CRITICAL ISSUES IN DRILLING & COMPLETIONS Activity ramp-up pushes workforce challenges back to center stage JAN/FEB 2023 Volume 79 • Number 1 Official magazine of the International Association of Drilling Contractors www.drillingcontractor.org www.iadc.org IADC Chairman Andy Hendricks: Industry optimistic for period of stability Moderated growth can create healthier business environment for drillers – p42 New dual-gradient drilling technique aims to remove limiters for ultra-deep wells Technology combines new surface & downhole systems with current equipment, drilling practices – p33 ONE-TOUCH TUBULAR SIMPLICITY REVOLUTIONARY RIG-FLOOR EFFICIENCY AUTOMATED CONNECTION INTEGRITY WITH NEXT-GENERATION SAVINGS, SAFETY, AND VALUE weatherford.com/vero 50% LESS PERSONNEL 10% LESS RIG-TIME 100% CONSISTENCY © 2023 Weatherford. All rights reserved. The Vero ® OneTouch automated tubular system transforms rig-floor efficiency for the ultimate connection-integrity system. Eliminate failures with absolute certainty and save on well-construction costs featuring hands-free makeup, analysis, and switch-out between drilling, casing, and completion operations — all with just one touch of a button. Vero OneTouch seamlessly integrates into the driller’s chair to remove all rig-floor personnel and equipment for safer, more precise results and bottom-line savings. Discover flawless connection integrity today. TAB LE OF CONTE NTS Official magazine of the International Association of Drilling Contractors JAN/FEB 2023 Volume 79 • Number 1 drillingcontractor.org iadc.org Nabors is developing capital-light automation systems that can improve both safety and efficiency, like its RZR robotics module, which has been retrofitted to the X29 rig. Read more on Pages 7 and 28. Cover photo courtesy of Nabors Industries. CRITICAL ISSUES IN DRILLING & COMPLETIONS 10 Investments in digital systems, sustainability will help drillers carve niche in new landscape BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 14 Renewed focus on safety needed as industry deals with labor shortage amid activity ramp-up BY LINDA HSIEH, EDITOR AND PUBLISHER 16 Technology allows drilling contractors to bring added value beyond traditional work scope 22 Open architecture, end-to-end solutions can help to advance industry’s digital journey BY LINDA HSIEH, EDITOR AND PUBLISHER 26 Petrobras looks to disruptive technologies to ensure all E&P projects have ‘double resilience’ BY LINDA HSIEH, EDITOR AND PUBLISHER 28 Financial and human capital challenges call for the industry to adopt new ways of thinking BY LINDA HSIEH, EDITOR AND PUBLISHER BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 19 14 Industry must fill talent gap for both today and tomorrow as it seeks long-term value creation BY STEPHEN WHITFIELD, ASSOCIATE EDITOR D E E PWATE R D R I LLI N G MAR KETS & TECH N O LOG I E S 32 Fast innovation process allows Petrobras to tap Búzios with lower cost, higher reliability BY LINDA HSIEH, EDITOR AND PUBLISHER MANAGED PRESSURE DRILLING 33 Dilution-based dual-gradient technique aims to remove limiters for drilling ultra- deep wells 37 Machine learning-based pressure MPD-enabled real-time pressure testing helps Shell improve safety in ‘conventionally undrillable wells’ 38 management technology brings full automation to MPD operations BY ERIC VAN OORT, LEWIS J. DUTEL AND LUC DE BOER, ULTRADEEP ENERGY COMPANY 35 BY STEPHEN WHITFIELD, ASSOCIATE EDITOR BY STEPHEN WHITFIELD, ASSOCIATE EDITOR New well design and MPD deployed to manage pressure uncertainties in Gulf of Thailand BY STEPHEN WHITFIELD, ASSOCIATE EDITOR D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 3 TAB LE OF CONTE NTS H E A LT H , SA F E T Y, E N V I R O N M E N T & T R A I N I N G 40 Mitigating drops risks through pipe screen replacements, red zone management technology BY STEPHEN WHITFIELD, ASSOCIATE EDITOR IADC CONNECTION 42 IADC Chair Andy Hendricks: Moderated 46 News Cuttings growth may create healthier business environment for drillers in coming years 48 Wirelines BY LINDA HSIEH, EDITOR & PUBLISHER 44 IADC Board of Directors elects 2023 officers 45 IADC: An association by our members, 49 Conference Calendar 50 Editorial Preview for our members BY JASON MCFARLAND, IADC PRESIDENT 42 DEPARTMENTS 5 Drilling Ahead: Activity rebound puts workforce challenge back at center stage BY LINDA HSIEH, EDITOR & PUBLISHER 6 D&C News 51 People, Companies & Products 53 Advertisers Index 54 Perspectives: Stephen Foster, Scandrill – Moving from US Army to the oilfield opens new career opportunities 7 D&C Tech Digest 8 News Briefs: Environmental, Social 54 BY STEPHEN WHITFIELD, ASSOCIATE EDITOR and Governance 9 Oil & Gas Markets NOTE: Some articles feature QR Codes which can be scanned using your smartphone to access web-exclusive, enhanced editorial on DrillingContractor.org or in our Digital Reader. JAN/FEB 2023 Volume 79 • Number 1 Drilling Contractor (ISSN 0046-0702), the official magazine of the International Association of Drilling Contractors (IADC), is issued six times per year. DC is a wholly owned publication of IADC, which is also the publisher of the annual IADC Membership Directory. Drilling Contractor strives to ensure that the articles and information it publishes are accurate and reliable. However, DC cannot warranty the information provided in its editorial content, and publication in DC is not a guarantee that the material presented is accurate. DC wants to hear from its readers. Send your comments or inquiries to editor@iadc.org or Attn: Editor, Drilling Contractor Magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042 (please include your name, plus an email or phone number). We hope you will enjoy and benefit from DC’s editorial. However, should you wish to 4 complain, please contact the publisher. 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. 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 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. 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 JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R DRILLING AHEAD • DEPARTMENTS Activity rebound puts workforce challenge back at center stage BY LINDA HSIEH, EDITOR & PUBLISHER Speaking with industry executives from drilling contractor and E&P companies over the past couple of months for our annual “Critical Issues in Drilling & Completions” Q&A’s, it’s apparent that old challenges around recruitment and reten- tion have resurfaced with full force as drilling activity ramped up over the past year. Companies are feeling the pinch from a critical labor shortage, evident in the increased presence of short-service employees on drilling locations. Both oper- ators and drilling contractors expressed concerned around the potential impacts. “One competent person cannot be replaced by several less competent indi- viduals. That will only drive up cost, and the quality of the projects will suffer. I think that’s the biggest challenge,” said Tommy Sigmundstad, Senior VP Drilling and Wells for Aker BP (Page 22). The labor shortage is not only about the immediate future, however. It’s a long-haul challenge tied both to the public percep- tion of oil and gas, and to the changes that companies are willing to make to attract the next generation. At Nabors, for exam- ple, Senior Vice President Subodh Saxena urges companies to think about allocating their capital differently this time than they have in past cycles (Page 28). Drilling con- tractors have typically focused on build- ing new rigs when the market picks up, but that strategy leans too much toward achieving short-term gains instead of long-term sustainability. In terms of addressing the workforce challenge, more investments need to go into improving safety and the general well-being of employees, he said. “Today’s workforce is very much willing and capa- ble to work hard for their 12-hour shifts, but when they are off, they want a reason- able quality of living. At a minimum, this means employers need to provide some element of privacy in the living quarters, as well as WiFi. Those investments need to happen. If we don’t do that, we will 2023 IADC HEALTH, SAFETY, ENVIRONMENT & TRAINING Conference & Exhibition not be able to attract and retain those employees because they see those things as necessities, not luxuries.” Differentiating with digital The industry also continues to push ahead in its automation and digitaliza- tion journey. As in recent years, opera- tors we interviewed this time – Petrobras, Petronas, Pioneer Natural Resources and Aker BP – all cited this as a key strategy for cost reduction and efficiency improve- ment. And the drilling contractors we talk- ed to – H&P, Nabors and Seadrill – are all working on finding new ways to leverage digital innovations; they see this is the next frontier for differentiation among the competition. This means that upskilling rig crews and drillers will be critical, as automa- tion systems gradually take over repetitive tasks and manual labor. “Going forward, it’s going to be less about big muscles and more about big minds,” said Simon Johnson, President and CEO of Seadrill (Page 10). Another common thread this year is around the need for more collaboration between operator and drilling contrac- tor. While supply chain bottlenecks and inflation are global issues outside of any one company’s sphere of control, leaders say their impacts can be mitigated when companies work together to plan ahead. “Communication and transparency are paramount, and that involves having con- versations early and often,” said Bonnie Black, VP Drilling at Pioneer (Page 14). “If there is potential for our plans to change, we communicate that with them. At the same time, if our vendors are having chal- lenges around supply chain or labor, there is enough trust in our relationship that they can tell us upfront, and we can try to solve those issues together as early as possible.” DC 18-19 APRIL 2023 H YAT T R E G E N C Y HOUSTON WEST H O U S T O N , T E X A S KEYNOTE SPONSOR PLATINUM SPONSOR SILVER SPONSOR www.iadc.org/event/ 2023-iadc-hset-conference For more information, contact IADC by phone at +1.713.292.1945 or via email at iadcconferences@iadc.org Linda Hsieh can be reached at linda.hsieh @iadc.org. D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 5 DEPARTMENTS • DRILLING & COMPLETION NEWS Angola Block 15 exploration well a success for ExxonMobil The recently awarded contract extension for Sonadrill’s Libongos drillship has a term of 25 months. The rig is managed and operated by Seadrill. Libongos set to drill 12 more wells offshore Angola Sonadrill Holding, a 50:50 joint ven- ture between Seadrill and Sonangol, has secured a 12-well extension in Angola for the Libongos drillship at a dayrate of $402,500. Total contract value for the firm portion of the contract is approxi- mately $327 million, inclusive of addi- tional services. The firm term of the contract is approximately 25 months. There are currently three drillships bareboat-chartered into Sonadrill: a Seadrill-owned unit, the West Gemini, and two Sonangol-owned units, the Quenguela and Libongos. Seadrill man- ages and operates the units on behalf of Sonadrill. New contracts add $488 million to Transocean backlog Transocean announced contract awards or extensions for five rigs. Together, the fixtures represent approxi- mately $488 million of firm backlog. ■ The Deepwater Invictus drillship, was awarded a new three-well contract with an estimated 100-day duration in the US Gulf of Mexico with an independent operator. ■ The Transocean Barents semisub- mersible was awarded a new one-well contract with an estimated 110-day duration in the UK North Sea with a major operator. ■ Harbour Energy exercised the third option on its UK North Sea contract with the Paul B. Loyd Jr. semisubmersible, for eight P&A wells, extending the contract to Q3 2024. ■ In Norway, certain previously dis- closed options under the Transocean Norge contract with Wintershall and OMV have been added to the backlog. ■ TotalEnergies exercised a one- well option on its contract with the Development Driller III semisubmers- ible, working in Suriname. The incre- mental well is expected to last 90 days. Velesto Energy wins integrated jackup drilling contract Hess E&P Malaysia has awarded Velesto Energy with a contract for the provision of integrated rig, drilling and completion services (i-RDC) for Hess’ 2022 to 2024 North Malay Basin Full Field Development Campaign. The con- tract includes the provision of Velesto’s NAGA 5 jackup. Under the i-RDC con- cept, integration of drilling rig services, 6 equipment and, in some cases, procure- ment of materials for drilling and com- pletion services are covered under a single contract between the operator and one service company as an i-RDC contractor. Velesto will partner with Halliburton as its technical partner to drill and com- plete 14 offshore wells. A new discovery has been announced at the Bavuca South-1 exploration well on Angola Block 15. The well encountered 98 ft (30 m) of high-quality, hydrocarbon- bearing sandstone. It is located approxi- mately 365 km northwest off the coast of Luanda and was drilled in 3,608 ft (1,100 m) of water by the Valaris DS-9 rig. The well is part of the Angola Block 15 redevelopment project, operated by ExxonMobil. The multi-year drilling pro- gram aims to produce approximately 40,000 bbl/day. Tullow signs PSC for Côte d’Ivoire exploration license Tullow Oil has signed a production- sharing contract (PSC) for offshore explo- ration license CI-803 in Côte d’Ivoire. Tullow will operate the licence with 90% equity, with the remaining 10% held by PetroCi. The license strengthens Tullow’s posi- tion in the Tano Basin, where significant prospectivity has been identified within the Cretaceous turbidite plays. These are similar to the plays producing in the adja- cent TEN and Jubilee fields. Precision Drilling bolsters positions in Saudi Arabia, Kuwait with new rig deals Precision Drilling was recently award- ed four contracts in Kuwait, each with a five-year term and an optional one-year renewal. The contract awards are for the company’s AC Super Triple 3000 HP rigs and will increase its active rig count in Kuwait from three rigs to five by the middle of 2023. In addition, Precision recently signed its third drilling rig in Saudi Arabia to a five-year contract extension, following two earlier five-year contract signings last year. With the three contract extensions in Saudi Arabia and the Kuwait contract awards, Precision will have eight rigs under long-term contracts in the Middle East stretching into 2028 and represent- ing approximately $600 million in back- log revenue. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R DRILLING & COMPLETION TECH DIGEST • DEPARTMENTS Robotics module offers new path to scale automation Nabors Industries launched its Canrig Red Zone Robotics (RZR) Rig Floor Module, a modular rig upgrade that auto- mates routine drilling activities in areas like the catwalk, pipe rack, rig floor and derrick. RZR is electric powered, allowing pre- cision control and digital workflows. It enables completely hands-free pipe han- dling and eliminates the need for a crew member to be positioned on the floor and in the derrick. The system autonomously performs repetitive tasks on the rig floor, including making drilling connections and tripping in and out of hole. It enables offline stand-building and handles cas- ing in upper, intermediate and produc- tion sizes. All features are enabled through Nabors’ proprietary rig operating sys- tem, SmartROS, which can be installed on existing rigs and control third-party rig manufacturer’s equipment. RZR is modular and may be deployed on most standard rig configurations to optimize drilling operations and achieve consis- tently best-in-class performance. Nabors has retrofitted RZR to an exist- ing rig, X29. The upgrade was capital- light, according to the company, and was completed at a fraction of the cost of a newbuild rig. The X29 has already drilled multiple horizontal wells for ExxonMobil in the Permian Basin. The RZR technology incorporat- ed learnings from Nabors’ work with ExxonMobil on the R801 fully automated rig. The rig recently drilled nine wells, with well times approaching Nabors’ best West Texas fleet averages. The R801 was purpose built, however, and the companies are now working on validating the use of modular rig retrofits as a viable path to scale drilling automa- tion. Nabors says it plans to integrate RZR into its high-spec rigs over time and will also offer the system to other drilling contractors. SUBSEA SUBSEA CAPPING CAPPING SOLUTIONS SOLUTIONS Our unique capping system provides a comprehensive Our capping system a a comprehensive solution to global deepwater well control incident Our unique unique capping system provides provides comprehensive solution to global global deepwater well on control control incident prevention and response based more than 40 years solution to deepwater well incident prevention and more than of conventional and subsea based well on control prevention and response response based on more experience. than 40 40 years years TM of of Wild conventional and subsea well control experience. Well’s WellCONTAINED conventional and subsea well system control includes experience. 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Stretching 50,000 ft, the well is around 800 ft longer than the previous world record set in 2017. ADNOC Drilling drilled the well from Umm Al Anbar, one of ADNOC Offshore’s artificial islands. ADNOC Offshore designed and led the extended-reach well project in col- laboration with its Upper Zakum part- ners ExxonMobil and INPEX/JODCO. The extended-reach wells will tap into an undeveloped part of the giant Upper Zakum reservoir, with the potential to increase the field’s production capacity by 15,000 bbl/day of oil without the need to expand or build any new infrastructure. Umm Al Anbar is one of Upper Zakum’s four artificial islands, serving as a hub for offshore drilling and operations. DEPARTMENTS • ENVIRONMENT, SOCIAL AND GOVERNANCE ADNOC to apply blockchain to certify carbon intensity Abu Dhabi National Oil Company (ADNOC) and Siemens Energy will pilot blockchain technology to certify the car- bon intensity of a range of products. By using smart sensor data gathered from across ADNOC’s operational chain, the pilot will show how much CO 2 was used to make products such as Murban crude, ammonia and aviation fuels. This infor- mation will be automatically recorded onto a decentralized blockchain ledger. Such transparency will allow inde- pendent regulators to certify the carbon intensity of products. Equinor is leading the use of rigs fitted with emission reduction technologies, with 33,618 contracted days between 2020-2032, while the combined number of contracted days for all other operators is 43,600. Westwood: More incentives needed to accelerate adoption of emission reduction upgrades on rigs New research from Westwood Global Energy Group reveals that the availabil- ity of emission-lowering upgrades for offshore rigs has been on the rise but that adoption of these new technologies is slow outside of Norway and the US Gulf of Mexico due to limited regulatory and financial incentives. The report indicates that the biggest users of rigs fitted with emission reduc- tion technology are those with ambi- tious emission goals of their own, driven largely by Equinor’s Norway and Brazil operations. Between 2020 and 2032, Equinor’s contracted days of low-emis- sion upgraded rigs is 33,618 (92 rig years) compared with the combined number of days for all other operators, which is 43,600 rig days (119 rig years). “Drilling contractors, and the industry as a whole, are starting to realize that oil and gas will be imperative to energy security over the coming years. But that doesn’t need to come at the detriment of the energy transition,” said Teresa Wilkie, RigLogix Director, Westwood. “Rig operators have ambitious Scope 1 reduction targets, and eco-friendly rig technology is keeping pace. The next step is for regulators to work with the industry to ensure that the framework is there to facilitate adoption of these new 8 technologies in a financially sustainable way.” She continued: “Norway is dominating as the biggest user of low-emission rigs, driven by the country’s carbon taxation regulations, as well as incentivization. Pair this with Equinor’s ambitious emis- sion reduction targets and you have a ripe environment for low-emission rig adoption.” Since the downturn in 2014, newbuild rig orders have almost come to a halt due to lack of demand, a mass oversupply of rigs and a resulting stack of new- builds abandoned in shipyards with no work. There is still a lack of appetite to invest in costly newbuilds and, therefore, a deluge of “green” newbuild rig orders is unlikely. Instead, it is expected that more of the current fleet will be retrofitted for lower-emission operations. “Some drilling contractors are at the beginning of their emissions reduction journeys, while others have been work- ing on emission-reducing technologies, projects and studies for several years,” Ms Wilkie said. “By amalgamating the industry’s different and increasing efforts regarding this complex topic, we can better understand the trajectory of the industry, highlight new technologies and identify the areas of opportunity.” Oil and gas expertise to help with well control for CCS Norway’s state-owned Gassnova has awarded eDrilling NOK 10 million under its CLIMIT research program to develop well control software for carbon capture and storage (CCS). The project recognizes that today’s market does not have the well control technology needed to address the risks for underground leakage with full- scale CO 2 storage. By leveraging its experi- ence with well control of petroleum wells, eDrilling expects it can reduce the time and resources needed to launch reliable software for well control in CO 2 wells. The development will also aim for easy inte- gration with existing systems. APA cuts upstream routine flaring in Egypt by 40% APA Corp has achieved a compensa- tion-linked ESG goal to reduce upstream routine flaring across Egypt operations by 40%. The goal was reached ahead of schedule and is the result of numerous emissions reduction projects executed in Egypt throughout 2022. To achieve the 40% flare reduction goal, technical teams in Egypt identified a series of emissions reduction initiatives. The projects included the installation of new compressors to move gas from flar- ing to sales and implementing flare-to- power generation processes that move previously flared gas to power genera- tion, which eliminated the need for diesel- based power generation. