocks, we need to put more weight on the bit so you can take a bigger depth of cut. If you spin it too fast, in a lot of these rocks, you’re going to wear the bit quickly. But the problem with putting a lot of weight on the bit is the torsional vibration. When you’re going laterally into the rock, you lose a lot of energy, and the drill pipe can get very flexible. It’s very inefficient to drill that way.” GA Drilling held a public demonstration of the tool, which has been in development for the past two years, on a land rig at a Nabors’ testing facility in Houston, Texas, on 25 April. The demonstration kicked off a week of proof-of-concept testing of a prototype, showing that the pistons could grip into the wellbore wall and prevent the transmission of force from the bit up the drillstring during the drilling of a test well. The testing also demonstrated the walk- ing capability of the tool, as the pistons transitioned between gripping the forma- tion and moving downhole. “This is our first chance to show Anchorbit as a viable product that we can bring to market, where we can show full integration with the rig,” said Igor Kocis, CEO of GA Drilling. “We also wanted to test the basic functionality and the limits of the tool to give us information and param- eters that we can use to update the design .” The current prototype can operate in a maximum ambient temperature of 300°F, the minimum temperature of rock required to generate geothermal power, according to the US Energy Information J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R GEOTHERMAL DRILLING GA Drilling’s Anchorbit tool uses extend- able pistons to grip the wellbore wall, allowing them to absorb the reactive torque generated by the drill bit as it moves downhole. Administration. However, GA Drilling says it aims to increase the tool’s temperature rating to 570°F. The company is also tar- geting an average ROP of 70 ft/hr for the commercial product. During testing, the drill bit reached a peak speed of 20 ft/hr while using the prototype. Mr Kocis said GA Drilling will take the data gathered during the initial field tests and make the necessary design chang- es. Testing for an updated prototype is planned for the second half of 2023, with a finalized version of the tool coming to market in 2024. Nabors’ investment in GA Drilling came on the heels of previously announced part- nerships with three other geothermal com- panies: Geo-Z Energy, SAGE Geosystems and Quaise. Nabors has also provided its rigs and equipment to GA Drilling for tool development and testing. Nabors’ experience in working with other geothermal companies has given the drilling contractor valuable insights, Mr Kocis said, which has been valuable in helping GA Drilling develop its new tools. “We’re basically connecting with a new technology world, working with a compa- ny that is really experienced in how to get from this stage that we’re in now with the tool into the market,” he said. “Our vision is to help make geothermal anywhere a real- ity. To have a partner like Nabors, with a lot of rigs where you can do these projects, is really helpful for us .” DC 2023 IADC Membership Directory 2023 IADC MEMBERSHIP DIRECTORY WWW. IADC .ORG The IADC Membership Directory is the definitive guide to the global drilling industry and your opportunity to connect with the global wellsite industry rig owners both land and offshore and the oil companies they serve. The Directory lists key personnel and company information for drilling contractors, oil and gas producing companies, oilfield service firms, equipment manufacturers and more. The Directory also includes information about IADC officers and staff, membership and rig statistics, IADC initiatives and more. 130 pages. Phone: +1-713-292-1945 • bookstore@iadc.org Buy this book and more at store.iadc.org IADC TECHNICAL RESOURCES PRACTICAL TOOLS TO ENHANCE EXPERTISE Copyright © 2023 International Association of Drilling Contractors D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 37 I N NOVATION S I N DE E PWATE R OTC panel: Deepwater’s low-cost, low-emission profile to keep it competitive in coming decades Companies exploring carbon credits, CCS technologies and supply chain decarbonization to fully leverage deepwater E&P’s advantages BY STEPHEN WHITFIELD, ASSOCIATE EDITOR E&P companies face a difficult balancing act. They have to address the world’s grow- ing push for renewables and environmen- tal sustainability, which impact invest- ment trends and business strategies, at the same time that factors like the COVID-19 pandemic, the Russia-Ukraine war and global inflation push them to explore for and produce more hydrocarbons. According to a panel of analysts and industry experts at the 2023 Offshore Technology Conference, this approach of increasing E&P activity while incorporat- ing low-carbon solutions will define oper- ator activity in the near- and long-term future. Deepwater oil and gas will play a key role in enabling that journey. “Deepwater production is going to grow more quickly than any other resource,” said Julie Wilson, Research Director, Global Exploration at Wood Mackenzie. “All of the hype you’ve heard about tight oil and LNG, ignore all of that. Deepwater is where we’re going to see the most growth.” Wood Mackenzie estimates that, by 2050, the world’s total discovered and pro- spective oil resources will be more than double its base-case energy transition outlook oil demand forecast, and natu- ral gas resources will be close to double the expected demand. However, not all resources will be cost effective and/or emissions efficient, so the industry will have to become much more selective. “Advantaged” barrels, which Wood Mackenzie defines as resources with breakeven price below $30/Brent and an emissions intensity of less than 20 kgCO 2 e/BOE, will be prioritized in the coming years. However, only 28% of the resources in commercial undeveloped fields currently meet those criteria. This means operators will have to invest in solutions to help turn disadvantaged resources into advantaged resources, Ms Wilson said. “Total resource is not the issue,” she explained. “Many of the resources we have in our database have never been developed because they are too expensive, too dirty or too far from markets – whatever the reason, they’re disadvantaged. There’s still a great deal of demand required, and exploration of new resources is going to be required.” Going forward, E&P operators will like- ly produce some of the disadvantaged resources in order to meet demand, but they will be looking to offset some of the cost and emissions by maximizing pro- duction from more advantaged develop- ments like deepwater. One example is the Guyana-Suriname Basin, which already has more than 50 wells on the Stabroek Block even though exploration in Guyana only began in 2019. Joint venture partners ExxonMobil and Hess made nine discoveries on the block last year and, just in April, announced sanction of their fifth project there – Uaru . Upon startup in 2026, the project is expect- ed to produce 250,000 bbl/day of oil . Clare Gardner, Exploration Director – South America at Hess, pointed out that the average breakeven prices of the first four sanctioned projects in the area – Liza Phase 1, Liza Phase 2, Payara and Yellowtail – ranged between $29-$35/bbl. “If you look back to the beginning of 2019 with Guyana, we were getting zero production. Now we’re getting 75,000 bar- rels a day in Q1 2023. The pace and scale at which these projects are coming online A panel of industry representatives at the 2023 OTC discussed the role they expect deepwater to play in the near- and long- term future . Pictured (from left) are Maiza Goulart, Petrobras; Brandon Finley, TechnipFMC; Sarah Hill, BP; Romain Chambault, Baker Hughes; Clare Gardner, Hess; and Julie Wilson, Wood Mackenzie. 38 J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R I N NOVATION S I N DE E PWATE R is just phenomenal. We feel the basin is going to play a key role in future deepwater growth – we still have billions of barrels yet to find there,” Ms Gardner said. The area also holds great potential for low-emissions energy, she added. In December 2022, Hess announced plans to spend $750 million on carbon credits under the United Nations Reducing Emissions from Deforestation and Forest Degradation (REDD+) program. The deal, which will see Hess purchase 37.5 million REDD+ carbon credits from the Guyanese government, is designed in part to help offset carbon emis- sions from its deepwater E&P activity. Carbon capture and storage For Petrobras, carbon capture and stor- age (CCS) has been a primary driver in reducing emissions intensity from its deepwater megaprojects in the Brazilian pre-salt, increasing the efficiency with which it produces hydrocarbons while also reducing greenhouse gas emissions. Maiza Goulart, Head of Petrobras’ Research and Development Center, said that many of the operator’s fields in the basin carry a high amount of CO 2 , particu- larly in the natural gas, and this CO 2 can challenge the topside production capac- ity of its FPSOs. So, in 2018, the com- pany began reinjecting CO 2 produced from its production platforms into reservoirs beneath the seabed. Currently, all 21 Petrobras production platforms operating in the pre-salt incor- porate CCS combined with enhanced oil recovery techniques, and this effort has paid dividends. Last year, the company reinjected 10.6 million tonnes of CO 2 , a 22% increase from the 8.7 million tonnes it reinjected in 2021. According to the Global CCS institute, the 10.6 million figure represented approxi- mately 25% of the total CO 2 that was stored globally last year. Petrobras is also developing a high-pres- sure separation (HISEP) technology, which will separate and reinject gas with high CO 2 content produced alongside the oil while on the seabed. A two-year pilot test period is expected to begin at the Mero 3 presalt field upon its startup in 2024. The operator is also aiming to install the system in other pre-salt fields, such as Libra Central and Jupiter, if the pilot proves successful. “All of the hype you’ve heard about tight oil and LNG, ignore all of that. Deepwater is where we’re going to see the most growth.” - Julie Wilson, Wood Mackenzie “This is going to be a very important solution in increasing the energy efficien- cy and the reliability of high-CO 2 fields we have in the pre-salt,” Ms Goulart said. “If we can use the HISEP system to avoid having to do the reinjection process at the surface, it could have an impact on the CAPEX, OPEX and lead times of our pre-salt fields. It’s a good example of how our technology profile can help support our goals.” CCS was also cited by TechnipFMC as a key pillar of its energy transition plans. In 2021, the company entered a strategic alliance with Talos Energy on front-end engineering design and storage site characterization for Talos’ CCS hub in the US Gulf of Mexico. That same year, TechnipFMC acquired Magma, a manu- facturer of a hybrid flexible pipe that could become an enabler for efficient CCS in off- shore environments, said Brandon Finley, Commercial Director – New Energy at TechnipFMC. The pipe is made of a combi- nation of carbon fiber and polyether ether ketone and is resistant to highly corrosive natural gas, like the high-CO 2 gas in the Brazilian pre-salt. “CCS is the type of market that’s allowed us to integrate both our surface and subsea divisions to look at how we can make the most optimal solutions,” Mr Finley said. “We’ve really been able to jump into a mar- ket that we think is maturing very quick- ly. As we move further and further into deepwater, we think we’ll be able to take advantage of some of these technologies that have been developed in oil and gas.” Supply chain management Beyond operators’ efforts to reduce emissions, another theme that emerged from the panel session was the value in decarbonizing the deepwater supply chain. Romain Chambault, VP – Global Services and Offshore at Baker Hughes, emphasized the role that service compa- nies can play in helping the industry to commercialize and scale deepwater and low-carbon technologies. “The biggest challenge for us is how can we partner not only with our cli- ents but throughout the supply chain,” Mr Chambault said. “We’re not going to find the solutions all by ourselves. We have to leverage the supply chain to actually scale the technologies that are going to help us. When we’re working with small developers, they don’t necessarily know how to scale their technologies to bring them to market. We can provide that scale.” BP also says it has been focusing on better supply chain management in order to boost the efficiency of its deepwater projects while lowering its carbon foot- print. The company’s partnerships with its vendors, for example, are key to success- ful adoption of sustainable solutions, said Sarah Hill, VP – Procurement, Americas and Manufacturing at BP. Last year, the company signed a memorandum of understanding with Thyssenkrupp Steel to decarbonize steel production, primarily through the replace- ment of coal-fired blast furnaces, used to turn iron ore into steel, with hydro- gen-powered plants. The operator is also developing methods to track the carbon footprint of its supply chain so that it can identify opportunities for emissions reduction. Supply chain management has become especially critical for BP as it expands its deepwater portfolio, Ms Hill said. The operator has developed 14 oil and gas proj- ects, including Mad Dog Phase 2 in the US Gulf of Mexico, over the last three years and plans to start up four more projects this