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R OIL & GAS MARKETS • DEPARTMENTS >2200 2000-2200 1800-2000 1600-1800 1400-1600 1200-1400 1000-1200 800-1000 600-800 400-600 20 18 16 Million BOED 14 12 10 US growth phase 8 6 Angola growth phase NSTA report: Focus on sidetrack drilling, interventions can boost UK production Namibia’s Graff and Venus expected online in 2027-2028 Guyana’s Stabroek reaches 1 million bbl/day Búzios surpasses 500,000 bbl/day in 2020 on its way to >1.8 million bbl/day Macondo Brazil begins long-run expansion 4 2032 2030 2028 2026 2024 2022 2020 2018 2016 2014 2012 2010 2008 2006 2004 2002 2000 1998 1996 1994 1992 0 1990 2 Source: Wood Mackenzie Lens Upstream Production growth in the deepwater sector to 2032 will be primar- ily driven by Brazil, Guyana and Mozambique as there have been few commercial discoveries in the more mature basins. Deepwater production forecast to climb 60% by 2030 despite cost challenges Global deepwater production will increase 60%, reaching 17 mil- lion BOED, by 2030, according to a report from Wood Mackenzie. This means the deepwater sector will expand from 6% of the upstream oil and gas supply today to 8% by the end of the decade. “Brazil, Guyana and Mozambique are the main growth drivers. Developments are also getting deeper; production from water depths of over 1,500 m will surpass that from 400 to 1,500 m by 2024,” said Marcelo de Assis, Director of Upstream Research for Wood Mackenzie. On the other hand, traditional growth regions, such as the US Gulf of Mexico and Angola, have lacked major new commercial discoveries. “The forecast for mature deepwater basins remains uncertain. We could see production performance begin to peak and then plateau after 2030 without an exploration and invest- ment renaissance,” Mr de Assis said. Cost inflation will continue to be a challenge, with constraints in the global deepwater supply chain leading to increases in lead times and unit costs. The hard-fought efficiency gains made dur- ing previous downturns will start to reverse. The report also points out that deepwater will still remain niche relative to conventional oil and gas. “The future of the deep- water sector remains in their hands of the majors and Brazil’s Petrobras for the foreseeable future,” Mr de Assis said. Drilling activity in the North Sea remained low in 2021 as the industry continued its recovery from the COVID-19 pandemic, but a focus on sidetrack drilling and maintaining existing wells could help boost production, according to the UK’s North Sea Transition Authority (NSTA). The agency is also working to spur more exploration drilling with the launch of the first oil and gas licensing round since 2019 (read more on Page 44). A new NSTA report noted that the UK offshore industry is focusing on faster development, with approximately half of the 66 wells that were spud in 2021 targeting near-infrastructure opportunities. Additionally, 30% of the wells were geological sidetracks, which can be drilled more quickly and at lower cost than new wells. In the report, the NSTA also urged the industry to undertake more well interventions to reactivate production, noting that intervention work was carried out on just 15% of wells in 2021, down from 17% in 2020. This has led to a decline in the perfor- mance of the existing wellstock, with 34% of total active wells on the UK Continental Shelf now shut-in or plugged. Continued low demand may lead to more semis departing North Sea in 2023 Utilization of North Sea semisubmersibles, as well as award activity during 2022, have shown improvement, but a lacklus- ter demand outlook for 2023, especially in the more mature UK sector, could result in more units leaving the region. According to Westwood Global Energy Group’s RigLogix, the North Sea semi supply shrank by 17 units, or 36%, between January 2015 and November 2022, following a prolonged lack of demand for these units. The Island Innovator and Deepsea Bollsta both left last year for new campaigns in Africa, for example. While this shrinking supply will help to buoy utiliza- tion in the near term, it could pose availability issues further down the line if demand picks up, which Westwood predicts may be the case from early 2024. During 2024, Westwood expects to see several new Norwegian developments move ahead because of the tax incentives that were implemented by the government during 2020. Meanwhile, longer-term UK campaigns are likely to start up, consisting of both plugging and abandonment work and development projects. Number of oil and gas contracts down, but contract value rises to $47.7 billion in Q3 2022 The overall number of contracts in the oil and gas industry declined by 7% in Q3 2022, decreasing from 1,662 in Q2 2022 to 1,542 in Q3 2022, according to a recent report from GlobalData. However, there was an increase in the contract value reported, which rose from $38.8 billion in Q2 to $47.7 billion in Q3. Keppel Shipyard helped to keep the momentum during Q3 with its two engi- neering, procurement and construction contracts, said Pritam Kad, Analyst at GlobalData. Combined, those contracts for the P-80, P-82 and P-83 FPSOs are worth $8.76 billion. All three units are destined for Petrobras’ Búzios field (see Page 32). Operation and maintenance represented 53% of the total contracts in Q3, followed by procurement scope with 24%. Contracts with multiple scopes, such as construc- tion, design and engineering, installation and procurement, accounted for 12%. ADNOC Drilling’s two 15-year contracts for eight jackups, worth a combined $3.4 billion, was also notable during Q3, as were ADNOC’s agreements for directional drilling and LWD with SLB, Halliburton, Weatherford, Al Ghaith Oilfield Supplies and Services, and Al Mansoori Directional Drilling. D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 9 CRITICAL ISSUES IN DRILLING & COMPLETIONS Investments in digital systems, sustainability will help drillers carve niche in new landscape Drilling contractors may also need further collaboration with operators to integrate wellsite data, review how risk is allocated in today’s rig contracts Simon Johnson, President/CEO, Seadrill BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Simon Johnson is President and CEO of Seadrill. How would you assess the state of the global offshore drilling market right now? I don’t think it’s that different from pre- vious cycles. We’re facing the same issues that we have in past upticks. We’re deal- ing with cost inflation. It’s getting hard to find personnel. We’re struggling – and our vendors are struggling – with essen- tial equipment deliveries and lead times. Projects are overrunning in cost and time, and our customers are becoming anxious about the impact of that on their work programs. So, it’s familiar muscle memory being reactivated. The difference is that this is coming after the most protracted downturn in our business. A lot of people have left the industry. A lot of organizational knowl- edge and memory is gone. We’re having to re-learn some old ways while dealing with new challenges. How is inflation impacting your busi- ness? It makes it difficult to forecast for your business because you don’t know how that inflation is going to impact projects that you’re planning two or three years out. The vendors themselves are typically just one layer in a very complicated service deliv- ery value chain. It’s layer upon layer upon layer, so the days of dealing with a vendor that has complete control of its business 10 is gone. One piece of equipment might be assembled with different components from all over the world. Can you give an example? An example would be with the dispute in Ukraine. One of the things that many people aren’t aware of is that Russia and Ukraine both produce crucial materials for the manufacture of semiconductor chips, such as inert gases . They are a vital com- ponent in everything from TVs to PCs to the equipment we use on our rigs. This kind of interdependence makes it much more complicated to have a complete understanding of your supply chain and how everything comes together. Staying on the topic of Ukraine, the theme of energy security has become huge, and Europe is in the midst of a burgeoning energy crisis. Given how long it takes to get a conventional oil and gas project going, is there any- thing that can be done in the short term to help alleviate the supply shortfall? I think the industry is absolutely fun- damental to energy security, and there’s no new technology I’m aware of that can substitute for drilling contractors’ critical role of penetrating the reservoir and deliv- ering hydrocarbons to surface. Until there is, we’re fundamental to the production of oil and gas. The countries that have better man- aged their resources and that have good frameworks for consistent investment through time – a good example is Norway – have an opportunity to profit from their approach in the short term. However, as you point out, it takes around six years to take a drop of oil from discovery to production, depending on infrastructure and other issues. It’s a long development cycle. Now, all of a sud- den, a lot of people are worried that they’re not going to have gas to heat their homes this winter. The problems that have caused that situation have their root in a failure to give the oil and gas industry a stable invest- ment environment over the past eight years. In my opinion, drilling contractors, oil and gas companies, and service com- panies have all been decried and actively persecuted. The policymakers and politi- cians didn’t understand that we need a multiplicity of energy sources. It’s not like substituting one for the other. While renewable sources are an important part of future energy needs, they don’t provide that baseload response. They don’t provide the same utility in terms of dispatchable energy. Now we have a problem, but it can’t be turned around through a single policy change. It will take years. I think the short- termism of political processes in countries all over the world – the three- to four-year cycles – doesn’t encourage policy setters to think longer term. We can’t engage with the future with- out understanding that there’s no bridge between that future and how the world works today. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS The last downturn brought about an increased focus on capital discipline. As the market recovers, do you think we’ll see a shift back to more of a focus on investing in rig newbuilds or upgrades? No, I think capital discipline still is the No. 1 concern of management teams. The Chapter 11 process, which most drillers have been through, is still a very recent memory, and there’s a lot of scar tissue around that. The directors of the newly constituted boards, the stakeholders and the investing public – all of them are con- cerned that drilling contractors can’t be trusted when the terms of trade change in their favor. They think we’ll lose sight of that cost discipline and start throwing money at new investments. I don’t think that’s going to happen this time, though, because this downturn has been so protracted and there have been so many painful lessons learned. Also, there’s an understanding that management doesn’t necessarily control these companies in the same way as they did in the past. I think one of the big- gest problems in the industry had been a principal/agent problem between manage- ment and the shareholders. Even though being a drilling contractor is an incredibly capital-intensive business, the manage- ment teams had been left for many years to preside over their businesses with very little direct input from the shareholder base. That’s now changed. There is far more scrutiny on management, and I think that will continue to put capital discipline at the forefront. If we’re not going to see investment being directed to newbuilds, then where will capital go and how do you make sure that your rigs stand out among the competition? Even in an environment of discipline, our business still requires a lot of capital. You’re starting to see some technologies and equipment that were previously the domain of the service companies becom- ing part of the rig equipment set, and that requires a lot of capital. MPD, for example, is becoming far more common, particu- larly in areas like the deepwater Gulf of Seadrill sees the application of data analytics for equipment maintenance and lifecycle management as a key strategy for the company to reduce its total cost of service delivery. These investments into digital systems are likely how drilling contractors will set themselves apart from competitors in the coming years. Mexico and South America. The average MPD setup will run to about $30 million – and that’s excluding the OPEX component. We’re also doing things around digital to gain a competitive advantage. Even through the downturn we’ve been work- ing continuously to develop ways to make better use of our data – for example, to optimize service intervals and mainte- nance activities. Your readers may have seen some of the thought leaders from our Technical Services team sharing our ideas around asset lifecycle management at IADC conferences. We’ve been investing in that because we think it’s going to have an enduring value in terms of our total cost of service delivery. Of course, we’ve also been investing in sustainability, although that’s not so much of a competitive response than it is a stakeholder response. We’re doing that with the understanding that we need to be a good corporate citizen, and we need to respond to the community’s expectations about us minimizing our carbon footprint. There’s also a prospect that this can be a business that generates large dividends to its investors – and if not dividends, then we can consider share buybacks. Basically, anything that returns capital to shareholders that is not utilized by the enterprise. When you talk about investments in sustainability, are you talking about things like selective catalytic reduc- tion (SCR) systems and battery energy storage systems? Yes. We’ve done a lot of work around battery technologies and deployed one of the first battery systems on the West Mira semisubmersible in the Norwegian North Sea. And on the West Saturn, which just commenced work with Equinor in Brazil, we’ve installed a range of new technolo- gies designed to reduce the rig’s carbon footprint, like closing the bus ties on the power distribution and trialing some novel fuel additives. It seems like reducing power usage on the rig is where a drilling contractor is going to see the biggest bang for the buck in terms of emissions reduction. Everything on our rig is powered by the diesel we combust. So, fuel consumption is D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 11 CRITICAL ISSUES IN DRILLING & COMPLETIONS organization as we do about downtime and revenue performance. What would you say to a young per- son looking at this industry for a potential career? Seadrill is trialing novel fuel additives on its West Saturn drillship (pictured) as a means to potentially lower the rig’s carbon footprint. Among other investments into sustainable rig technologies in recent years, the company has also deployed a battery power system on its West Mira semisubmersible. the most measurable, impactful improve- ment that we can make in our activities. But the interesting thing about it is that a lot of people are focusing on fuel injection technology, engine management technol- ogy and emissions controls like SCRs. However, we’re finding that the biggest bang for our buck in terms of improving outcomes is simply to engage the people on the rig in tweaking settings on things like transfer pumps to reduce the ener- gy demand to run the rig. We’re finding smarter ways to distribute the energy on the rig and consume less of it in day-to- day operations. It’s interesting that, in just the last few years, sustainability has shifted from being something that’s nice to have in your portfolio to something you must have in your portfolio. 12 That’s true. We’ve been self-reporting to the Carbon Disclosure Project, a global dis- closure group, on our emissions footprint for the better part of 10 years now. The first thing you need to do on the environmen- tal side is measure your emissions and start tying your activities to a measurable improvement in what you’re doing. But what’s more interesting about the ESG conversation is the governance and community aspects. They might not be as sexy to talk about, but we’ve been doing a tremendous amount of work in terms of our interaction with local communities in the countries where we work. On the governance side, we’re continu- ally advancing our practice in the area of corporate compliance to ensure that we do business in a transparent and accountable manner. It’s all part of the triple bottom line. We get as many questions about the social and environmental aspects of our What I would say to them is that we’re in a period of energy “addition,” not “tran- sition.” Yes, the business has shrunk, but if we’ve learned anything from what’s happening in Europe right now, it’s that a diversity of energy sources is absolutely critical to a country’s security. We must get the young talent re- engaged. They see us as more of a brown- field tail-end industry rather than some- thing that’s going to be an enduring source of employment and professional develop- ment into the future, and that simply isn’t the case. We should also tell them how we’re applying leading-edge technologies. Some of the technology that we’ve developed on the maintenance side with condition- based monitoring is being used in Formula One today. We’re also looking to bring in new types of workers. The industry used to be cast as a heroic scene of a roughneck in torn and dirty clothing. The reality is that our business is increasingly about equipment that will be remotely operated. The people who are going to be most important are not necessarily the equipment operators but rather the system commanders, like data scientists. We’re mining their knowl- edge to improve the systems that run our business. Going forward, it’s going to be less about big muscles and more about big minds. What do you think will be the next step change in reducing major accident risk on the rig? I think it will be a progression of phases. The first step is to get the drilling team off the rig floor so they will be close to, but remote from, the equipment. The next step is to get them off the rig and operating the equipment from shore. The big problem with that, up until now, has been latency, the rate at which we can pass signals backwards and forwards. There’s been a big step in that with Starlink (satellite JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS internet system). In the Gulf of Mexico, we can now get 10 to 50 times faster data transfer speeds compared with conven- tional rig satellite communications. We have more work to do to fully uti- lize that medium, but the speed of data transfer is approaching a level where it makes sense to operate things from shore. I believe there will be a progressive move in that direction over time. When you get latency shrunk down, you start approaching truly real-time data. Is that going to be a game changer for remote operations? That’s right, but I think the most impor- tant thing is not so much the remote operation bit. It’s more about making sure that the person who’s in charge of the equipment can be more of a systems com- mander than an equipment operator, that the equipment is thinking for itself. We’ll be using machine learning and algorithms to make the equipment work in a sophisti- cated manner that is not hampered by the human’s imperfect execution ability. Do you see that automation, in its cur- rent state today, is bringing concrete, quantifiable value to drilling opera- tions? You’re definitely seeing it now. Automatic tripping is becoming a rela- tively common thing. We have that on the West Saturn today, for instance. It’s progressively making its way through the system of work. We don’t have a fully automated system, but we have sequences of work where we can automate them and have confidence in their ability to be robust through time and deliver results better than a human-managed process can. However, drilling a well is a complex series of interrelated steps, so what peo- ple have been focusing on is doing those repetitive steps where the removal of human variability is most valuable. We’re also seeing that sensors have plummeted in cost and skyrocketed in quality, so today’s rigs are much more sensate than they were even five years ago. And as the cost of these sensors gets lower and the amount of information we can gather with them becomes richer, the possibilities open up for not only automat- ing sequences of work but also automating safety processes, things like automated BOP control. Instead of waiting for some- one to go to the BOP panel and close an annular or the pipe rams, we can have a system powered by sensors to make a decision. In what aspects of drilling projects have you seen more collaboration between