year – GTA Phase 1, KG D6 MJ, Seagull and the Tangguh Expansion. “We really need to understand how we can support our deepwater business with our sustainability agenda and how we can create that partnership,” Ms Hill said. “Our suppliers have been helping us to achieve immediate supply chain emis- sions reductions in an area that can be hard to crack.” DC D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 39 D E PA R TM E NT S • H S E&T CO RN ER Great Crew Change 2.0: Better job-site engagement, competency assurance programs help to keep short-service employees safe Companies also relying on behavior-based tools, automation to enhance rig-site safety BY JESSICA WHITESIDE, CONTRIBUTOR Drilling companies are facing a shortage of experienced personnel as the ongoing post-pandemic recovery continues, which means many are bringing on less-experi- enced short-service employees (SSEs). To ensure these SSEs can operate both safely and efficiently, companies are looking to automated and error-tolerant systems, competency assurance programs (CAPs) and mentorship engagement to keep per- sonnel safe while meeting productivity expectations. “You cannot achieve operational excel- lence without safety. We have to make sure our people are highly trained, high- ly skilled and highly competent,” said Donovan Randolph, Nabors Industries’ Senior QHSE Manager for North America. He spoke during the Great Crew Change 2.0 panel at the 2023 IADC HSE & Training Conference in Houston on 19 April. Workforce pressures compounded by upturn The long-simmering “great crew change” was always going to be tricky for the industry, due to the hiring slump in the mid-1980s and ’90s that left a whole generational gap in the workforce. A brain drain of STEM professionals leaving for the tech sector over the past couple of decades hasn’t help either. More recently, the personnel shortage has been exacerbated even further by pan- demic-related layoffs and resignations, as well as stiff competition from other skilled and unskilled labor markets, including the growing renewables sector. And then there’s the impact of the post- 40 pandemic demand for rigs. Dirk Kolnsberg, VP HSE at Patterson-UTI Drilling Company, pointed to a Baker Hughes statistic show- ing that the April 2023 US rig count was up by over 200% from the low in 2020. “Not only do we have this crew change issue, but now also we have this massive upswing in the numbers of rigs, so we also have additional pressures that weren’t there back in 2013 or 2014,” he said. With broader factors than retirement now at play in the skills shortage, the tran- sition focus has shifted from knowledge transfer to retention and skill develop- ment. For example, Patterson-UTI has imple- mented a formal process to verify that new-to-industry employees have the criti- cal information and competencies they need to be successful, Mr Kolnsberg said. “We’ve seen a significant improvement in our retention because of that.” Engineering variability out through automation Setting people up for success also includes looking for opportunities from a technology standpoint to engineer some of the hazards out, Mr Randolph said. “When something happens, it’s not always about going back and reviewing and revising the policy,” he said. “We need to look at it from a deeper perspective, at how we can actually eliminate something or create a better error-tolerant system for our teammates so when things do happen, no one gets killed.” Mr Kolnsberg said Patterson-UTI is automating a lot of its downhole solutions to take some of the variability out of its operations and to shift some of the rou- tine tasks within a drilling process away from personnel. “We’re looking for ways to automate that so we’re not relying on the drillers who might only have four or five years of experience in the oilfield.” Enabling mentors Mentorship is another essential com- ponent to help newhires feel engaged and gain the competencies they need to stay safe – but what if their supervisor doesn’t have the time or skills to get that coaching component right? Patterson-UTI reviewed its operational and HSE expectations in 2022 to see how processes and responsibilities for its job- site managers had changed since 2014 to keep pace with internal and external requirements. The analysis found that the documented responsibilities for the role had ballooned from 359 to more than 1,200. The requirements broke down roughly by thirds into administration, engagement (such as coaching and verifying the work of others), and action (when the manager would personally go out and perform jobs), Mr Kolnsberg said. “One of the questions that we asked is, where should they be spending their time? Are we asking them to do the right things? Are we providing them opportunities to spend more time on engagement? How can we minimize the amount of adminis- tration they have to do?” Part of the answer is to take a risk- based, time-management approach to optimizing processes and to employ digi- talization strategies to eliminate a lot of the administrative tasks so supervisors have more time to supervise and foster job- site engagement. “Improved engagement will lead to better retention, better perfor- mance, better safety,” Mr Kolnsberg said. Mr Randolph noted it is also important to ensure that leaders receive training and resources to be effective mentors. Someone may be deemed a mentor simply by virtue of their time in service or high performance. But is someone a good rig manager simply because he or she is a good driller? If you expect mentors to oper- ate at a high level, you have to give them tools to help them learn how to manage and communicate, he said. “We expect J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R H S E&T CO RN ER • D E PA R TM E NT S Donovan Randolph (from left), Nabors; Dirk Kolnsberg, Patterson-UTI Drilling Company; and Jorge Leuro, Workforce Impact, all spoke on “The Great Crew Change 2.0” panel at the IADC HSE&T Conference in Houston on 19 April. him to execute everything, but have we actually invested into him?” Among the behavior-based safety tools Nabors uses to help improve HSE in a market with a high percentage of SSEs is the Safety Observation Conversation (SOC) system, which digitally tracks safety observations submitted by crew members. When an incident happens, one of the first things Mr Randolph said he checks is the level of SOC participation on that rig. If participation among the rig’s manag- ers are low, he said, that “tells a lot about leaders.” Audit of CAP best practices Leadership skills should be included in a company’s CAP , said Jorge Leuro, Talent Management Executive at Workforce Impact. That was one of several CAP best practices that emerged from a study undertaken by Mr Leuro and David Demski of Competent & Engaged in 2021 and 2022. The