drilling contractors and operators? Going forward, what are some things that either party can do to advance collaboration? I think the data environment is impor- tant. Historically, there’s been a separation between the data that’s gathered about the control of the equipment at surface and the data that’s acquired subsurface. There have been a lot of issues about confidentiality, but to optimize what’s hap- pening downhole, you need the informa- tion that’s gathered from the equipment that rotates the drill string. We can opti- mize our rate of penetration against the objectives of the operator if we have more data about what’s happening downhole. I think a commonality in terms of that data pool has some great benefits for all parties, not just operators and drilling contractors but also service companies. There are some great lessons that off- shore can learn from the Lower 48 onshore, in terms of how the drilling contractor has acted as the wellsite integrator to bring everything together into one data pool and reduce the number of service interfaces. I think we also need to revisit the con- tractual bargain. There’s a lot of work to be done around business models with regards to alignment of purpose and allo- cation of risk. The model that’s currently in use today is a bit shabby, frankly, and is worthy of some reconsideration and re-contemplation. That will need to be approached from both sides. You mentioned allocation of risk. How has that changed in contracts in recent years, and what work do you think needs to be done to make that fit with the current drilling environment? The typical allocation of risk has been that the reservoir pollution from the well was the operator’s concern, and pollution from the rig, as well as the safety inci- dents and control of our equipment, was our problem. The problem is that, over the years, those interfaces have been chal- lenged and moved around due to changes in the insurance market. Today, the operators have very little insurance to cover their own wellsite risks. Instead, what they seek to do is take the risk that they accept in a drilling con- tract and put that on their balance sheet. In doing so, they now have an interest in redrawing the traditional contractual bargain to their advantage through time by imposing carve-outs and weakening indemnities generally. Through downturns, the offshore drill- ing contractors have been forced – as a commercial necessity – to accept worse and worse terms. Now, we have levels of responsibility and exposure that are unmatched by the commercial reward that’s on offer. You have company-killing risks – around things like blowouts, pol- lution events and the conduct of person- nel – that are completely disproportionate to the incremental revenue that we might earn once you’ve allocated all the costs of running a drilling rig. There are a lot of uncertainties in off- shore drilling, and I would argue that we’re not fully recompensed for the risks that our shareholders are underwriting. Is the dayrate model an adequate model for this economic environ- ment? Does the industry need to move on to something else? It doesn’t really align the interests of operators and drilling contractors, but the problem has always been that no one wants to move on to another model. The customers want to get whatever price is in the market. They don’t want to get caught paying too much, but they also don’t neces- sarily want to get caught paying too little. I think that the dayrate model has prov- en to be a crude but ultimately effective measure that gives the drilling contractor visibility in terms of an earnings profile, but I am not sure it drives the best out- comes at the wellsite or through time. DC D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 13 CRITICAL ISSUES IN DRILLING & COMPLETIONS Renewed focus on safety needed as industry deals with labor shortage amid activity ramp-up Inflation and supply chain are also creating challenges, but communication and transparency between operator and contractor can help both parties Bonnie Black, VP Drilling, Pioneer Natural Resources BY LINDA HSIEH, EDITOR & PUBLISHER Bonnie Black is VP Drilling at Pioneer Natural Resources. What do you see as the biggest chal- lenges that the global drilling industry currently faces? Supply chain and inflation are certainly impacting all operators, but I would say Pioneer is doing a good job of navigat- ing these challenges because of our long- standing partnerships with our contrac- tors and suppliers. These partnerships have allowed us to dampen the effects of inflation, as well as keep our supplies secure. Pioneer plans to run between 24-26 rigs in 2023, so we’ve also been able to leverage our size and scale, but I strongly believe it’s our deep partnerships that have been criti- cal to our success. As the headwinds come, we’re able to approach them with open communication and honest discussions about the risks and challenges. Another challenge that may be a bit more specific to the US or the Permian Basin is the labor issue. All industries are seeking labor, not just oil and gas. And we’re all looking for the same people – the ones we can rely on to show up, not just today but the next day and the next hitch. But unlike other industries, the oil and gas industry is facing a double whammy because we already had a gap in labor dat- ing back to the downturn in 2014 and even further back to the 1980s. Moreover, a lot of our more experienced employees are now looking to retire. All this combined means that we are seeing a lot more short-service 14 employees (SSE’s) on location. These can be individuals new to our industry, to a certain location or to that specific job. It’s not uncommon today to have 30% SSE’s on a drilling location. This has created challenges in safety, and it’s something that we will have to address as an industry. At Pioneer, one way we’re addressing this is by continu- ing to shift the way we approach safety. We’ve left the days of incident-based safe- ty culture behind and are moving toward a more risk-based culture. That means we’re focusing less on what happened in the past and much more on what could happen in the future. We are looking more closely at what risks are out there, what we can prevent, and how we can further engineer people out of the line of fire. find that our two wellsite supervisors on each rig – day and night – are going to be very different from each other. One will be a seasoned supervisor who has great instincts about what’s going to happen on that well. The other will be a lot younger, and he or she might be a degreed engi- neer who is very well versed in cutting- edge technology. This gives us the best of both worlds, combining experience and an eagerness for technology adoption. Then, on top of that, we give them sup- port through a remote command center. They don’t oversee or direct the rigs – they support them. These centers are staffed with even more diversity, including a sea- soned superintendent as well as teams of engineers, operational geologists, direc- tional drillers and data scientists. What are your views on the industry’s efforts to adopt new technologies, particularly around digital and auto- mation? Can you talk a bit more about how Pioneer is using digital technologies to improve your drilling operations? I see our industry making a lot of strides with drilling automation and integrating those technologies with big data to drive increased efficiency. This is really helping to support our field personnel, especially the new workers. Of course, technology brings its own challenges. Rolling out a new technology across a rig fleet is never straightforward. On Pioneer’s rigs, we’ve adopted a lot of diversity to help with these efforts. I’m not talking about gender or ethnic diver- sity but rather diversity in experience, education and job responsibilities. You’ll We are very much focused on using digital technologies to make what we call data-driven decisions. We have built live algorithms that leverage real-time data from our wells to give alerts to our person- nel. These can be alerts for potential stuck pipe or hole-cleaning issues, for example. We’ve also built physics-based models that show us things like offset parameters and torque and drag analyses – all designed to help us make real-time decisions while drilling. Over time, we believe efforts like these can help us to take our lower-per- forming rigs and match their performance to our best-performing ones. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS TOP With plans to run 24-26 rigs this year, Pioneer will leverage both its scale and supplier partnerships to address supply chain and infl ation challenges. BOTTOM Pioneer is pairing seasoned employees with newer ones to supervise its rigs, which the company believes helps to combine experience and an eagerness for technology adoption. Are you looking at technologies that could help Pioneer achieve com- pletely autonomous drilling? Automation is a journey. In the near term, we’re focused more on improving efficiency and safety rather than auton- omous drilling. There are many, many technologies out there; you can’t adopt all of them all at the same time. We have to figure out which ones are a right fit for our operation and which ones will really make a difference in efficiency. It doesn’t mean that we won’t adopt more of them later, but you have to have a priority. With that said, I believe we have built a strong foundation, particularly on the people side with our subject matter experts. Like I mentioned with our command cen- ters, we’re putting together very diverse teams so they can play off of one another’s expertise and technological backgrounds to improve efficiencies. I think that’s what is making drilling exciting again, and we’ve not yet seen the limits of what we can do. Going back to what you said earlier about having deep, long-standing relationships with your contractors and suppliers – can you talk about Pioneer’s approach to building rela- tionships like that? One of the things that we are very proud of is that we approach those vendor rela- tionships as true partnerships. We are as transparent as possible with our plans so that they can also plan their work. We recognize that, in order for them to help us deliver on our projects, they have to know what we need from them and when, with some surety. Communication and transparency are paramount, and that involves having con- versations early and often. If there is potential for our plans to change, we com- municate that with them. At the same time, if our vendors are having challenges around supply chain or labor, there is enough trust in our relationship that they can tell us upfront, and we can try to solve those issues together as early as possible. There seems to be a bigger focus on energy security now than we’ve seen in perhaps decades. Do you see this as a potential turning point for the oil and gas industry? What can we do to turn this into an opportunity to renew our image among either investors or next-generation talent? Without a doubt, there’s been a huge focus on energy security. People are talk- ing a lot more about the energy supply and demand dynamic and whether this is completely a product of the Russia/ Ukraine war. I think that’s been good for our society because it has brought energy security to the forefront. We’ve had limited investment in the oil and gas space for several years, so we definitely have some- thing to prove to our investors. I believe we have to continue to show that we are strong investments that focus on returning free cash flow and a strong return of capital. That is certainly a key focus for us at Pioneer. While we’re seeing a recovery in the onshore drilling market, it seems unlikely that many new rigs will be built soon. So what upgrades to existing rigs and equipment would you like to see in the next few years? Q&A with Bonnie Black, Pioneer, continued on page 31 D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 15 CRITICAL ISSUES IN DRILLING & COMPLETIONS Technology allows drilling contractors to bring added value beyond traditional work scope Rather than focusing on being the lowest-cost provider, H&P says it aims for consistent operations and precise wellbores, whether in US or international markets John Bell, Senior VP, International and Offshore, Helmerich & Payne BY STEPHEN WHITFIELD, ASSOCIATE EDITOR John Bell is Senior VP, International and Offshore, at Helmerich & Payne (H&P). just adds to the complexity of entering and competing in some of these markets. H&P has been very active in markets like the Middle East and Latin America. What do you see as the biggest chal- lenges in increasing activity in those areas? Compared with North America, how are rig and drilling needs different in those non-US markets? On the flip side, where do you see similarities where H&P can apply its expertise gained in North America to improve operations in those other markets? H&P has operated in most countries in Latin America, and we’re in Colombia and Argentina right now. The region is chal- lenging because of various economic and geopolitical issues, which have resulted in a lack of capital being deployed there. This means the level of activity can be incon- sistent and leans toward short-term work. In terms of the Middle East, certainly there’s a lot of capital being employed, but it is a very competitive market. There are also very high barriers to entry. The com- panies that we work with are primarily the national oil companies , and the process that they go through to acquire rigs and pick up providers is a longer process than in the US. There’s also a huge focus on cost, but from our perspective, working with a cus- tomer is about more than just providing the lowest cost. It’s about how you can bring additional value beyond just what has traditionally been viewed as what a drilling provider can provide in these markets. The other hurdle is that it takes signifi- cant capital to deploy assets overseas. You have to prepare the rig, put the rig on a boat and you often have to add additional equipment required by the customer. It 16 For us, it’s less about the rigs – because our rigs can perform the majority of the work that needs to be done in interna- tional markets – and more about the type of work that’s being done. In the US, it’s been almost exclusively unconventional drilling for the last 10 to 15 years, which requires a different mindset, different pro- cesses and different contractual incen- tives. Internationally, outside of the Vaca Muerta in Argentina, it’s still largely a conventional drilling market. We believe we can have a huge impact on these markets as they begin developing their unconventional resources. However, we also believe that a lot of what we do from the standpoint of creating consisten- cy, applying technology, having seamless safety and operational processes, can be very impactful in conventional markets. ing to use more technology and drilling automation to differentiate. That has been our focus over the last handful of years, and it will continue to be our focus. We believe properly applying technology will be a significant differentiator. So digital systems and software are going to play a bigger role than phys- ical equipment upgrades? That’s a fair assessment. The mecha- nization of various key components on the rig will be important, but we’re not looking at wholesale changes to the rigs themselves. There are things we can do around automation that will make a difference, but it’s also just the digital systems we use from the standpoint of the operating sys- tem, from the support system perspective, whether that’s maintenance systems or asset management systems, and making sure we have the right people in the right place with the right skills. It’s also about safety – there are so many things that technology can do to help us better operate the rig from a safety per- spective. What is H&P doing to ensure your rigs will remain competitive over the com- ing years, or are new rigs going to be needed? Automation and digital systems have been a key area of focus within the industry. What do you see as the big- gest gains that drilling contractors have made so far, and what do you see as the next frontier? It’s not about having a different type of rig or having more rigs; it’s about continu- One thing that our customers want is consistency. It helps from a planning per- JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS Top H&P believes the industry must do more to excite the next generation of workers and show them that oil and gas is a part of the solution for the future . The industry also must play up its achievements in sustainability – for example, how increased drilling effi ciency has led to reduced well cycles and less emissions across the board. Bottom Digital systems will remain a key focus for H&P , but they will not diminish the importance of rig crews . This means upskilling drillers will be important, so they can spend less time on repetitive tasks and more time leading on the rig. spective, and it ultimately provides them with lower total well costs. If you drill one well way ahead of the curve but the next one is a mess, it is hard to plan and more than likely your overall costs will be higher in the long run. Automation and technology also allows our customers to scale up and down as they need to. It allows them to combine our capabilities, our technologies, our remote operation centers, and so forth, with their capabilities and other third-party capabili- ties. They end up having smoother and the most precise wellbore, and they get fewer bit trips. You can’t do all these things in unison without technology. Technology also plays a big role in safety, because it allows leaders on the rig to have more time to lead. In the old days when you had a driller on the brake handle, he had to just keep doing that. Nowadays, they’re in a driller’s cabin with joysticks, but how do we allow them to focus on the crews and have time to pre- job plan, stop and adapt when something doesn’t look right or the job changes? It sounds like the driller is still going to play a significant role even as you continue to adopt automated sys- tems onto your rigs. That’s exactly right. It’s about upskill- ing them and enhancing their impact. We want them to have the time to lead. We want them to develop personnel. The more we can help them spend less time on the detailed, repetitive work, the better. How are personnel challenges differ- ent in your international markets ver- sus in North America? What is H&P doing to ensure that its overseas rig crews are as competent and as a part of H&P’s culture as their counterparts in the US? We pride ourselves on having a con- sistent culture and consistent process- es around the globe, not just in the US. Whether you’re in Vaca Muerta, Bahrain, or in West Texas or North Dakota, it looks and feels the same and the people are using the same systems and same pro- cesses to the best of our abilities. Obviously, there are some variations depending on certain countries and lan- guages, but we want those tools to be applied across the fleet. We want to share learnings, and we work hard on that. On your first question, the pandemic is an example of the personnel challenges we face in the international space. The personnel who rotated internationally on our rigs oftentimes came from different countries. They couldn’t just hop in their car and get to the rig from their home. That forced us to think about, one, how can we leverage technology and two, how do we manage our businesses differently when we have those logistical challenges. The pandemic was a transformational event, and it really illustrated the chal- lenges of operating internationally. We improved many of our processes. Can you give some examples of things that you’re doing now that you hadn’t before? D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 17 CRITICAL ISSUES IN DRILLING & COMPLETIONS I think one of the silver linings of the pandemic was that we were forced to col- laborate in ways that we wouldn’t have seriously considered before. We used to fly people all around the world to attend a one-hour meeting. Now we have the abil- ity to share information, solve problems and develop cross-functional teams better than ever before. A lot of it just comes down to collabora- tion and remote communication. The pan- demic meant that we needed to be more agile and create a platform that we could update remotely without having to send a technician on site to physically look at something. Also, we had to create ways to transfer knowledge when we couldn’t send somebody out to the rig. really across the US shale market, look at how much more footage is being drilled per day with how many fewer rigs. These significantly reduced well cycles mean less emissions across the board. Decreased engine use is just one exam- ple. Our carbon footprint has decreased significantly while, at the same time, our footage and production have increased. I think that’s one of those things that people don’t fully appreciate and understand. We need to talk about that, as well as our plans for the future. What impacts have you seen from inflation and supply chain bottlenecks on your business? What do you think drilling contractors can do to minimize the impact of these issues? We have to have these stories in our playbook. We have to talk about the things we’ve done and get people excited. We have a lot of work to do, but we’re a part of the solution for the future, not part of the past. We need them to continue to come up with ideas of how to decrease emis- sions while we continue to provide all the benefits of hydrocarbons. It’s not about hydrocarbons and fossil fuels; it’s about the emissions. We’ve been successful in attracting tal- ent. Yes, it’s going to be harder in the future, but if you have the right story and you help people understand the role they can play in improving lives around the world, that can get people excited. We have a longer planning cycle inter- nationally than in the US. We also have a robust planning cycle within H&P, so most of the time the assets we need come from our US operations, where we have a large volume of standardized components. Obviously, we’re not completely insulated from those supply chain issues, but we can plan for them. The industry has seen a lot more focus on reducing the rig’s carbon emis- sions in recent years. What is your view on this, and has the energy transition had any impact on H&P’s business? The desire to transition away from fossil fuels and the speed with which that takes place, from our view, has to be in proper balance with the need for energy security and the importance of energy affordability. We would love to see solutions grounded in collaboration and objectivity based on data. Certainly, reducing emissions is impor- tant to H&P, and we will continue to look for ways to reduce emissions in the future. But we also, frankly, as an industry, need to emphasize what we’ve already accomplished in that regard. If you look at increased efficiencies in our fleet, and 18 The younger generation of workers coming up have placed an increased value on sustainability. How do you reach out to them? H&P has been a proponent of perfor- mance-based contracts, calling them the “next phase” in its evolution as a service provider. What are some of the hurdles to widespread adoption of performance-based contracts, and how might they be overcome? One of the hurdles is that you have to have a foundation of trust with the customer because, in the end, the reason that performance-based contracts are so attractive to us and to our customers is that we’re focused on the same goals. We’re talking about shared successes, and we’re talking about outcomes that we both see as beneficial to us. In order to do that, you have to do it based on a foundation of trust where we have clarity around how we can both win together. If you really don’t have clarity on how we’re going to work together, and you have different views on what suc- cess looks like, it won’t work. But we see customers like it because everybody is focused on the same outcomes. When you do that, we can all benefit from it. The other hurdle is change manage- ment, and you have to have buy-in all the way from the rotary table to senior management, both with H&P and with the customer. If you don’t have that, you’re just going to stumble all the way. It’s a big change, but it can be hugely impactful when everybody is really clear about how we’re going to win together. What are your main concerns around rig safety right now? What do you see as the next step-change in keeping personnel safe? So, as I said earlier, the cycles that we’ve gone through in the past have made it difficult because you have people mov- ing around between rigs, whether you’re going into a down-cycle or an up-cycle; it just changes the dynamics of the rigs and the crews. It changes what these crews know and how they access data, how they access information and how they interact. Technology is key to creating a consis- tent set of processes and having up-to-date information for pre-job planning steps and so forth. We want these crews and these leaders to have the right tools and infor- mation at their fingertips. That, to me, is really the central aim. The other part of this is, we should always ask what’s working and what’s not working. We have to be careful not to over- complicate programs and lose sight of the core elements of what our safety program is all about. Several years ago, we shifted away from a model of focusing on recordable inci- dents to focusing on serious injuries and fatalities. We overhauled our program and changed our mindset and entire approach to safety. We have to make sure our crews understand why we did that and what that means. We have to continually enhance our processes to make sure that we control and remove exposures that can cause seri- ous injuries and fatalities. DC JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS Industry must fill talent gap for both today and tomorrow as it seeks long-term value creation Petronas looks to school partnerships and upskilling programs, along with automation and integrated contracting strategies, to address key challenges BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Jumasri Terimo is Head of Wells Technology and Technical Assurance at Petronas. From your perspective at Petronas, what do you see as the biggest near- term challenges for the global drilling industry? Currently, getting talents who are the right fit for our sector is a challenge. Learning from several years of downturns, the human capital resources in the drill- ing industry have generally been kept to a minimum level. With the sudden increase in drilling activity we’ve seen, we have seen a need to find the right talents. The significant gap in the level of experience and expertise in talents today has impacted the overall quality of the services rendered, not only to Petronas but to other operators, as well. We have to see what we can do to attract people with the right aptitude and skills to the industry. Can you talk about what Petronas is doing to attract new talent? We look at the education value chain and have built a talent pipeline right from universities, as well as technical and voca- tional education centers. We create better access for youth to attain a quality education, especially in the areas where we operate, by investing in student sponsorship programs. Our sig- nature initiative, the Petronas Education Scholarship Program , which started in 1975, has so far benefitted more than 37,000 students. We have designed programs that meet industry requirements and global standards through Universiti Teknologi Petronas and Institut Teknologi Petroleum Petronas . These two institutions have proven to provide a conducive environ- ment for the development of the next gen- eration of talents, with state-of-the-art facilities, relevant and certified syllabi, as well as expert educators. Petronas also provides various upskill- ing programs and structured training ses- sions to its entire workforce. For example, in upstream, we have a program called All- Rounded Drilling , where new graduates are exposed to classroom and on-the-job training sessions. I think through efforts like these, we have been able to position Petronas as a desirable employer. In 2021, Petronas announced its aspi- ration to achieve net-zero carbon emissions by 2050, and in 2022 you launched a green energy subsidiary, Gentari. How will climate-related goals impact your investments to drill tradi- tional oil and gas wells in the next 2-5 years? At Petronas, we intend to provide the world with the energy it needs today, with consideration for the climate goals of the Paris Agreement. We recognize that each country has its own energy access, afford- ability and security concerns that require a unique spectrum of solutions to address. Jumasri Terimo, Head of Wells Tech- nology and Technical Assurance, Petronas With a strong integrated energy port- folio, we are focused on delivering our core responsibilities while transforming to meet the energy needs of the future – in line with our aspiration to achieve net-zero carbon emissions by 2050. Petronas will produce energy from its core portfolio and cleaner energy solu- tions as differentiated products that are aimed to be safe, reliable, cost optimized and emissions abated. Gentari, a n inde- pendent entity focused on cleaner energy solutions, will capture opportunities in the energy transition alongside our core portfolio through lower-carbon solutions in three offerings – renewables, hydrogen and green mobility. That is our long-term goal. Still, Petronas’ production is still expect- ed to be largely from our core areas in the short- to mid-term period. As of 2018, 63% of Malaysia’s energy mix consists of oil and gas. This is a significant amount even in the future, despite the declining per- centage of oil and gas in Malaysia’s future energy mix. Given this high demand, our invest- ments in drilling new oil and gas wells remain a focus. We are, however, looking to be more effective in how we operate and reduce our emissions in the traditional part of the business. We are working collaboratively with our contractors to see how they can reduce emissions while working on our proj- ects by optimizing our drilling days and improving our efficiency. This translates to lower fuel consumption while the proj- ects are being carried out. This is in line D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 19 CRITICAL ISSUES IN DRILLING & COMPLETIONS What’s important now is for Petronas, together with our service partners, to set the baselines and establish what we are monitoring and controlling. This is a col- laborative effort. Our combined focus will be on driving long-term value creation through responsible investment while collectively reducing our environmental impact and carbon emissions. As we are still transitioning to new tech- nologies, we will be working together with our rig contractors on innovative features to help us progressively adopt decarboniza- tion and emissions reduction compliance. How will operators approach cost reductions in the next couple of years? Petronas sees recruiting and maintaining a skilled workforce as one of the industry’s biggest challenges , particularly as activity picks up. The operator is prioritizing investment in training, like its All-Rounded Drilling program for new graduates. with our efforts to be a low-carbon busi- ness at Petronas Upstream. As we aspire to achieve net-zero carbon emissions by 2050, we are committed to pursue profitable and scalable growth for long-term value creation in cleaner energy development. We will see investments in new technologies to help with continu- ous operational improvement. We are also looking at innovative contracting strate- gies to help provide a sufficient and stable cash flow that will allow us to invest in growth. Can you elaborate on those contract- ing strategies? We have stepped away from the tradi- tional model of paying our business part- ners based on unit price and managing the operation ourselves. The current model sees us bundling services together. We are trying out concepts where we share the risks with our business partners. We com- pensate them on a consolidated basis. By doing that, we are encouraging our busi- ness partners to make their services more efficient and cost-effective. 20 What are some challenges and ben- efits you’ve seen to this approach? By consolidating the contracts, the ser- vice provider has a bigger volume, and it eases our ability to manage our operations. A bundled, integrated contract, or con- solidated deal, also provides better value for our business partners and us. Both par- ties would also share mitigation respon- sibilities. On the other hand, when we integrate everything, the monetary value of each contract is huge. Therefore, if there is any performance issue with a business part- ner, the impact will also be significant. We continue to improve the industry’s health and lucrativeness for as many players as possible. This will allow everyone – be it operators, partners and service providers – to benefit from a robust ecosystem. Going back to sustainability, what would you like to see drilling contrac- tors do in the next two years to help Petronas reach its carbon reduction goals? We really need to focus on improv- ing our efficiency as a way to reduce our costs. The focus areas will be on digitalization, automation and remote operations. That’s how we can improve efficiency and reduce costs, and effec- tively get better project economics. For example, our Remote Operations Platform – piloted at Resak, offshore Terengganu – is expected to gain us a potential 30% OPEX reduction. Most of the potential cost reductions and efficiency improvements for E&P projects will probably be captured in the design phase. Having said that, we can also achieve improvements during the drilling phase with the implementation of digitalization and automation. One thing that we learned from the COVID-19 pandemic was that we don’t need to be in an office setting to be effec- tive. That’s become a good thing for our business as we know we can operate our business remotely and travel less, reduc- ing our carbon footprint in the process. How have supply chain and inflation issues affected your drilling projects? How can companies effectively deal with these bottleneck and cost issues? I think this is something that we can’t really control. We know that the pace of supply of equipment and materials is not as fast as we want, so we have to prioritize our projects. Consolidation will help to stabilize the price even when supplies are low. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS By maintaining rigs for longer periods of time, drilling contractors can offer us more attractive rates and we can maintain the same crew. Longer-term contracts are good for business part- ners because they are able to plan ahead around their resources, equipment and personnel. How can operators and drilling con- tractors continue to innovate on tech- nology while both are maintaining capital discipline ? It is a symbiotic relationship. We need each other. The operator needs the drilling contractor to support our business, and vice versa. This is a win-win situation. Technology is continually evolving, and we must acknowledge that, as part of this maturation, there will be a trade-off in capital investment, given the volatility of the industry and the shift of fiscal focus over the last few years. In the long term, it is crucial for us to pursue and deliver more innovation in the technology space. This will give us posi- tive returns through process optimization, efficiency improvement and ensuring sus- tainability, among other things. Petronas is committed to collaborating with our business partners to tackle chal- lenges and advance the industry together. We believe that sharing resources among industry stakeholders will allow us to innovate and push ahead to achieve col- lective success. This is where advancing technologies together will help us arrive at new capabilities and, ultimately, reap the benefits together. That’s how we are going to evolve. We cannot work in isolation. As the industry strives for cost optimization, con- tractors would need to adapt by maintain- ing good service at reasonable pricing and terms. At the end of the day, we will be at the losing end if we don’t invest. NC50 TSC39 If you look specifically at well comple- tions, what do you see as the biggest challenges and technology gaps in the industry today? What is Petronas focused on? In Malaysia, we are looking at two areas: gas and depleted reservoirs. Our produc- tion is shifting into a more gaseous base. This means we are facing more challenges in designing wells with a higher grade of material for delivering gas . Since 2017, the contamination reading of CO 2 and H 2 S in our Malaysian produc- tion wells has increased from 3% to 10%. The challenges we face today range from choosing the right metallurgy, connection types and completion components. The other challenge is in the sand pro- duction operation. We are working with our partners to optimize our completions sooner, while keeping well costs at a level where we can still yield economic value. DC TSDS42 www.drilllpipe.com C ONNECTIONS FOR EVERY PLAY D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 21 CRITICAL ISSUES IN DRILLING & COMPLETIONS Open architecture, end-to-end solutions can help to advance industry’s digital journey Aker BP working to create full loop for autonomous drilling and new business models with alliance partners as it prepares for a lower-margin future Tommy Sigmundstad, Senior VP Drilling and Wells, Aker BP BY LINDA HSIEH, EDITOR & PUBLISHER Tommy Sigmundstad is Senior VP Drilling and Wells for Aker BP. What do you see as the biggest chal- lenges for the global drilling industry? Ever since the market crashed back in 2014, the service sector in particular has been surviving, more or less, on fumes. That is going to impact us today as activ- ity picks up significantly because, as an operator, we rely on the service sector to deliver on the projects. But with the pace of the increase we’ve seen, and the experience from before 2014, there is great potential for quality problems due to a lack of resources and competent people. That would drive cost and delivery times up, and might end up driving safety in the wrong direction. One competent person cannot be replaced by several less competent indi- viduals. That will only drive up cost, and the quality of the projects will suffer. I think that’s the biggest challenge. What about all the work the industry has done on automation? Is that not helping with this challenge? We’re not far along enough though. Neither digital planning nor automation has allowed us to cut back on resources yet. We still sit on the same crews and same number of drilling engineers. So what value are you able to see now with automation and digital? 22 We’re focusing now on what I call flow efficiency, which means we can do things faster. Digital, in particular, is helping us because we now have better access to the data we need. Our engineers don’t have to go searching for the data in differ- ent databases or Excel spreadsheets. This means they can spend more time building robustness and quality into our well plans. Overall, yes, automation and digital will help with reducing our resource needs for planning and executing projects, but there is still a lot of work to do. Automation has hardly started. Some of the service companies are offering sequences for things like tripping and connections, but you still need a driller to sit there and watch it. That is not solved yet, and it’s a big challenge. At Aker BP, we are getting to that stage now. Like everybody else, we have digital twins and automatic drilling controls, but to actually get an entire loop, we still have some more work that we need to do. I think we can be there within five to 10 years, but we need to have the full loop where we can break down the drilling plan into commands and have it inter- act with the rig-floor machinery. When we can have a digital twin programming machines, that’s when we can have real autonomy. What are the remaining barriers to getting to that point where resource needs can be reduced? With the APIs you mentioned, do you see those being standardized for the whole industry? I think the challenge is that we need an ecosystem. When we have a digital twin, it’s static. It’s the plan. The minute we start drilling and getting real-time data, that static twin becomes a dynamic twin. But just updating the drilling data piece doesn’t help. We also need the formation data, the pressures – everything we need to update the subsurface model, which again needs to inform the drilling plan. We need a digital ecosystem where all the various types of data can talk to each other through APIs (application program- ming interfaces). We will need to have that ecosystem in place before we can really do autonomous drilling. We want open architecture and open source. Yes, we want APIs that are com- mon for the industry. One of my biggest fears is that bigger companies will use this for their competitive advantage, and they will either make silos or vertically integrate. I don’t think that’s the solu- tion. The pockets of oil and gas that we’re drilling for are going to become smaller, so we need to focus more on cost. This means we need to work together and lift this chal- lenge as an industry. If every company just goes about their own way of doing it, it will just drive cost up, and it will take more time. Any timeline in mind? JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS Can you give us a couple of examples of digital projects where Aker BP has seen value? We put a strategy in place around digital back in 2017-2018. It was a very simple plan revolving around the ecosystem I mentioned earlier — planning a well in a day and automation. So far, we have devel- oped the planning piece – we have what we call collaborative well planning (CWP), which digitizes the interface between the subsurface and our Drilling & Wells group, along with the digital well program. This gives us a digital twin. We’re using that in two instances. First, we take a tactical approach. For example, in one well we were drilling, we didn’t manage to follow the planned trajecto- ry, and the team believed they needed to go back and sidetrack. But then they put together a CWP session, where they worked closely with the subsurface team to visualize all the various options. They were able to come up with an alternative plan that saved around 70 million NOK, which is roughly $8 to $9 million. Secondly, we now use the CWP software on all the PDOs we submit, which allows us to deliver the well plans within a much shorter time frame. Moreover, the plans are much more robust than before – I believe the improved quality of our plans will result in large savings without me knowing any specific number. But it is a large number. I will add that we jointly developed both of these pieces of software with our alliance partner Halliburton. We work very closely with them to develop new software that we can put into our opera- tions at Aker BP. This type of collaboration streamlines the process for beta testing new technology, and they can quickly scale it and make it available to other operators. So you’re open to sharing technolo- gies with other operators? Yes, the software is open architecture. So, when those other companies start developing their apps and digital solutions, we can use them, as well. Like I said, we need to lift this challenge together as an industry because it’s going to be expensive Odfjell Drilling is one of Aker BP’s several alliance partners. Through alliances, Aker BP says it is working to build relationships based on trust that will allow both operator and drilling contractor to reduce cost and, in turn, create more work opportunities. to develop these types of software and put them in use. We have actually met with several other operators already, like Hess, Shell and ConocoPhillips. We are sharing because we don’t see this as a competitive advan- tage. How we use the tools and interpret the data — that’s the competitive advan- tage, not having the tools at hand. Do you see the industry embracing the digital mindset as much as we need to? I think we are at Aker BP, but I’m not sure about the rest of the industry. In many instances, I see the mindset of peo- ple is still a barrier. Especially when it comes to things that will impact busi- ness cases, there’s a lack of willingness to change. Do you think that’s because of how volatile our industry is? There’s a lot of conservatism in our industry, and there can be very high con- sequences of something going bad in terms of well control. But automation and digital will require significant investment, and I don’t think any single company can do it alone. So change is necessary. If you take Norway as an example, we will see smaller and smaller pockets of oil, so we need to do more with what we already have. That means more exploration around existing infrastructure. That means infill drilling. That means more interven- tion. For that to be economic, you need to lower your cost or you won’t be competitive. And I can’t think of any improvement bet- ter than digital that can actually help us to transform and lower our costs. D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 CRITICAL ISSUES IN DRILLING & COMPLETIONS Aker BP is working through its drilling alliance partners to invest in technologies that can reduce emissions from rigs like the Maersk Invincible. What are your key considerations when deciding whether to invest in a digital technology? Everything we invest in needs a busi- ness case. One challenge with digital is how do you actually link it to what’s cre- ating value for the company? We’ve been working a lot on this and finding ways to convert it to value for the company and show why we’re investing in it. But we’re also investing in what I call leap of faith, where we invest in something because we believe it is the right thing to do. It’s not straightforward, but as we mature on our digital journey, we are prov- ing why we invested in a technology. Another important thing when invest- ing in digitalization is to define what we call end-to-end solutions. I have spent a lot of time putting Drilling & Wells into the value creation of our company – what kind of value do we actually bring to the table? As long as we can say, this is the part that we are going to digitize now when we create that kind of value, we can build a business case. But still there is a leap of faith when you initially invest in it. Do you find that it’s hard to integrate new digital technologies into existing workflows? 