two companies audited the CAPs of 17 drilling companies to identify industry best practices and trends. Some of the gen- eral best practices included using CAPs to test knowledge, not just verify that knowl- edge has been delivered as part of train- ing; ensuring that competencies address incidents; and involving management in an annual review of the CAP. CAPs were also found to have a strong connection with SSE programs, Mr Leuro said, although a number of the companies audited also apply their CAPs to other employee populations. The audits found that CAPs were frequently used to ensure an employee’s competence for promotion decisions, and that companies tended to take a risk-based approach to reas- sessing an employee with long service in their position to ensure continued compe- tence. A risk-based approach is also a best practice for verifications to ensure that employees have been assessed correctly for competencies with the greatest impact on human errors, Mr Leuro said. The research found that many compa- nies are using existing corporate process- es to manage CAPs, such as management of change, internal audit, verification and data management processes. Looking at the technology that companies rely on to handle employee competencies, the study found that 41% use a manual system, 35% use a learning management system and 24% use a competency management sys- tem. On average, the companies studied dedicate one assessor per six employees and one verifier per 16 assessors. CAP participation varied depending on company size, with large companies (more than 1,000 employees) averaging 68% of their workforce participating in compe- tency programs. The figure dropped to 47% for medium companies (less than 1,000 employees) and 37% for small companies (less than 300 employees). For companies that do not already have a CAP, Mr Leuro noted that IADC provides guidelines on how to build one and offers a Competence Assurance Accreditation program. He further recommended as a best practice that companies make use of IADC’s role-specific competencies (KSAs) . “We need to have a very well-designed, implemented and sustained competen- cy assurance program to really have an impact on the safety culture of the orga- nization and on the performance of the employees,” he said. DC D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 Scan me for IADC’s guidelines for building a competence assurance program. bit.ly/3qBmTzQ Scan me to access IADC’s Knowledge, Skill and Ability (KSA) database. bit.ly/3N2B7Bs 41 IADC CONNECTION • EDITORIAL Our members make the industry an exceptional global community FROM THE PRESIDENT One of my favorite aspects of this associa- tion is the community, which somehow manages to be both wide-reaching and closely knit at the same time. We have members spread throughout the world, and every event I attend outside our Houston headquarters still feels like I’m right at home. I’ve never seen or expe- rienced anything quite like it. This is a group essentially comprised of business competitors, and yet drilling contractors gather frequently and fervently for many reasons. Some of these reasons include working together to keep people safe, advocating for fair and sensible legisla- tion, innovating changes in technologies and techniques, and serving as a unified voice for industry’s needs. Ultimately, what it comes down to is collaborating to further the best interests of the drilling industry. That was the stat- ed purpose of this association when it was formed in November 1940, and it continues to be our purpose today. While many of our main goals have remained the same, this association has seen a lot of changes over the decades. For example, IADC was originally estab- lished as the American Association of Oilwell Drilling Contractors (AAODC) and initially focused on drilling contractors within the US. That changed in 1971 when we expanded both in name and in scope. The industry grew exponentially as drill- ing contractors started working in dif- ferent regions around the world, and our focus as an association shifted with this growth. We expanded our activities to different areas of the world while main- taining activities within the US, and the AAODC officially became the International Association of Drilling Contractors. Today, IADC has a network of regional representatives who serve as local advo- cates to foster connection and collabo- ration among members in Europe, the UK, Brazil, the Middle East, Asia Pacific, Australasia, Africa and Latin America. A core component of IADC’s global presence 42 is our 10 regional chapters outside the US, which are run by local members. Regional chapters provide connection through networking events, professional develop- ment opportunities, and targeted efforts to address regional challenges . IADC’s stu- dent chapters have continued to develop outside the US as well, with a presence in Saudi Arabia, India, Australia and – the newest addition – Malaysia. One primary area of focus for all IADC regional chapters is safety. The Southern Arabian Peninsula Chapter held a well- attended HSE awards ceremony earlier this year, and the Nigeria Chapter held a similar ceremony in June. The North Sea Chapter is currently undertaking a “Mental Health in Energy” initiative, which aims to drive cultural change in how mental health is addressed in the energy industry. The chapter has published a 15-page white paper on the subject and recently hosted an interactive “Mental Health in Energy” workshop . The Southeast Asia Chapter introduced its inaugural safety awards presentation during the IADC HSE and Sustainability Asia Pacific Conference, held in Kuala Lumpur in May. In addition to the Asia Pacific conference, IADC also hosts an HSE and Sustainability Europe Conference. Conferences such as these are only pos- sible because of the efforts of the dedicated members who make up the conference planning committees. These conferences provide members with a forum to gather and discuss significant topics. Other IADC conferences taking place outside the US this year include events in the Middle East, Asia Pacific, Europe and the Caspian region. IADC members outside the US are engaged in a variety of advocacy efforts affecting drilling contractors at the region- al level. These members, along with IADC’s team, build and maintain relationships with local government officials, regula- tors and other industry organizations. We take part in important conversations to Jason McFarland, IADC President ensure the unique perspective of the drill- ing contractor is heard and respected. The Latin America Chapter is in the process of responding to the reclassification of drillships with a formal letter to regional regulators. The IADC South Central Asia Chapter has been addressing challenges in India regarding imposed age