24 Yes, but we have been in a much bet- ter place since we started focusing on these end-to-end solutions. This means our front-line workers are always part of the development process. And every time we put together a use case, we pick where we’re going to use it upfront. We know which team is going to get the technol- ogy, so they are a part of developing the solution. We don’t want to end up with a solution and then you run around looking for a problem. We have to know, what will you use it for? It’s been a few years since Aker BP entered into alliance agreements with Halliburton, Odfjell Drilling and what was then Maersk and now Noble. Can you talk about your considerations when you were selecting alliance partners and share any lessons learned over the last few years? We spent a lot of time in the beginning making sure we picked the right alliance partners. We were not necessarily focused on the technical stuff but more on the mindset and behavior of the organization and the leadership. I wanted to see that we can work together to create more value for each company by establishing a deeper and longer relationship. This was impor- tant because more than 90% of the work within Drilling & Wells is done by the sup- pliers. My thinking is: They need to win if we’re going to win. What we’ve seen with the alliances is they give each company more predict- ability. For example, we give our alliance partners full insights into our five-year plans. For the drilling contractors, that gives them much more predictability on their rig schedules. But alliances also require everyone to do things very differently than what you normally do when you go to the market and act in a more transactional way. Because you have long-term con- tracts, you will shave off the peaks, but you will also remove some of the depths of the dips. You also have much more continuous operations, so you eliminate costs associated with learning curves, start-stops and the frequent equipment mobilization. By working together to reduce cost, we have also opened up opportunities for new work. As an example, we contracted the Maersk Integrator back in 2018 for just nine months, but we ended up having it for five years because we were continuously pushing cost down, so new opportunities came up. Aside from the drilling alliances, we also have an intervention alliance with SLB and Stimwell. In the Valhall area, we have a lot of work on normally unmanned installations, and we found that we were spending a lot of time rigging up and rig- ging down equipment for well interven- tions. So we started running coiled tubing from a jackup from Maersk. That was an inter-alliance setup between Maersk and SLB/Stimwell, and it was a great success creating value for everybody and creating new opportunities that we never thought of a couple of years back. Does something like that come as a result of having an open mindset? You have to listen, and you have to cre- ate trust. Our contractors need to make money. If you’re a contractor that is losing money, there will be no trust and they’re going to move out as soon as you can. We’ve learned a lot from our alliances over the past five years, and we’ve recently JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS renewed both drilling alliances. We have updated our contractual framework and the commercial mechanisms for achiev- ing mutual benefit. I think that will help to drive cost even further down, because we have insights to the risks that our sup- pliers face, which we can help to mitigate. That will help them to reduce their cost, which then benefits us. Do you see the current energy crisis, especially in Europe, leading to any changes in the way countries are approaching the energy transition? In some ways, yes. Before, the green shift was everything people talked about, and everything with oil and gas was bad. But the situation we now find ourselves in shows us that oil and gas is part of the solution. It’s a part of the energy mix. I now see more discussions around the time needed for the transition, and what is it going to cost? Before, the conversation was always around how they need to shut down all oil and gas tomorrow because they’re making a green shift. In my view, wind and solar will never ever replace oil and gas because of the dif- ferences in energy density. Nuclear power plants may be part of the solution. Molten salt reactors can be an example since they have a much higher energy density than solar and wind. But if you ask me what time frame? I don’t know. I still believe that oil and gas will be the most important ingredients in the energy mix until at least the late 2030s. How do you view the investments that drilling contractors have made in emissions reduction technologies? We have worked closely on that with our drilling contractors as part of the alliances, so we actually helped them to invest in this. But I would say that what we’re doing now are just stepping stones. These include hybrid packages, flywheel solutions and urea injection to reduce NOx emissions. We have also done a lot of work on changing the mindset of people – like making sure the motorman knows he should shut down a generator when it’s not needed. I think we’ve achieved more than a 20% reduction just by working with people and changing behaviors. But the question that I’m pondering is, when do we bite the bullet and say we need a different fuel than diesel? At Aker BP, we’ve looked at ammonia, and we’re going to try to run bio-methanol on a jackup within the next year. The biggest problem with alternative fuels is that there’s no infrastructure onshore to support it. That is starting to change in Norway. We’re also working with Odfjell on their offshore windmills and potentially getting electricity down to the subsea templates. In short, emissions reduction is impor- tant, and we are investing, but I think we need another step change. Right now, Aker BP is investing a lot on the production side because it’s the production facilities that are the big emitters. Drilling & Wells is only about 10% of Aker BP’s emissions. But once the production facilities are done, we’ll be in the limelight, too, so we can’t just sit and wait. We are also working with suppliers on four hotspots to reduce emissions: cas- ing, cement, big-volume chemicals and logistics. So we are doing what we can, but I believe that within five to 10 years, we will need to find a way to get to zero emissions on drilling rigs. And what might get us get there, particularly in Europe, is higher carbon pricing. Right now the taxes as alternative pricing makes it hard to create a value stream on investing in technology to reduce emissions. Sooner or later, there will be heavier taxes on emissions, at least in Europe. Then you can get enough of a pricing system where you can invest in new technology to reduce your emissions because the alternative cost is high. How do you view the industry’s chal- lenges around people? A lot of com- panies find it difficult to recruit young talent. The worst thing we are doing as an industry is how we promote ourselves. When we talk about drilling, most often you see a photo on a land rig that looks like it’s 1950, with a roughneck covered in mud. How appealing is that to new talent? How about showing a photo of someone sitting in a cyber chair or in a simulator at our onshore collaboration center (OCC)? Show them how we’re investing in ESG. Show them what we’re doing in digital. We also need to make sure that we are developing engineers who are not working what we call dead-end streets. We have to show them that the technical know-how they develop in our industry can be appli- cable in other industries. That would help to make us more attractive. Personally, one of the things I’ve done at Aker BP is to have very young people run my rigs. Why? Because they think differently, and they want to change. But to do this, we need to create a safety net around them so they don’t make the same mistakes that the previous generations have made. That’s why I involve the more experienced people in early-phase plan- ning and have them do risk mitigation long before it hits the rig line. We’ve seen our productivity increase quite a lot since we did this; it’s really paying off. The other thing is we need to create an environment where people want to work. I’ve been part of building onshore collabo- ration centers before, but they’ve always ended up being fancy meeting rooms. The newest OCC we built at Aker BP has a much more inviting atmosphere, where people actually want to spend time in the break room, where they can mingle and get to know each other. What innovations do you hope to see around well completions? First and foremost, we need to get elec- tricity down to the sandface of the comple- tions. If you think back to what I said ear- lier about needing to do more with what we already have, that means you need to embrace challenges like water produc- tion. Electricity will help, so we can put in valves that can be manipulated. Overall, cost needs to come down, so you need to simplify where you can. Aker BP has a stake in a company called Fishbones. We invested in the company simply because their technology allows us to reduce our stimulation cost. It lowers our cost of installation and reduces the time to production. That’s the kind of tech- nology we need so we can economically drain smaller pools of oil. DC D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 25 CRITICAL ISSUES IN DRILLING & COMPLETIONS Petrobras looks to disruptive technologies to ensure all E&P projects have ‘double resilience’ Innovations like True One Trip, all-electric completions help to support strict goals around cost, emissions João Henrique Rittershausen, Chief Pro- duction Development Offi cer, Petrobras BY LINDA HSIEH, EDITOR & PUBLISHER João Henrique Rittershausen is Chief Production Development Officer at Petrobras. How are you addressing the challenge with rising costs? Does that mean fewer wells will be drilled? What do you see as the biggest chal- lenges for the drilling industry right now? Not at all. We understand that oil prices will always be volatile, so we have built our projects to be resilient even at a Brent oil price of $35 per barrel. In our newest 2023-2027 business plan launched in December, we outlined $78 billion in CAPEX, with 83% going to exploration and production. To ensure project sustainability, all of our projects are planned under the concept of Double Resilience, which means they are resilient both economically to $35 and environmen- tally, with a carbon intensity of only 15 kg of CO 2 equivalent per barrel. Today, the biggest challenge is to com- plete our drilling campaigns on schedule and within budget. We have already seen incremental increases in the dayrates for rigs, and we also see problems in the sup- ply chain due to the low level of operations that the industry had seen in the past few years. While Petrobras has not seen any impacts on the timelines of our projects so far, we do see challenges with the returns of rigs that were in cold stack. Because of the increase in drilling activity, we understand that sometimes the only way to have the rigs we need is to bring them back from cold stack. So, in our planning and our bids, we are allowing more time for the mobilization of those rigs because we understand that the rig contractors and their sub-suppliers are seeing challenges with both people and materials. They need more time to bring those rigs back to nor- mal operation mode in a way that will ensure safety, integrity and reliability. At the same time, we’re also increasing the duration of the contracts we offer to make it more feasible for the rig contrac- tors to invest in bringing the rigs back to operation. Overall, the industry has lost a lot of experienced people in the past few years, so this return in the market is not easy. 26 What is Petrobras doing to ensure this type of resilience for your projects? The answer to this is innovation. When it comes to cost reduction, we cannot just keep doing the same things in the same ways. We need new technologies and new equipment so that we can deliver more cost-effective wells. For example, Petrobras has developed our True One Trip concept, which involves drilling the well in just three phases and installing the completion in one run. We’re also using a drill-through wellhead system to reduce drilling time by avoiding the need to trip the BOP. When you consider the first wells that we drilled in pre-salt years ago, a well would take us more than one year to drill. Today we can drill that well in around 60 days. What about on the environmental side? What are you doing to support emissions reduction from drilling operations? That is very important to the resilience of our projects. Even though we know that drilling operations are not the high- est emitters in our projects, we need to be very connected to this challenge, and everyone must have plans on reducing emissions. When we look at emissions reduction, there are three big areas for us: wells, FPSOs and subsea systems. With wells, the best option to reduce emissions is to reduce the time required for well construction. That’s a win-win because we will reduce both the cost and the emissions. However, we can only do this with cooperation among all the companies involved – Petrobras, drilling companies and service companies, and this means we need to have better equip- ment reliability. In a field like Búzios, for example, where a single well can produce 60,000 barrels per day, reliability is very important. We are also working to increase the effi- ciency of diesel consumption through the use of incentives with our contractors, as well as additive technologies. With FPSOs, we are investing a lot in new designs to reduce emissions – for example, topside electrification, optimiza- tion of the seawater cooling system, as well as carbon capture, utilization and storage. In subsea systems, we are looking at various initiatives like the application of diverless solutions. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS TOP Petrobras awarded a 5.8-year contract last year for the Petrobras 10000 drillship, which offers Transocean’s patented dual-activity technology. BOTTOM Petrobras plans to implement 18 new FPSOs in the next fi ve years, including the P-71 (pictured) . The NOC says it’s investing signifi cantly in new FPSO designs that will allow for reduced emissions. What do you think of when it comes to the future of drilling and wells? We would like to have autonomous rigs and disruptive drilling technologies. In the long term, we would like both our drilling rigs and our FPSOs to be unmanned – but, of course, this is not going to be easy. When you talk about an unmanned operation and autonomous rig, everything must be redesigned, and we need to have much higher levels of reliability than what we have today. I don’t think we can just take today’s rigs and transform them into an autonomous rig; it will require a completely different approach. Digitalization will be a key enabler, and we need to automate the processes around well planning, design and operation, as well as have integration with the supply chain. We will need well structure alterna- tives, high-performance completions, real- time integrity monitoring, rigless mainte- nance, and wells that can self-stimulate and be self-abandoned. Of course, this is all a vision for the future. We don’t have a project saying we will have an autonomous rig within a cer- tain time period, but these are things we are always studying and thinking about. Along the way, it can also inspire the development of other new technologies that we can implement today. In October last year, Petrobras selected seven rigs from a “mega ten- der,” and all the rigs are required to be ready for operation in 2023. What is Petrobras doing to make sure that it will be ready to start so many drilling rigs and campaigns? From Day 1 after signing the contract, we are working closely with the rig contrac- tors to review lessons learned with previ- ous rigs that have undergone acceptance tests. We also have careful planning and talk about how we will commission the rig, then look at their people and skills. When we start a new rig, it’s important that we are not just taking experienced people from other rigs that are already in operation. Also, I would also say it is not unusual for Petrobras to start multiple rigs in a short time period. In addition to the rigs, from 2023 to 2027 we will also be implementing 18 new FPSOs, which will be half of all the FPSOs delivered worldwide in that time period. We will do very detailed planning, and we’ll be successful in starting these operations in the schedule that we need. Petrobras has invested significantly in the Equatorial Margin. How does that region fit into your plans for the next few years? Nearly half of Petrobras’ $6 billion of exploration CAPEX from 2023 to 2027 will go to the Equatorial Margin. It is very important to Petrobras to start working in this new frontier region, and we hope to begin drilling the first well there in early 2023. We believe this frontier has significant potential, and opening this new explora- tion area will bring a lot of value both for Petrobras and Brazil. Q&A with João Henrique Rittershausen, Petrobras, continued on page 31 D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 27 CRITICAL ISSUES IN DRILLING & COMPLETIONS Financial and human capital challenges call for the industry to adopt new ways of thinking Drilling contractors can address workforce, efficiency needs through cultural shifts and capital allocation strategies that focus on long-term sustainability Subodh Saxena, Senior Vice President, Nabors Industries BY LINDA HSIEH, EDITOR & PUBLISHER Subodh Saxena is Senior Vice President at Nabors Industries. What is your outlook for the upstream business, particularly the drilling con- tractor segment, and do you see any looming challenges? There is a lot to celebrate today. Even with some economic uncertainty, the fore- seeable future is positive for our industry as we head into the so-called “supercycle.” Drilling contractors have pulled out a lot of stops to service customers and their need for additional rigs despite challenges around the workforce and the supply chain, so there really is a lot worth celebrating. With that said, I see two key structural issues and challenges that exist within the drilling contractor space. One is around human capital, and the other is around financial capital. In terms of human capital, we have to recognize that today’s workforce requires a sense of purpose, and they want to work for organizations that have a similar sense of purpose. They also need their employers to provide both psychological safety and physical safety. The first element is more of a cultural challenge. Our industry’s culture is some- times not very endearing to the younger generation, and that impacts drillers’ ability to attract, retain and protect our employees. The second element revolves around the industry’s HSE performance, which has struggled in the recent activity ramp-up. That is a huge deterrent to our recruitment efforts. 