restrictions on MODUs. The Southeast Asia Chapter has been working for better cabotage regu- lation in Indonesia. In the North Sea, chap- ter members have been advocating for more support of drillers through visiting and writing letters to parliament. Another important way IADC region- al chapters support their membership is through opportunities for networking and professional development. Many regional chapters host events so local members can gather for quarterly meetings or work- shops on specific topics. For example, the Southern Arabian Peninsula Chapter recently held a “Soft Skills Communication & Negotiation” training session for its members. The Australasia Chapter recent- ly hosted its 58th Annual General Meeting. The Caspian Chapter and the Northern Arabian Gulf Chapter, among others, hold annual golf tournaments and networking events. In June, the Brazil Chapter hosted a family cookout day. The list of examples could go on, but you get the idea. IADC’s global efforts are far-reaching and long-lasting. I bet the group of vision- aries who started this association 83 years ago would be astounded by the remarkable work that has taken place and continues to be carried out by IADC’s passionate members. To all IADC members worldwide, thank you for the countless ways you contribute to making the drilling industry the excep- tional community that it is. DC J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R NEWS CUTTINGS • DEPARTMENTS IADC North Sea Chapter workshop highlights industry's mental health challenges On 25 April, the IADC North Sea Chapter hosted the Mental Health in Energy Workshop in Aberdeen, UK. The workshop was designed to address the current state of mental health among energy industry professionals. The event began with a panel discus- sion on topics like the definition of mental health, whether there are positive changes in this area in the industry, and how com- panies and leaders can better support the workforce in regards to mental health. The panel was followed by interactive sessions with attendees. Prior to the workshop, the North Sea Chapter issued a white paper (“Changing Minds: Saving Lives – An urgent new approach to mental health in the North Sea") highlighting the ways to best support the mental health of workers in the UK Continental Shelf. An IADC North Sea Chapter workshop on 25 April examined the steps that compa- nies can take to support the mental health of their workers. Pictured are (from left) Kim Woolner, Ithaca Energy; Brett Townsley, a mental health specialist; Cami Rose Alexander, a well-being coach; Chaplain Gordon Craig; Darren Sutherland, IADC North Sea Chapter Chair; and Kirstin Gove, Global Underwater Hub (moderator). Q1 2023 ISP report shows 284 recordables globally Fred Growcock (right), Chair of the IADC Technical Publications Committee, interviewed Samuel Bridges, co-author of "A Practical Handbook for Drilling Fluids Processing," about the new book and its value for the industry. The conversation took place as part of the committee's DrillingIn book review series. » DrillingIn video series features drilling fluids processing book As part of the IADC Technical Publications Committee's DrillingIn book review series, Chairman Fred Growcock interviewed Samuel Bridges about his new book, "A Practical Handbook for Drilling Fluids Processing," co-authored with Leon Robinson. The Q1 2023 report of the IADC Incident Statistics Program (ISP) record- ed 284 total recordable incidents across its nine reporting regions (Africa, Asia Pacific, Australasia, Canada, Central America Caribbean, Europe, Middle East, North America and South America). The US registered the most record- ables, with 143. Of that total, 126 record- ables occurred in land operations and 17 were offshore. The region saw 57 restricted work/transfer (RWTCs) cases, 49 medical treatment only (MTOs) cases and 37 lost-time incidents (LTIs). Africa registered the second-high- est total recordables, with 58 (56 land, two offshore). Of those, there were 34 RWTCs, 15 LTIs and seven MTOs. Africa was one of only two regions to record a fatality in Q1, which occurred in land operations; Europe was the other, with one fatality recorded offshore. The book provides a reference for drilling fluid and mud engineers to safely understand how the fluid processing operation affects the drilling process. Agitation and blending of new additions to the surface system are also explained. bit.ly/3MXN0Zd D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 Scan me to access the full IADC ISP Q1 2023 summary report. bit.ly/43uXHJW 43 IADC CONNECTION • WIRELINES NSTA streamlines submission of supply chain action plans with new online portal The UK North Sea Transition Authority (NSTA) has launched a digital platform that operators can use to submit and update supply chain action plans (SCAPs) containing important information about their contracting activities. Operators use SCAPs to demonstrate that they are collaborating openly with suppliers early in the project lifecycle, including through the sharing of project information and details of upcoming ten- ders. SCAPs are also useful for the NSTA, helping the group to monitor changes in costs, find gaps in supply chain capability, promote best practices and identify les- sons learned. SCAPs are required for all field develop- ment and decommissioning projects on the UK Continental Shelf. Since the NSTA rolled out the process in January 2018, more than 200 have been lodged. Previously, submitting an SCAP using a paper or electronic form required an estimated eight hours of work by an E&P company employee, with further updates potentially requiring additional time. Using the online portal, SCAPs can now be completed in smaller, more manageable steps as projects move forward. The NSTA also removed the need to include information that can already be found in field development plans or decommissioning programs. As such, the NSTA said the process should now take about four hours in total. BSEE revises OCS decom rules, signs collaboration agreement on oil spills » IADC’s VP of Policy discusses advocacy efforts in D.C. DC interviewed Joe Lillis, IADC’s recently named Vice President of Policy, on 18 May at the 2023 Drilling Onshore Conference in Houston. In the interview, Mr Lillis discusses initial impressions from his first six weeks on the job. He also speaks about key takeaways from his meeting with the Energy Education Foundation, as well as the importance of DRILLERSPAC, IADC’s political action committee. Mr Lillis also talks about planning IADC’s next Washington, D.C., fly-in, which will allow members to meet with Congress to discuss critical issues. bit.ly/43LNk44 Halliburton, Oil States recognized with NOIA safety awards Halliburton and Oil States International were recently announced as