28 Is that increase in incidents related to the new people coming into our industry? Partly. We do have a younger workforce who need to be coached and mentored. If you go to any rig today, you will see at least 30%, sometimes even 40%, of the workers wearing orange hats, which means they’re a short-service employee. It is our job to protect them and make them aware of all the risks they may encounter during a drilling operation. But these incidents are happening across the upstream sector and not just happening with short-service employees. Whether its drilling, completions or pro- duction, all segments need to be more vigi- lant on safety with all of our employees. Nabors has invested a lot in automa- tion in recent years. Are those technol- ogies helping at all with easing some of these safety challenges? Absolutely, I think technology will play a huge role in removing people from risky activities like working at height or inter- acting with the pipe. A customer once said to me that, in any interaction between pipe and human, the pipe always wins. That is so true. So, Nabors’ approach is to focus on the top tier of the hierarchy of con- trols pyramid, which is elimination of the risk, substitution of the risk, and putting in engineering controls. Automation is definitely part of the solution. Last year we proved we can fully automate any AC rig, which will enable not only Nabors but any drilling contractor to remove crews from red zone areas while delivering consistent best-in-class results to customers. But, like most things, it has to mature.. Going back to what you said about the human capital and how our cul- ture impacts our attractiveness to young workers – can you expand on that a little bit? Younger people today really have option- ality. Drilling contractors are not competing for crews with each other; we are compet- ing for the same people against industries from fast food to the high-tech industry. I think it’s important that people, like me, who have been in the industry for 30 years, understand that the new gen- eration thinks differently. And we have to remember that young people are the only workforce available to us. That means it is up to us to move toward them. We can’t just expect them to move fully toward us, because that is not going to happen. The cultural change involves under- standing who today’s workers are and recognizing that we have to transform ourselves and move toward them. Finally, automation also has a role to play in cultural impacts and the attractive- ness of our industry. Software and robotics are the exact cool factor we need to recruit the next generation to our industry. On your earlier point around the finan- cial capital challenge, does that refer to maintaining capital discipline? JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS That is part of it and is very important, but I believe how we allocate the capital is equally as important. Considering the state of our industry, I believe there are three areas where we need to deploy our capital. First, it needs to go into making our rigs more efficient because that is the only way we provide value to our customers. Second, it needs to go toward improving safety on our rigs because that will help us retain and protect our employees. Lastly, our capital should be spent on improving the general well-being of our employees. What does that general well-being encompass? From a field perspective, today’s work- force is very much willing and capable to work hard for their 12-hour shifts, but when they are off, they want a reason- able quality of living. At a minimum, this means employers need to provide some element of privacy in the living quarters, as well as WiFi. Those investments need to happen. If we don’t do that, we will not be able to attract and retain those employees because they see those things as necessities, not luxuries. Even though our industry appears headed into a supercycle, we know that this will always be a volatile busi- ness. What can drilling contractors do now to better prepare for the next downturn, whenever it may come? We have to take a long-term view, which means focusing on the things that will give us long-term sustainability rather than short-term gains. Traditionally, whenever the demand and supply become tight, the first reaction is to build more rigs. But right now, if a company decides to go and manufacture new rigs, that capital is not being wisely spent. As an industry, we have repeatedly given negative return on investment for the last six to seven years. We have to do things that will bring value for us, for our customers and for our employees over the next 10-15 years. Short- term gains should not be the focus. Are there any new ways in which our industry can approach technology development that will allow us to The newly launched RZR Rig Floor Automation Module is one example of automation that can improve both safety and effi ciency. The system provides full control of tubular handling from the driller’s cabin, removing people from red zones. maintain financial discipline at the same time? One of the challenges we have in our industry is that, because it’s a very com- petitive industry, we somehow believe that we always have to build our own solutions. But if everybody builds their own solutions, I think that can be very destructive in the bigger picture. Despite the competitiveness, we should be able to understand where we can collaborate with our peers and cross- license where it makes sense. We have to overcome this cultural bar- rier of build versus buy. We do not have to build everything; we should be able to buy what is available off the shelf, even if it’s coming from one of my competitors. That is actually an important element of Nabors’ approach, which is to empower other drilling contractors with our tech- nologies. We hope drilling contractors can D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 29 CRITICAL ISSUES IN DRILLING & COMPLETIONS We have made significant progress in deploying technologies that effectively automate the process of drilling, and that eliminates the variability and inconsis- tencies that come with human beings making decisions. You may not get the highest level of efficiency from day one of deploying a technology, but you will get consistency and repeatability. Over time as that technology is optimized, you will start to gain efficiency. Technology deployment is a journey, and how people consume that technology at the rig is really what will make it either a success or a failure. So will humans always be needed at the rig site, even in a highly autono- mous drilling operation? Nabors’ X29 rig has been retrofi tted with the Canrig RZR and has drilled multiple wells for ExxonMobil in the Permian Basin. collaborate with each other to deploy solu- tions that are mutually beneficial. This seems like a big shift away from 15-20 years ago, when contractors pri- marily developed technologies or equipment for their own rigs. Absolutely, it’s a big shift, but it’s neces- sary. Technology today evolves at such a quick pace, and it requires significant investments, so we can’t all invest in everything while maintaining financial discipline. Each drilling contractor has a unique value proposition, so we really don’t need to compete on everything. Find your niche, find where you can prosper and outsource the rest – that way every- body can be successful. Where do you think the next step changes in efficiency on your rigs are going to come from? In today’s drilling operations, between stuck pipes and BHAs that are lost due to twist-offs, well control and other safety issues, the industry loses hundreds of mil- lions of dollars. The step change in effi- ciency is going to come from how we can eliminate those drilling dysfunctions in real time while we are drilling. 30 Drilling contractors’ focus has been to optimize connection and tripping speeds, which are valuable, but those are simpler problems to solve. The bigger problems still remain, and they will require sig- nificant collaboration with customers. By applying data science and other digital solutions, we can create a loop of continu- ous improvement. This will allow for bet- ter planning because we can choose better drilling parameters, and it will help in the execution of the drilling roadmap. Further, when something unplanned happens, it will allow us to course-correct and quickly push out new parameters to the rig. Why do you think we haven’t been able to achieve this before? First, we were very reliant on experi- enced people to mitigate risks. Second, the industry was not using technologies like edge or cloud computing or algorithms for real-time analytics. Those technologies exist now thanks to investments from a lot of technology firms, and we are able to adopt them to create our own digital ecosystem. Can you talk about the progress Nabors has made in eliminating the drilling dysfunctions you mentioned ? I believe so, although the skill sets of the humans will be different. When Nabors launched our newly built autonomous rig, R801, and when we fully automated an existing rig with our new robotics upgrade, the crew sizes were still the same, but we had more software people on the rig. There will always be decisions that need to be made in real time, and I don’t think arti- ficial intelligence has advanced to such a level that they can be taken by machines completely. What would you say are the key enablers to seeing more automation at scale across our industry? They need to be modular, rig agnostic and capital light. As with anything groundbreak- ing, the cost of development is high. For something like that to be a success at scale, the cost – both to the manufacturer and to the customer – needs to come down. There will also need to be a mindset shift, where organizations recognize that they want to use the technology, whether they developed it or not, because it improves performance and HSE, and they have to be willing to go through the required learning curve. Do you see increasing demand from operators for these types of automa- tion technologies? Absolutely. We have deployed our pro- cess and machine automation technolo- gies across our fleet and for various rig JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R CRITICAL ISSUES IN DRILLING & COMPLETIONS contractors in the US, and we have been running them internationally in regions like Latin America. Just recently, we deployed some of our newest automation technology on rigs in Saudi Arabia, which is an exciting milestone for Nabors and the Middle East market. What long-term role do you see drill- ing contractors playing in the energy transition? Q&A with Bonnie Black, Pioneer, continued from page 15 Most of the rigs that we’re running today were built during the boom we saw in the early 2010s. With the pace of today’s drilling operations, we’re definitely push- ing their limits to drill faster and far- ther. As we continue to require more from those rigs in the coming years, we will likely need things like higher torque on top drives, better iron roughnecks, higher racking capacity and probably bigger mud pumps. Pioneer is also very focused on gen- erator management as part of our car- bon reduction efforts and ESG in general. Technologies that can help us to run gen- erators efficiently and minimize diesel usage will be beneficial. Ultimately, we Q&A with João Henrique Rittershausen, Petrobras, continued from page 27 When it comes to innovation for off- shore rigs, what upgrades would you like to see? Today, it is not easy to request big changes in drilling rigs, so we are try- ing to hire rigs that will require the least amount of changes to operate for Petrobras. However, we still see some advancements that would be good, par- ticularly technologies around diesel con- sumption reduction and riserless opera- tions. We would also like to see BOPs with a higher shearing capacity, because when you look at a risk matrix for an oil company, a blowout is the highest risk we have. We need to do everything we can to I see two ways drilling contractors can play a role in the energy transition space. One is by lowering the carbon footprint of their rigs because that is something that is within their control. By deploying or developing technologies, we can reduce the amount of fuel consumption on our rigs. In turn, that will create value for ourselves, for our customers and for the environment. Apart from that, there are a few adja- cent industries where we can play a role. Geothermal is one of them, which is why Nabors has invested in that. I would not say that drilling contractors should go headlong into energy transition projects because they are not necessarily going to be aligned to the core business. It depends upon the strategy that each drilling contractor has. I believe that oil and gas will remain important even as the world’s energy mix diversifies in the com- ing years. DC may also see the industry gravitate toward electrifying rigs and running on highline power. I think there’s a lot of opportunity for both operators and service companies to continue exploring in this space. I don’t have the solution, but I do believe that it is the obligation of everyone who is part of this great industry to help attract the next generation. This means that we have to tell our story and show people how much good we do for people and the planet. For the young people we do attract into our industry, we also need to make sure they understand the role they’re playing in energy security. Compared with previous generations, I think young workers today place a much heavier emphasis on hav- ing a sense of purpose. They’re looking for meaning in their work, and they want to be proud of what they do. That means our industry has to make sure we’re creating an atmosphere where our purpose is not only understood but also appreciated at all levels of the workforce. DC What are your views on the difficulties that our industry faces in attracting next-generation workers? I’m the mom of two college-aged boys, and one of them recently went to a career fair where he said every single company there had a long line of students waiting to talk to them, yet there was no one at the oil and gas table. I think that is very illustra- tive of the challenge we’re facing. The next generation has been persuaded by society that our industry is bad, and that’s hugely problematic for us. ensure we will not have an uncontrolled well. We would also like to see more dynami- cally positioned (DP) rigs that are capable of operating in shallow waters. Today’s environmental restrictions mean that sometimes we cannot use moored rigs to drill and complete shallow-water wells anymore, and we need DP rigs that can allow us to conduct abandonment opera- tions for those types of wells. And, of course, digitalization is a very important point to us because we see automated drilling as the future. We are discussing new initiatives with rig con- tractors and service companies to use automation systems so that, no matter who the driller is, we can always have software that is using the best knowledge of the best driller to control the drilling system. We are confident that automation can increase the efficiency and value cre- ation throughout the drilling process. If we look at well completions specifi- cally, what do you see as the biggest challenges and technology gaps? For us, it’s all-electric completions. We want to move from a mix of hydraulic/ electric to all-electric completions that can be more reliable and cost effective. We are working with several companies to have all-electric completions qualified. Within the next couple of years, we expect to install the first electric, open- hole intelligent completion, and we expect this to be a game-changer for us in terms of reliability and capability to manage the reservoir. DC D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 31 DE E PWATE R DR I LLI N G MAR KETS & TECH NOLOG I E S Fast innovation process allows Petrobras to tap Búzios with lower cost, higher reliability Alignment of well design with technology R&D and procurement strategy among innovations helping to maximize the presalt field’s potential BY LINDA HSIEH, EDITOR & PUBLISHER In the Búzios presalt field offshore Brazil, the numbers are staggering. The thickness of its oil reservoir, for example, can reach up to 480 m, comparable to the majestic Sugarloaf Mountain in Rio de Janeiro. Just one single well on Búzios can reach a production peak of 60,000 bbl/day, and two FPSOs on the field were able to reach their maximum capacities with just three wells. Further, by 2026, the field is anticipated to account for 33% of Petrobras’ total oil production. “Búzios is probably the largest deep- water field in the world, or at least the largest deepwater project in the world at the moment,” Marcos Coradini Tolfo, Well Construction General Manager for the Búzios Field, said at the 2022 IADC International Deepwater Drilling & Human Performance Conference, held in Rio on 7-8 December. He expects Búzios to even- tually produce 2 million bbl/day. To tap the full potential of a giant field like this, Petrobras knew it had to innovate, both in terms of the way it approached technology and in its well construction processes. In the first phase of the Búzios’ develop- ment after the field’s discovery in 2010, Petrobras had been contractually bound to produce only a limited volume. Embarking on the second phase of development – after securing a new contract in 2019 with the Brazilian government to access the rest of the reservoir – Petrobras developed a methodology called Selepoço . It’s a con- cept connecting well design with technol- ogy opportunities in the early stages of the project, Mr Tolfo said. 32 “Usually we would define the design of the well and the technologies that we are going to apply in phase two of the project,” he explained. “But if we wait until phase two, some of the technologies wouldn’t be applicable anymore because of the lead time to apply those technologies.” Recognizing that being able to leverage new technologies would be key to achiev- ing two primary goals – reduced cost and increased reliability – the operator zeroed in on minimizing the lead time to deploy new technologies . This led to the creation of the Well Efficiency Program, or PEP70, where the ambition was to achieve an average well construction duration of 70 days. It defined several focus areas for Búzios, including connecting technology development with the project’s procurement strategy. The other pillars of the program were: well safety, which called for having high- capacity shear rams; top-hole drilling improvements; new completion technolo- gies, including transitioning to electric con- trols; and reservoir scope optimization. Open-hole intelligent completions Mr Tolfo cited Petrobras' open-hole intel- ligent completion technology, called PACI, as an example of the program’s success . Petrobras began looking at the technol- ogy in 2011 in the early days of presalt development, yet the first installation didn’t happen until 2019. “We had eight years from concept to first field installation, and eight years is too long,” he said, noting that Petrobras now aims to reduce that time to four years. Petrobras’ current development plans for the Búzios field, located in the pre- salt Santos Basin, calls for a firm 11 FPSOs. Four of those are already pro- ducing, and a fifth unit is expected to start producing in mid-2023. Six more units are scheduled to be delivered by 2027 , and Petrobras is now considering a potential 12th FPS O. He added that the well where the first open-hole intelligent completion was installed took 91 days to drill and com- plete, and “today we already have one well that was drilled and completed in 65 days.” A dditional work is ongoing to further advance the technology. In 2024, for exam- ple, Petrobras expects to install its first all- electric open-hole intelligent completion, “which we expect will be a game-changer for us in terms of reliability and ability to manage the reservoir,” Mr Tolfo said. In terms of innovations on the drilling rigs working on Búzios, Mr Tolfo said Petrobras is planning to trial NOV’s NOVOS drilling automation platform on one drill- ship, and two other rigs on the field – one drillship and one semisubmersible – will be outfitted with a new shear ram technol- ogy called K-BOS . Multiple rigs on Búzios are also already equipped for managed pressure drilling (MPD) operations. While MPD isn’t exactly new anymore, he said, Petrobras continues to work on enhancing the way MPD is deployed – for example, working through IADC to enhance well control training in MPD operations. DC JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R MANAGED PRESSURE DRILLING Dilution-based dual-gradient technique aims to remove limiters for drilling ultra-deep wells Deeper hydrocarbon, geothermal wells can be enabled by reducing number of casing strings, preserving larger production hole size BY ERIC VAN OORT, LEWIS J. DUTEL AND LUC DE BOER, ULTRADEEP ENERGY COMPANY The industry’s current ability to drill effi- ciently at great depth limits the economic development of ultra-deep oil and gas res- ervoirs, as well as the implementation of the “Geothermal Anywhere” concept, which aims to deliver clean baseload geothermal energy at any location around the world. Dual-gradient drilling (DGD), which was traditionally limited to deepwater and ultra- deepwater well construction, was recently extended to be used in the shallow-water shelf and