winners of the 2023 Safety in Seas Awards, held by the US National Ocean Industries Association (NOIA). Halliburton received the NOIA Safety in Seas Safety Practice Award, recogniz- ing the company’s Risk Management and 5 Checks to Go programs. Those are part of Halliburton’s “Journey to ZERO” 44 vision of achieving zero safety incidents, zero environmental incidents and zero nonproductive time. Oil States was recognized with the NOIA Safety in Seas Culture of Safety award for the company’s processes to improve safety performance, including executive monitoring, clear communi- cation of vision, and implementation of structured management systems. In April, the US Bureau of Safety and Environmental Enforcement (BSEE) pub- lished a revised rule specifying decom- missioning requirements for rights-of-use and easement grant holders and formaliz- es BSEE’s policies regarding performance by predecessors ordered to decommission Outer Continental Shelf (OCS) facilities. The final rule specifies right-of-use and easement holders accrue decommission- ing responsibilities in the same manner as lessees, operating rights holders and right- of-way grant holders. It also establishes time frames for recipients of BSEE decom- missioning orders to take organizational measures and submit decommissioning plans in response. Separately in April, BSEE also signed an agreement with the Alaska Department of Environmental Conservation (ADEC) focused on the agencies’ coordination of oil spill planning, preparedness and response offshore Alaska. The agreement calls for BSEE and ADEC to cooperate in carrying out their respec- tive regulatory responsibilities and to identify opportunities for innovative and effective implementation of oil spill plan- ning, preparedness and response monitor- ing. Each agency must exercise its own rule- making responsibilities independently and in accordance with applicable laws, but the two may coordinate on rulemak- ing initiatives. In conducting drills, the agencies will follow the objectives of the National Preparedness and Response Exercise Program. J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R UPCOMING IADC EVENTS • IADC CONNECTION IADC WELL CONTROL CONFERENCE OF THE AMERICAS & Exhibition IADC 22-23 AUGUST 2023 THE N E W RITZ ADVANCED RIG TECHNOLOGY Conference & Exhibition CARLTON O R L E A N S , L O U I S I A N A 14-15 SEPTEMBER 2023 MÖVENPICK AMSTERDAM A M S T E R D A M , IADC HSE AND S U S TA I N A B I L I T Y EUROPE CONFERENCE & EXHIBITION 25-26 SEPTEMBER 2023 AMSTERDAM MARRIOT T HOTEL T H E HOTEL N E T H E R L A N D S 2023 IADC OFFSHORE Regional Forum Held in conjunction with the IADC Houston Chapter A M S T E R DA M , T H E N E T H E R L A N D S 26 SEPTEMBER 2023 TRANSOCEAN FACILITY H O U S T O N , IADC/SPE MANAGED PRESSURE DRILLING & UNDERBALANCED OPERATIONS T E X A S IADC Annual General MEETING MEETING Conference & Exhibition 3-4 OCTOBER 2023 G R A N D H YAT T D E NVE R D E N V E R , C O L O R A D O 8-10 NOVEMBER 2023 H YAT T REG ENCY A U S T I N , AUSTIN T E X A S 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 • J U LY/AU G U ST 2023 45 IADC CONNECTION • DRILLING CONTRACTOR DON’T MISS OUT ON OUR NEXT ISSUE! EDITORIAL PREVIEW OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS DRILLINGCONTRACTOR.ORG • IADC.ORG DISTRIBUTION: September/October ◊ Automation & Drilling Rig Advances: ◊ Monitoring & Reducing the Rig’s Carbon Footprint ◊ Drilling Engineering in a Digital Ecosystem ◊ Advanced Drilling Robotics IADC HSE & Sustainability Europe Conference & Exhibition [25-26 SEPTEMBER, AMSTERDAM, THE ADIPEC [2-5 OCTOBER, ABU DHABI, UAE] ◊ Directional Drilling AD CLOSING: 3 AUGUST MATERIALS DUE: 10 AUGUST 46 NETHERLANDS] NETHERLANDS] ◊ Well Control Readiness News IADC Advanced Rig Technology Conference & Exhibition [14-15 SEPTEMBER, AMSTERDAM, THE SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference & Exhibition [3-4 OCTOBER, DENVER, COLORADO] Visit DrillingContractor.org for the latest drilling industry news and videos ONGC completes 36 rig moves in advance of monsoon season Chesapeake issues 2022 Sustainability Report NPD confirms significant oil discovery for Aker BP in North Sea H 2 S draft curriculum, review of WellSharp test questions among ongoing IADC accreditation efforts Halliburton introduces ultradeep boundary mapping service DC visits the 2023 IADC Drilling Onshore Conference: Photo Gallery J U LY/AU G U ST 2023 • 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 Mohamed Hegazi appointed new CEO of ARO Drilling Valaris announced that ARO Drilling, its 50/50 joint venture with Saudi Aramco, has named Mohamed Hegazi as CEO. Mr Hegazi previously served as CEO of TGT Diagnostics, a provider of wellbore integrity measurement solutions to the oil and gas industry. Prior to being appointed CEO of TGT in 2015, he served as COO and Managing Director at the company from 2012 to 2014. Before joining TGT, Mr Hegazi held vari- ous senior leadership positions at SLB. Chevron adds to onshore portfolio with PDC Energy acquisition Chevron entered into an agreement with PDC Energy to acquire all of the outstand- ing shares of PDC in an all-stock transac- tion valued at $6.3 billion. The acquisition provides Chevron with 75,000 net acres in the DJ Basin, adjacent to Chevron’s existing operations that add over 1 billion BOE of proved reserves. It will also add 25,000 net acres in the Permian Basin to Chevron’s portfolio. The transaction has been unanimously approved by the Boards of Directors of both companies and is expected to close by the end of 2023. Expro wins contracts for well services offshore UK and Uganda Energy services provider Expro secured a new contract with Harbour Energy for a well abandonment campaign as part of the decommissioning project for the Balmoral area, in the UK Continental Shelf. The multi-year contract will utilize Expro’s Subsea Well Access technology. The company also signed a five-year well intervention and integrity contract with TotalEnergies for the multi-well Tilenga project offshore Uganda. Work begins in Q2 2023. Equinor awards SURF, FPSO contracts for Brazil project Equinor, along with its partners on the BM-C-33 license Repsol Sinopec Brasil and Petrobras, awarded a contract for subsea umbilicals, risers and flowlines (SURF) to TechnipFMC, and a sales and purchase agreement for the delivery of a floating production, storage and offload- ing (FPSO) unit to MODEC. ADNOC invests in project for sustainable water supply ADNOC and TAQA awarded $2.4 billion to a project that will develop a centralized seawater treatment facility and transpor- tation network for operations at the Bab and Bu Hasa fields in Abu Dhabi. This proj- ect will replace the current high-salinity deep aquifer water systems at the fields, thereby reducing water injection-related energy consumption by up to 30%. The Tenaris to support Neptune drilling activities in Norway Neptune Energy awarded a contract to Tenaris to provide equipment and services supporting drilling activities on the Norwegian Continental Shelf. The five-year contract covers the manufacture, transport, handling and repair of various casing materials. Well Control Schools adds immersive simulators to classroom training Well Control School is integrating high-spec simulation systems from Applied Research International into its classroom training for well control. The simulators, which are powered by high-fidelity mathematical models that accurately simulate real-world scenarios, can also be used on a rig site for continued learning. API names Meyer to new role as Senior Vice President The American Petroleum Institute (API) promoted Dustin Meyer to Senior VP of Policy, Economics and Regulatory Affairs. He had previous served as API’s VP of Natural Gas Markets. Prior to joining API, he led analytics and consulting services for global LNG and renewable energy markets for Energy Ventures Analysis. project will deliver more than 110 million imperial gallons per day of nano-filtered seawater. InteliWell lands rig services contract with Transocean InteliWell secured its first rig services contract, from Transocean, to equip and utilize its proprietary InteliWell software on the Transocean Norge. The harsh-envi- ronment semisubmersible recently com- menced a joint contract with Wintershall and OMV for the drilling of 17 wells on the Norwegian Continental Shelf. Huisman launches digital portal for equipment owners Huisman has launched myHuisman, an online portal that offers its clients a parts shop, a knowledge base including a smart ticketing system, and a technical library of Huisman equipment. Aquaterra Energy seals subsea riser deal with BP Aquaterra Energy secured a subsea riser contract with BP for the Cypre subsea well development project off- shore Trinidad and Tobago. The sys- tem will be operated from a jackup and support gas exploration from seven development wells. Drilling activities are expected to commence later this year, with gas production set to begin in 2025. Stallion brings 3 divisions together under new name Stallion Oilfield Services has re- branded as Stallion Infrastructure Services. Further, Stallion Oilfield Services, StallionRents and STAR- COMM are all being merged into a single entity. D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 47 DE PAR TM E NTS • PEOPLE, COMPANIES & PRODUCTS Nabors, Corva form alliance to scale digital transformation Corva and Nabors Industries formed a strategic technology partnership to inte- grate Corva’s App Store and Dev Center with Nabors’ SmartROS universal drilling rig controls and automation system. The companies aim to rapidly scale process and machine automation in the industry by simplifying the execution of automation on any AC rig. Operators can design and deploy custom apps across their rig fleet, regardless of the rig provider. Smart ROS is now deployed on more than 124 Nabors rigs in the Lower 48, Latin America and the Middle East, as well as 15 non-Nabors rigs. Corva offers more than 100 apps and dashboards, including Predictive Drilling, a machine learning technology that enhances rotary drilling performance. It has already been used to provide data visualizations for 27,000 wells covering 596 million ft. BiSN reaches milestone with Wel-lok technology BiSN has achieved a milestone of 400 commercial deployments of its Wel-lok technology , which enables bismuth-based seals for plug and abandonment and well intervention applications . The company reached its previous milestone of 300 deployments just 13 months ago. In addition , BiSN has now deployed into 17 countries, the most recent in Mozambique . Products All-climate hydrocarbon fire protection coating ideal for extreme environments Jotun launched the Jotachar JF750 XT coating, which aids in passive fire protection for oil and gas assets and was designed to perform in all climates. The coating went through five years of internal and third-party testing, including exposure to a wide range of external environments. Testing was conducted at Jotun’s Svalbard facility, the industry’s only Arctic testing sta- tion for coatings, as well other loca- tions for harsh desert and sub-tropical conditions. The coating is certified to key industry fire and cryogenic spill protection standards, including listing to UL1709 in addition to Lloyds Register and DNV Type Approvals for pool fire, jet fire and cryogenic spill protection. Extreme-Duty valves, seats achieve 800 hrs running life GD Energy Products (GDEP) recently completed a one-month field trial in the Delaware Basin for its new Extreme-Duty Drilling Valves and Seats, proving they provide a reduction in maintenance levels and in inventory and consumption rates, in drilling pump applications. In the Eagle Ford, they even achieved 800 hrs running life. The valves and seats are rated for up to 7,500 psi and are compatible with both oil- and water-based drilling muds. They can withstand up to 350°F. Ingersoll Rand expands cordless tools with IQV20 battery system 4D inversion technology enhances fluid tracking Ikon Science’s new Time-Lapse Ji-Fi app offers 4D fluid tracking capabilities for production and injection scenarios. The tool is applicable in most hydrocar- bon production and carbon capture, uti- lization and storage projects. It utilizes cross-plot display options, input filters for data management and a probability density function management system. The app encompasses the company’s Deep QI machine learning technology , which is expanded with a new machine learning property prediction and auto- mated rock physics modeling function algorithm for better workflow efficiency. 48 Ingersoll Rand expands its IQV20 Battery Series with three new cordless compact impact wrenches . This includes a ¼ -in. compact impact driver that deliv- ers up to 3,400 in-lb of fastening torque; a ⅜ -in. impact wrench with a breakaway torque up to 400 ft-lb and a maximum speed of 2,800 RPM; and ½ -in. impact wrench with a 5.3-in. tip-to-tail length for tight spaces. The company also introduced the G5351 IQV20 cordless angle grinder with a reduced weight to minimize worker fatigue while working in enclosed spaces. The wrenches and grinder all work on the same IQV20 battery system. J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R AD INDEX DrillingContractor.org Virtual Panel Discussion ...........................................6 IADC Advanced Rig Technology 2023 Conference & Exhibition ..........52 IADC Annual General Meeting .............. 51 IADC Bookstore .............................................. 