onshore drilling environments. Using a dilution-based DGD technique, it is now possible to remove technical and eco- nomic limiters while pursuing ultra-deep hydrocarbon and geothermal reservoirs. Reviving the focus on DGD DGD technology received considerable attention in the late 1990s and early 2000s, with coordinated industry efforts such as the SubSea MudLift Drilling Joint Industry Project. Several DGD technologies were considered for deepwater application prior to 2010, including Transocean’s Continuous Annular Pressure Management (CAPM) dilution-based technology, which is a direct predecessor to UltraDeep Energy Company’s technology described here. At the time, DGD-equipped deepwater drill- ships were projected to operate in up to 12,000-ft water depth and drill wells up to 40,000-ft deep. Post-2010, however, DGD technology implementation was negatively affected by a decline in deepwater drilling projects. Later, economic downturns in 2014, 2017 and 2020 also hindered the implementation of DGD technology in deepwater. Pre-BOP riserless mud recovery (RMR) and post-BOP controlled mud level (CML) drilling had become the only surviving DGD variants. Moreover, the momentum of dual-gradient technology was largely lost, as many DGD experts retired from the industry. UltraDeep aims to revive the focus on DGD by introducing an adaptation of the CAPM method, which is based on dilution to produce a dual-gradient fluid profile. This adaptation can be implemented in both onshore and offshore well construc- tion. . The dilution-based technology is a com- bination of new surface and downhole tech- nologies and current, off-the-shelf equip- ment and drilling practices. It exploits the use of a casing annulus to create a dilution injection point at an optimized, engineered subsurface location. Heavy-density mud is injected through the drillstring and used for hole-making. On its return to the sur- face, this heavy mud is diluted with light mud, creating a mixed mud of medium density. The hydrostatic head in the well on the annular side is now determined by two gradients: medium-density mud above the injection point and heavy-density mud below the injection point. Once at surface, the medium-density mud is separated into heavy and light frac- tions using proprietary centrifuge separa- tion equipment. The heavy mud is subse- quently used for drillstring injection, and the light mud resumes its role as a dilution fluid. A proprietary “flow stop” valve is used at the base of the drillstring to pre- vent U-tubing, a common issue in dual- gradient systems due to the difference in hydrostatic head between the drillstring side and the annular side. The dilution-based DGD system can be incorporated on any standard onshore or offshore drilling rig and is complemented with standard MPD system offerings. Figure 1 demonstrates a dual-gradient well versus a conventional single-gradient (SG) well for the same geopressured pore pressure/fracture gradient (PPFG) profile encountered while pursuing a deep hydro- carbon or geothermal target. The SG well wouldrequires eight casing strings and end up with a 6-in. hole at TD. The same well drilled with DG technology would require only four casing strings and can preserve a 12 ¼-in. hole size at TD. Even when employing conventional MPD technology, the SG will be difficult to drill due to a high equivalent circulating density (ECD) exceeding 1.0 ppg, whereas the DG well will have an ECD smaller than 0.5 ppg. Notice in Figure 1 that the DG pres- sure gradient profile is represented by a curve, not a straight vertical line. This is due to the combination of the hydrostatic head of a lighter mud above the dilution point and that of a heavier mud below it. This creates a unique pressure gradient profile that fits the PPFG profile much better than the SG mud weight approach, resulting in a reduction of the number of casing strings required to get to total depth and an associated reduction in the loss of drift diameter. The control over the PPFG profile is based on the dilution weight, the rate of dilution injection, the weight of the heavy drilling fluid, as well as the backpressure applied at surface, which uses a conventional MPD surface backpressure arrangement com- mon in today’s drilling operations. Figure 2 compares the days versus depth associated with the SG and DGD well depicted in Figure 1. Reducing the num- ber of casing seats from eight to four also reduces the predicted days from 140 days to 80 days. The integrity of DGD wells is also expected to be better by having larger cementable annuli. The associated design changes reduce casing and cementing time and costs, in addition to the cost savings from the elimination of casing strings. Moreover, the DGD well design reaches TD with a 12 ¼-in. bit and heavier drill pipe. In the DGD design, force transmission to the bit (weight-on-bit and torque-on-bit) is improved, and harmful drillstring vibra- D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 33 MANAGED PRESSURE DRILLING Click here to see more graphics from this article. Figure 1 (left): A new dilution-based dual-gradient technology allows for well designs with fewer casing strings compared with a conventional single-gradient well, as illustrated in this simulation of an ultra-deepwater gas well in the US Gulf of Mexico. This is primarily because of the more favorable mud density gradient profile (red dotted line) of dual gradient compared with single gradient. Figure 2 (right): For the well shown in Figure 1, reducing the number of casing strings also reduces the pre- dicted days needed for drilling, from 140 for a single-gradient well design to 80 with a dual-gradient design. tions, usually a significant drilling limiter, can be mitigated with a stiffer drillstring. Rate of penetration is expected to benefit from these measures. The larger production hole size is particularly important when pursuing geothermal targets, which typi- cally require larger diameters for produc- tion fluids than oil and gas wells for eco- nomic heat and power production. Application in geothermal well construction New geothermal technologies vary in focus and areas of advancement. Surface technology is generally coupled to a spe- cific subsurface design or targeted heat source. There are also a smaller num- ber of other technologies focused on heat transfer innovations and new wellbore construction methods that deviate from current oil and gas drilling practices. Few of these technologies, however, are at an elevated technology readiness level (TRL), and even fewer are operationally ready for implementation. 34 UltraDeep’s dilution DGD package is at a high TRL and can be deployed with exist- ing land-based drilling rig operations. The integration with standard drilling tech- nologies provide access to deep (15,000- 25,000-ft TVD) and ultra-deep (25,000- 35,000-ft TVD) well construction opportu- nities. The ability to drill these geothermal wells to these depths with large bore is critical to implementing the Geothermal Anywhere concept while drilling through geopressured sedimentary rock in pursuit of deep targets. The large-bore well design at depth pro- vides several benefits, including reduced well construction time and costs, as well as a reduced carbon footprint from rig operations, casing and cementing time. The larger bore at TD is the required con- duit needed to scale heat and energy trans- fer. Additionally, the well integrity and zonal isolation improvements enabled by DGD are essential for long operational life, as well as the ability to implement new technologies restricted to large-bore wells. Accessing ultra-deep gas reserves Sizable deep and ultra-deep gas reserves exceeding 100 Tcfe are present along the US Gulf Coast. From 2000 to 2010, sev- eral attempts to access these reserves were undertaken with various projects, such as Davy Jones, Blackbeard, Joseph, Highlander and Lineham Creek. Except for the Highlander project, the technical and economical limits of con- ventional drilling methods of the time were reached on most of these wells, and the projects ended prior to completion. This was primarily due to drilling prob- lems associated with well control, induced lost circulation and wellbore instability. However, by using dual-gradient drilling technology, in combination with conven- tional MPD technology, the industry can eliminate most, if not all, of this nonpro- ductive time. “Dilution-based dual-gradient drilling” continued on page 36 JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R MANAGED PRESSURE DRILLING MPD-enabled real-time pressure testing helps Shell improve safety in ‘conventionally undrillable wells’ Results from dynamic pressure tests during drilling enable selection of optimal strategies for safer well construction in deepwater GOM BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Shell has registered a ton of experience with managed pressure drilling (MPD) in the US Gulf of Mexico (GOM) over the past four years. Armed with 27 wells and more than 300,000 ft of hole drilled, the company believes it has set a new standard in deep- water safety by leveraging MPD, includ- ing using the technology’s capability to conduct real-time dynamic pore pressure assessments, dynamic formation integrity tests and dynamic leak-off tests. These tests not only helped Shell with pressure management and early kick detection, but they also allowed the opera- tor to redefine target depths while drill- ing, trip and kick margins, well-balancing methods and the cement design. “Most wells where we use MPD are already challenging from a safety and eco- nomic perspective,” said Nathan Tuckwell, Wells Engineering Team Lead – Deepwater MPD at Shell. “Although the well planning process includes detailed formation pres- sure predictions, there are still levels of uncertainties during the actual drilling. Real-time MPD tests have been proven throughout our campaigns to improve the management of the process safety risks associated with these wells.” Speaking at the most recent SPE/IADC Managed Pressure Drilling & Underbalanced Operations Conference in Kuala Lumpur, Mr Tuckwell outlined how two specific tests – the dynamic pore pressure test (DPPT) and a combination of the dynamic formation integrity test and dynamic leak off test (DFIT/DLOT) helped the operator to balance various GOM wells, run casing and then cement. The DFIT/DLOT is the MPD version of the more conventional formation integrity test and leak-off test. Mr Tuckwell discussed the use of MPD, DPPT and DFIT/DLOT on a pair of wells drilled as part of a drilling campaign that began in 2018 using Transocean’s Deepwater Thalassa drillship. This was Shell’s first MPD application in the deep- water GOM for what it called “conven- tionally undrillable wells” – specifically, wells that could not have been drilled without incurring severe circulation losses during drilling, tripping and cementing while simultaneously elevating the risk for safety issues during the well construc- tion process. Key among the MPD system’s compo- nents were an annular surface pressure control system that communicates with the MPD equipment and the rig’s control system. The surface pressure control sys- tem utilizes the capabilities of a central- ized, programmable automation controller with an integrated human-machine inter- face screen. It also allows users to run an integrated hydraulic software model that enables real-time management of the annular pressure profile and monitoring of well construction parameters. Completing hole sections safely In his presentation, Mr Tuckwell talked about one well where the DFIT/DLOT pro- vided real-time information that allowed the operator to determine the maximum kick intensity that the MPD system could handle without exceeding formation lim- its. In the 14 ¾-in. hole section, for exam- ple, Shell was able to determine the safest strategy for drilling the section, tripping out, running casing and then cementing, Mr Tuckwell said. The test began with the MPD choke operator increasing the surface back pres- sure (SBP) in small increments. The flow balance behavior (flow-out vs. flow-in) and the rig active pit level were then observed. In instances where the balance was preserved and the target equivalent mud weight was not reached, the opera- tor proceeded with a subsequent pres- sure increment, repeating all observations until an agreed DFIT value was reached or when a slight loss was detected. This helped to establish a DLOT point. At that final maximum pressure stage, the reading from the pressure-while- drilling (PWD) tool was defined as the confirmed or new limit. The SBP then returned to the original value observed before the start of the test. Before displacing the kill-weight mud into the drill pipe, Shell performed a DFIT test. That test revealed the formation was beginning to leak off and showed losses at 14.3 lb/gal – the presence of leak-off meant that a DLOT test had to be run. For that test, the well was displaced to a 14.1-lb/gal sur- face intensity, with the MPD system main- taining a minimum 14.1-lb/gal bottomhole equivalent circulating density (ECD). The displacement was completed in two stages. First, the drillstring pumps were used to get the 14.1-lb/gal fluid up to the riser. After that, the displacement was finished with the boost only. The BHA was stripped out of the well with the MPD holding the SBP to offset swab. The RCD bearing assembly was retrieved, and the BHA was pulled out of hole conventionally. The DFIT test allowed Shell to identify the point at which the losses started. This was set as the weakest point in the well- bore, providing an actual reference point that otherwise, if not spotted, could have led the operator to overdesign the balanc- ing method for the well, inducing more losses that could have triggered unsafe conditions. “In this case, we just stopped drilling at a certain point and ran the DFIT and DLOT. We saw that the limit was not where we thought it was, and it had actually started leaking off at a point earlier than we expect- D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 35 MANAGED PRESSURE DRILLING ed. We had to make a decision. Where are we going to set our casing? How are we going to adjust the mud weight? Can we keep drilling? We found that this was the best strategy for completing the well safely.” Determining real-time pore pressure Shell has also conducted several DPPTs with the same MPD system. These tests are conducted with returns through the MPD system while pumping downhole through the drillstring with slow rotation. The returns are lined up to a single pit system or a pit with the smallest possible surface area, in order to make it easier to identify and measure any changes in mud volume during the tests. The pore pressure is determined by a real-time PWD measurement. The well is constantly measured, and the volume of any potential influx is measured by a Coriolis flow meter. The test is performed once the bit is at depth. With the MPD system lined up, the rig mud pump section is isolated and the returns are directed to a single pit system. Once the flow rate and all other MPD and rig parameters are stable and the returns are clean, the MPD hydraulic model is cali- brated to account for fluid expansion during each pressure decrease step. The SBP is reduced at small intervals, and all MPD and rig parameters are recorded at each interval. “Dilution-based dual-gradient drilling” continued from page 34 UltraDeep is working to partner with existing leaseholders to utilize the dual- gradient technology to reach additional formation targets of deep and ultra-deep gas shelf and onshore reserves on existing leases. It is worth noting that the production infrastructure needed to commercialize produced gas is within easy reach through existing pipeline networks. When effectively accessed, these ultra- deep gas reserves can supply the growing LNG infrastructure along the Gulf Coast. More than 20 LNG terminals have already been proposed to feed the growing LNG supply chain with Europe. Further, there are important secondary 36 These pressure decreases continue toward a planned target until the MPD system detects a gain. Once seen, the PWD at that point is recorded as an initial flowing pressure, and the SBP is increased to the value required to obtain the same standpipe pressure recorded just before the start of the DPPT. If the SBP amount is within the parame- ters established in the well’s MPD Operating Matrix and Influx Management Envelope when inducing the influx and its volume, the influx circulation can then be per- formed with the MPD system – through the riser, at full circulation rate, with returns aligned to the rig’s mud/gas separator. DPPT tests have helped Shell define the safest strategy to determine the formation pore pressure in real time. In fact, the first such test that the operator performed in the deepwater GOM is used as a reference case to safely optimize all well construc- tion processes in the region, Mr Tuckwell said. This first test was performed using a surface mud weight of 10.3 lb/gal while flowing at 700 gal/min down the drill- string. The test began with MPD targeting an approximately 11.1 lb/gal ECD, which required a 560-psi SBP. The SBP was reduced in small incremental steps during the test. When the ECD reached approximately 10.75 lb/gal while holding 260-psi SBP, the formation pressure was reached and fluid began to enter the wellbore. SBP was increased, overbalance was reestablished, and the influx was stopped, followed by removal of the influx in the well by circu- lating through the MPD equipment while concurrently displacing the well to a 10.8 lb/gal fluid. After further analyzing the data collect- ed from the DPPT, the formation pressure was estimated to be closer to 10.77-10.81 lb/gal. The influx was circulated out of the well and up through the riser using the MPD system to maintain a constant BHP. During the influx circulation, a displace- ment from 10.3 lb/gal to 10.8 lb/gal surface mud weight was also conducted. The DPPT showed that the influx expanded once at the surface. Mr Tuckwell said this was not typically seen in cases where the Coriolis flowmeter was installed downstream of the MPD choke manifold. With this particular well, the Coriolis had been installed upstream of the MPD chokes, and the test revealed that this was an effective solution to determining for- mation pore pressure. DC benefits that can be achieved with the use of DGD technologies, including: The existing pipeline transport resourc- es and proximity to shore can create addi- tional value later in the (ultra-)deep well lifecycle for CO 2 sequestration, where depleted natural gas reservoirs can be coupled with enhanced gas production by injecting CO 2 into the reservoir as it is being produced. This process is known as carbon sequestration with enhanced gas recovery. In addition, highly depleted reservoirs without secondary gas recovery potential may be used for direct carbon capture and underground storage. ■ Wells drilled at great depth have reser- voirs at elevated temperatures, allowing for potential co-production of gas and heat, with the latter to be used for electricity production. In addition, there is the poten- tial to convert wells late in their lifecycle to geothermal wells, harvesting heat long after all natural gas is depleted. Proving dual-gradient technology for onshore and shallow-water wells will de- risk the technology for (ultra-)deepwater applications. Note that true dual-gradient technology has not been deployed in deep- water in forms other than riserless drill- ing, as CML technology is currently only used for ECD reduction. The geographical application of deep- gas DGD technology is certainly not lim- ited to just the US Gulf of Mexico Shelf and onshore Louisiana. There are also similar deep gas targets that can be pursued in areas like the Mediterranean – offshore Israel and Egypt, for example – and the Far East – such as offshore Malaysia and Indonesia. DC For more information, please refer to SPE/ IADC 210541, “Real-Time Downhole Pressure Environment Determination During Managed Pressure Drilling, Tripping and Cementing Operations to Improve Well Construction Safety Standards in Deepwater Gulf of Mexico.” JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R MANAGED PRESSURE DRILLING Machine learning-based pressure management technology brings full automation to MPD operations BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Automation in MPD operations is not new – operators and service companies have been utilizing technologies and software to automate various components of an MPD system for years. Recently, though, Opla Energy says it is bringing its ambi- tions for a fully automated MPD system that can run with no human intervention to reality with its Pressure Management Device (PMD). The device, which is installed above the BOP, is designed to replace conventional MPD systems in both land and offshore rigs. It connects to the rig’s control system and utilizes proprietary machine learning models to process rig data, such as flow rates, mud weights, pressures and rheol- ogy. After users input a desired downhole pressure, the device automatically adjusts the choke position, which is connected to a non-linear closed-loop controller installed with additional proprietary machine learning algorithms, to account for pres- sure changes due to pipe movement and flow rate changes. The machine learning models installed in the device also train it to anticipate potential pressure changes in the future, helping to maintain a consistent downhole pressure throughout the drilling operation. “When you look at a traditional MPD system, in order to calculate the hydrau- lics model needed to maintain a pressure profile, someone typically has to feed the survey results, the BHA, the mud prop- erties and so on, back into the system on location. We’ve done away with that,” said Elvin Mammadov, President of Opla Energy. “This device is really a bi-direc- tional stream of data. It sees the downhole and surface data coming from the well in real time, and we can control and actually change the settings as needed.” Development of the PMD began in 2019, and Opla conducted field trials on a land rig from its parent company Citadel Drilling in September 2021 at the Wolfcamp D shale in the Midland Basin. During testing, the contractor was able to drill one well using the PMD in just eight days, compared with an average 16 days for other wells on the same field drilled with a conventional MPD system, according to Dan Hoffarth, Citadel CEO. The device has also led to a reduction in NPT during rig-up. Rigs operating with the PMD have averaged around 2.5 hours of rig-up time, he added. By comparison, rigs operating with Opla’s conventional MPD packages average 8-10 hours for rig-up. This is because the PMD is designed to use much less piping than a conventional MPD system, so the PMD can fit within a much smaller physical footprint – the company says it is around the size of a coffee table. “As drilling contractors, we’ve have never had so much scrutiny over NPT in our history, so we really need systems that can come to a location and be rigged up in a simplistic manner,” Mr Hoffarth said. “We’re also eliminating a lot of risk, both from an operations perspective and a time savings perspective, by not having all that piping to build up.” After the device was commercially launched in September 2022, a Canadian operator completed the first fully remote, automated MPD tripping operation in December, using the device on a well in the Anadarko Basin in Oklahoma. Significant time savings were realized, according to Opla, because of the efficiency and speed of the machine learning algorithms; they replaced the MPD personnel typically working on location. For the Anadarko operation, Opla report- ed reduced time in drill pipe connections – the rig running the PMD reduced the time for each connection by approxi- mately three minutes compared with rigs using a conventional MPD system. This added up to time savings of approximately Opla Energy says its PMD can fully auto- mate MPD operations by using machine learning models to adjust the choke manifold and account for pressure changes. The device was recently de- ployed in Oklahoma, the company said, to complete a fully remote, automated MPD tripping operation. 