37 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 IADC Drilling Middle East 2023 Conference & Exhibition .......................35 Noble Corporation .......................................49 Oil States ...............................................................5 TSC Drill Pipe ....................................................25 Turnco ...................................................... DIGITAL Woodco USA .......................................................2 See the latest issue! Sign up for DrillBits www.iadc.org/ drillbits www.iadc.org/ newsletter-signup 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! 9,665+ Followers 30k+ Followers 5,355+ Followers 2.88K Subscribers 2,317,080+ Views D R I L L I N G C O N T R AC T O R • J U LY/AU G U ST 2023 49 DEPARTMENTS • PERSPECTIVES Robert van Kuilenburg, Noble: Innovative thinking can push drilling into new frontiers BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Robert van Kuilenburg is always thinking about the next frontier, building a career that has taken him to multiple companies that prioritize innovative thinking. These days, as Offshore Improvement Manager at Noble, he’s thinking not only about the future of rig designs and equipment, but also about the future of the industry itself. He stresses the value of mentorship for young employees, as well as how the industry can help to attract and retain next-generation talent by promoting its digitalization and automation efforts. “We’re seeing a lower influx of people coming into the industry at the same time experienced people are leaving the indus- try, and we should be doing something about it,” he said. “When I was growing up in The Netherlands, everybody thought Shell was a good company to work for. They had many programs for elementary schools covering a variety of subjects in a cool way. We lost that somewhere, and we need to rebuild that positive presence.” Although Mr van Kuilenburg learned about the oil and gas industry from an early age, through an uncle who worked as a superintendent for Shell, he did not have an interest in an oil and gas career at first. He loved the sea, and had developed a love of building things from his grandfathers, an art woodworking teacher and an auto mechanic. In 1990, when he joined the Delft University of Technology, he decided to major in mechanical engineering and minor in naval architecture, a combina- tion that provided a broad range of career options. 50 “When people go to university, I really think they should try to focus on special- izing in something, get really good at it, but also keeping your eyes open for something outside of your field because, sometimes, it can lead you to something interesting. I graduated on the topic of AI in condition monitoring systems, something that was outside of our industry at the time, and I never suspected it would grow into what it is today.” After graduating in 1996, Mr van Kuilenburg joined Innas, a Dutch engineer- ing firm whose clients were often willing to spend money developing interesting ideas. This created an ideal job for young engineers as there were often opportu- nities to work with some of the latest technologies available at the time, like 3D printing and machine learning systems. In 2001, Mr van Kuilenburg took another step closer to the oil and gas industry when he joined Huisman Equipment, first as a Concept Engineer, helping to concep- tualize equipment designs, and later as a Project Engineer, helping to oversee the manufacturing of the equipment. Part of his time at the company was spent in China, working with shipyards to execute designs for drilling rigs. He was promoted to VP of Projects in 2012. “To me, working in foreign countries with teams comprising of many nationalities is really a rewarding part of working in our indus- try. At one time we counted more than 30 nationalities on one of the rigs. Everyone was treated with respect.” While at Huisman, Mr van Kuilenburg came into contact with Hans Deul, then- Director of Research and Development at Noble. Mr Deul offered to bring him into the offshore drilling company in a Senior Mechanical Engineer role where he would develop new vessel concepts, review rig designs and oversee parts of the integra- tion testing for the rigs that Noble was building at the Hyundai Heavy Industries fabrication yard in South Korea. But he didn’t just hire Mr van Kuilenburg – he also served as a mentor for him. “I think it’s important for young people to find someone in the company who will be there for you, someone who can guide you through all the details of being in this industry. For the older generation, mentor- ing younger people is one of the best ways Robert van Kuilenburg, Noble Offshore Improvement Manager, recently co-led an ART workgroup to upgrade the long- standing IADC bit dull grading system. to keep them in this industry,” he said. In 2017, Mr van Kuilenburg was pro- moted to the position of Mechanical Engineering Manager, where he man- aged a team of engineers focused on R&D. Examples of projects his team has under- taken over the years include the develop- ment of electrically driven BOPs and the design/manufacturing of integrated man- aged pressure drilling equipment. In his current position as Offshore Improvement Manager, he “brings together all the differ- ent aspects of drilling, from mechanical systems to highly automated processes, looking at it from a very practical angle.” Mr van Kuilenburg has also been an active contributor to IADC, primarily through the Advanced Rig Technology (ART) Committee. During his time serving as ART Chairman in 2019-2020, he helped to spearhead IADC’s DDR Plus, expand- ing the daily drilling report’s legacy main codes and adding subcodes to improve granularity in rig activity reporting. More recently, he co-led an ART work- group to upgrade IADC’s long-standing bit dull grading system. Among other things, the project focused on expanding the categories of bit wear within the grad- ing system and developing a guideline to store codes, digital images and other metadata about drill bits that can be used for machine learning tools and real-time data exchange. The new IADC guidelines are anticipated to be launched later this year. DC J U LY/AU G U ST 2023 • D R I L L I N G C O N T R AC T O R IADC Annual General MEETING MEETING 8-10 NOVEMBER 2023 H YAT T R EG E N CY AUSTI N A U S T I N , PLATINUM SPONSORS GOLD SPONSORS T E X A S SILVER SPONSOR www.iadc.org/event/iadc-annual-general-meeting-2023 For more information, contact IADC by phone at +1.713.292.1945 or via email at iadcconferences@iadc.org IADC ADVANCED RIG TECHNOLOGY Conference & Exhibition 14-15 SEPTEMBER 2023 MÖVE N PICK AMSTE R DAM A M S T E R D A M , T H E H OTE L N E T H E R L A N D S GOLD SPONSORS SILVER SPONSORS EVENT SPONSORS www.iadc.org/event/rt23 For more information, contact IADC by phone at +31.24.675.2252 or via email at europe@iadc.org