5.5-6 hours for the well. The operator also saw significant improvement in bearing assembly change-out operations, reducing the time required from approximately 30 minutes per bearing assembly change on a well with a conventional MPD system to just five minutes, according to Opla. Opla Energy contracts the PMD directly with operators, but it works with drilling contractors to install the device on rigs. The device is currently installed on 12 land rigs, including one rig owned by Citadel, in the Permian, Eagle Ford, Anadarko, Haynesville and Canada’s Montney Shale. For the future, Mr Mammadov said Opla is looking to make potential enhance- ments to the machine learning algorithms around, for example, ROP optimization. “We’re exploring the causes of nonproduc- tive time and seeing how else we can help the well to be drilled even faster. Maybe that means giving suggestions with a push notification sent into the field, or something else.” Further, while the PMD is already suit- able for land and shallow-water drilling because the device’s bearing assembly bowl was designed to replace the above- tension-ring rotating control device (RCD), it can also be modified for use in deepwa- ter. In those applications, where the BOP and the RCD are installed underwater, the bearing assembly can be removed and replaced with a four-way port block that can be used in conjunction with a below- tension-ring RCD. DC D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 37 MANAGED PRESSURE DRILLING New well design and MPD deployed to manage pressure uncertainties in Gulf of Thailand 3-casing design coupled with MPD not only provided flexibility in pressure management but also lowered well construction costs BY STEPHEN WHITFIELD, ASSOCIATE EDITOR While well designs with four casing strings are typical in the Gulf of Thailand, some wells with pressure uncertain- ties call for a different approach. In 2019, PTTEP called on Weatherford to help devise and execute a new three-string design in two wells that would be drilled using managed pressure drilling (MPD). Not only did MPD provide the pressure management flexibility that the opera- tor needed in these wells, but they also reduced the costs associated with having to use a fourth string of casing. This marked the first time that Weatherford had used such a design with an operator in the region, and Harpreet Kaur Dalgit Singh, MPD Project Engineer with Weatherford, discussed the plan- ning process, equipment modifications and drilling results at the most recent SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference, held in Kuala Lumpur in September. “Given the uncertainties of these two wells, we wanted to do things a little bit differently in terms of drilling opti- mization and the cost optimization,” Ms Kaur said. “Instead of forcing a four-string design, let’s incorporate these uncertain- ties into our planning and execution. Let’s think of a different way to drill this hole section. That’s where we thought of the using the three-string with the MPD because we know the benefits of MPD in managing bottomhole pressure.” Weatherford’s work scope involved the drilling of 6 1/8-in. sections in two wells – Well C and Well H – with the lowest and safest mud weights to allow a reduc- 38 tion in equivalent circulating density (ECD) and added surface backpressure (SBP) when drilling and making connec- tions. This would help to minimize the potential for the pore pressure to balloon beyond the range of 1.46 and 1.50, which had been indicated in initial formation integrity testing, and safely stay below the maximum 1.60-SG rating of the cas- ing strings. To accommodate the small platform of the tender assist rig used in this drill- ing campaign, Weatherford made sev- eral alterations to its MPD system before deployment. This included adding a split skid choke manifold, comprising an MPD choke skid and detection skid. The split was needed as the rig-up crane was unable to lift the MPD choke manifold to the BOP deck, where it is normally located. The split also allowed the MPD skids to be lifted from the supply vessel onto the edge of the BOP deck using the tender crane, then moved to the deck center with the help of hydraulic jacks and roller skates. Ms Kaur noted that this approach could be a good option for other MPD proj- ects on rigs with small platform decks. Weatherford also considered alternative rig-up solutions for the rotating control device (RCD) due to the limited space out between the RCD and the rig floor on this rig. A modified 21 ¼-in. bell nipple inner barrel was installed on top of the RCS in lieu of a flowline, and then an RCD rub- ber leak containment line was added that diverted RCD leak flow directly to the mud trough. Planning, drilling and execution Ms Kaur noted that MPD planning typi- cally is guided by the drilling window, with the pore pressure as the lower limits and the fracture pressure as the upper limit. Planning also considers drilling mud weights with wellbore pressures that “walk the line” within a given drilling window. Prior to drilling the two Gulf of Thailand wells, Weatherford ran two simulations on each well. The worst-case scenario planned for each simulation was a bal- looning gradient, which would lead to higher-than-expected pore pressures and a narrow drilling window (approximately 0.1 SG for both wells) to drill the 6 1/8-in. hole section. The best-case scenario was a gradient that allowed the pore pressure to fall within the parameters of the formation integrity test. The simulation also took into account PTTEP’s plan to drill the section with two BHAs – a motorized BHA and an adjust- able gauge stabilizer (AGS) BHA. For Well C, the operator planned to use the motor- ized BHA to drill out the 7-in. casing shoe to a 3,318.5-m measured depth, then drill the AGS BHA from 3,318.5-m to the sec- tion total depth, 4,830 m. For Well H, the motorized BHA would drill out to 3,306.26 m, then the AGS BHA would drill from that point to 4,625.69 m, the section total depth. The simulations helped Weatherford to determine that drilling with an underbal- anced 1.4-1.45 SG mud weight would be sufficient for both wells while keeping the ECD within the drilling window. At that mud weight, the expected pore pressure peak of 1.5 SG for Well C would happen at 3,930-m measured depth. For well H, the expected pore pressure peak of 1.54 SG would be seen at 3,605-m measured depth. For Well C, the static pore pressure test performed at the end of the section total depth recorded 1.58 SG, higher than the maximum expected pore pressure of 1.5 SG. Thanks to the MPD system, the well was successfully drilled to total depth – Ms Kaur noted that the system allowed for higher flow rates to drill the section at points where it encountered unexpectedly high pressure. She also said the pressure measured in Well C confirmed the limitations of the JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R MANAGED PRESSURE DRILLING conventional four-string design. “Looking at the pore pressure, we knew for certain that if we had drilled this well with the standard four-string design or without an MPD system, it was not going to work. We would not have been able to drill to total depth.” The 6 1/8-in. section for Well H was drilled from 2,359 m to 3,306 m with mud weights ranging from 1.40 to 1.45 SG. The pore pressure value recorded during the static pore pressure test (1.46 SG) was at the limit of the three-string design planned for the well. However, the well was success- fully drilled to total depth, again because of the MPD system. Compared with the four-string design, the new three-string design with MPD ended up saving the operator approximate- ly $500,000 per well, Ms Kaur said. DC For more information, please refer to IADC/ SPE 209911, “Gulf of Thailand 4-String Well Design Transformation Using MPD System – Cost Saving, Operational Challenges and Learnings.” A three-casing string well design combined with an MPD system helped Weather- ford and PTTEP to handle pore pressure uncertainties for a pair of wells in the Gulf of Thailand, said Harpreet Kaur Dalgit Singh of Weatherford. Ms Singh spoke at the 2022 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Confer- ence in Kuala Lumpur, Malaysia, on 28 September. INCIDENT STATISTICS RIG RECOGNITION The IADC Incident Statistics Program provides for the recognition of drilling rigs that achieve a one-year period without a lost-time incident or illness. The Incident Statistics Program also provides for recognition of drilling rigs that achieve the accomplishment of operation for a one-year period without a recordable incident or illness. Order an IADC Safety Plaque today! www.iadc.org • 1-713-292-1945 www.iadc.org/health-safety-environment/ incident-statistics-program D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 39 H E A LT H , S A F E T Y, E N V I R O N M E N T & T R A I N I N G Mitigating drops risks through pipe screen replacements, red zone management technology BY STEPHEN WHITFIELD, ASSOCIATE EDITOR Dropped objects have continued to pose a significant safety hazard on drilling rigs over the years. At a DROPS (Dropped Objects Prevention Scheme) meeting on 2 November, industry stakeholders came together to look at two sides of the effort to mitigate potential dropped object risks: removing the dropped object from the rig, and keeping people on the rig away from the dropped object. The meeting featured discussion on the development of a digital system designed to set up “exclusion zones,” or areas of the rig where personnel are not allowed to enter at a given time. It also looked at as the efforts a drilling contractor took in eliminating the risk from a specific dropped object on its rigs. On the drilling contractor side, Ryan D’Aunoy, Senior Manager of HSE Management Systems at Precision Drilling, spoke about various lessons the company learned from its near-misses with one particular dropped object, over- head drill pipe screens. Pipe screens are designed to prevent solids from being pumped downhole while drilling, improving the viscosity of the drilling fluid by filtering out solids. They also prevent blockage of the ports in down- hole tools. Precision utilized two types of over- head pipe screens: Downhole filter screens, which can be placed anywhere in the drill string but are typically installed directly above critical equipment, such as the bot- tomhole assembly, as well as surface drill pipe screens, which are positioned in the top stand of the drill pipe and never go below the rig floor. Mr D’Aunoy pointed out that both pipe screen types require removal and cleaning after each stand, and crew members have to handle them while they’re positioned above the rig floor because there is no way 40 to securely move them into the derrick. This need for manual handling of over- head equipment can introduce potential risk for injury or even fatality. Precision saw four dropped pipe screens in its operations in 2022. Two incidents occurred because the saver sub threads stripped, causing the stand to fall into the pipe elevators. Two other incidents occurred because the drill pipe was rotated out at the top drive and, as the stand was moved to be stabbed into the mouse- hole, the grabber boxes could not hold the weight of the drill pipe. The stand broke free and dropped from the grabber box into the drill pipe elevators. In all four cases, the pipe screens were ejected from the pipe and fell approxi- mately 90 ft to the rig floor. There were no serious injuries or fatalities in either incident. However, the Dropped Objects consequence calculator showed that, if a crew member had been struck by the pipe screen, the incident could have resulted in a fatality. “If a pipe screen was to strike some- body on the rig, you’re definitely looking at a serious injury or fatality potential given the weight of the pipe screen and the heights that they’re falling from,” Mr D’Aunoy said. “As we investigated these incidents, we needed to look at our hier- archy of controls to see what we could do about these screens, maybe see if we could just completely take them out of the equation.” In its investigation of the incidents, Precision discovered that some of its oper- ator clients had begun running inline pipe screens, which are installed in the drilling fluid piping system on the rig floor, instead of above the rig floor. Instead of cleaning these screens after each stand, crew mem- bers clean them prior to running casing, and since they aren’t installed above the rig floor, the dropped object risk is elimi- nated. Precision then decided it would stop using overhead pipe screens. Precision began replacing its overhead drill pipe screens with inline screens in June, with replacements completed for the majority of its rigs by November. While inline screens could be a viable alternative for drilling contractors industrywide, Mr D’Aunoy acknowledged that cost may be a prohibitive barrier for some companies. “You haven’t seen much about these pipe screens being dropped, except around where employees were handling them overhead or placing them into the pipe, because there are no means to secure them,” he said. “Each company has to look at the risk/benefit analysis prior to using these pipe screens overhead. With us at Precision, we’ve gotten to the point where we’re just not going to do it anymore because of the risk.” Keeping people out of harm’s way in red zones During the DROPS meeting, FSC Systems presented its zone management technolo- gy, which combines radio-frequency iden- tification (RFID) with infrared technol- ogy to provide instantaneous feedback to drillers on personnel movements around hazardous equipment through electronic barriers. The system monitors the presence of human activity in pre-determined exclu- sion zones. Infrared sensors are installed throughout the rig and can be combined to create boundaries for the exclusion zones, each of which contains its own unique ID. It does not utilize wearable technology – instead, the sensors are wired directly to a control panel, and when personnel enter an exclusion zone, it provides instanta- neous feedback through an audible alarm. The driller can then stop work in the exclusion zone before a potential incident may occur. The lack of a wearable sensor element means that the zone management system cannot determine exactly who entered a zone, but Brennan Flores, Petroleum Engineer at FSC, said that this system can provide a more cost-efficient alternative compared with wearable systems, making it easier to justify economically. Further, “with the direct connections to the panel, JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R H E A LT H , S A F E T Y, E N V I R O N M E N T & T R A I N I N G there’s none of the noise or interference between wireless units that we’ve experi- enced with the wearables,” he said. The zone management system was not designed exclusively for dropped objects, but it can be used to keep people out of harm’s way during activities where dropped object risk may be higher than normal. However, this requires drillers to have a solid understanding of the dropped object risks on the rig. “If a driller knows they’re moving into pipe tripping operations or whatever it may be, he knows he’s got two or three guys that may need to be out there, and other than that no one else needs to be on the drill floor,” Mr Flores said. “He can set an active exclusion zone, and if anybody goes in and out who shouldn’t be there, we’ll catch it. And then when we do need to turn the zone off, he can just discon- nect it.” The zone management technology is effectively meant to help influence behav- iors, Mr Flores said. Users can monitor exclusion zone entries with a number of parameters to better identify gaps in pro- cedures. Each barrier break is then logged with a date and time stamp, as well as the exact location. Reports can be generated IADC FSC Systems’ zone management system uses infrared sensors to place barriers at various points along a rig floor. Drillers can combine sensor locations to create a barriers around an exclusion zone where dropped object risk is prevalent, said Brennan Flores, Petroleum Engineer at FSC. from this data so that patterns and trends can be drawn for future improvement. “It we catch a particular area of trouble during a specific operation, you can look at your procedures and see if you have some room for improvement,” he said. “Can we change the way this area is laid out? Can we change something during this opera- tion to avoid having these continual bar- rier breaks? The patterns and trends you see from this can help with that.” DC Scan me to access the metric and imperial versions of the DROPS Calculator. bit.ly/3wpCimu Drilling Onshore 3/4 C C O O N N F F E E R R E E N N C C E E 18 MAY 2023 & & E E X X H H I I B B I I T T I I O O N N GOLD SPONSOR H YAT T R E G E N C Y HOUSTON WEST HOUSTON, TEXAS www.iadc.org/event/ 2023-iadc-drilling-onshore- conference-exhibition SILVER SPONSOR EVENT SPONSOR For more information, contact IADC by phone at +1.713.292.1945 or via email at iadcconferences@iadc.org D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 41 IADC CONNECTION • 2023 CHAIR Moderated growth may create healthier business environment for drillers in coming years IADC Chair: Drilling contractors focusing on rig upgrades, not newbuilds, as industry heads into what will hopefully be a longer upcycle BY LINDA HSIEH, EDITOR & PUBLISHER We’re at an exciting time in the drilling industry – not only because rig counts and dayrates have both been going up but also because we’re poised for the possibility of a multi-year upcycle, depending on how the economies in North America, Europe and China evolve in the near term. A lon- ger period of stability is exactly what this industry needs, said Andy Hendricks, 2023 IADC Chairman and Patterson-UTI Energy President and CEO. “If you look over the past decade, we’ve gone through at least three very short- lived cycles in the onshore sector, which creates a lot of challenges from a drilling contractor’s point of view,” Mr Hendricks said. “It doesn’t allow companies to recov- er financially, and it stifles technology growth. But most importantly, it nega- tively impacts our employees. Every time we go through one of these cycles, we have to rebuild our employee base. A multi-year cycle will be very healthy for both drilling contractors and other service companies, whether in the North American onshore, international or offshore regions.” The reason Mr Hendricks is bullish about a longer upturn, he said, is that there has been a fundamental change in the way public E&P operators manage their business. “Several times over the past decade, US producers have ramped up production and chased growth because that’s what their shareholders incentivized them to do. In doing so, it really led to overproduction, which then led to challenges in the global oil markets,” he said. “But now, US produc- ers are focusing much more on returning 42 cash to shareholders. This is actually a huge positive for our industry, as they have been growing but with moderation.” Drilling contractors and other oilfield service companies are also aligning with this philosophy, prioritizing things like dividends, share buybacks and debt repay- ment. “There’s this belief out there that drill- ing contractors have overbuilt the mar- ket. Well, not necessarily,” Mr Hendricks remarked. “We’ve just tried to stay aligned with our customers through these very short cycles. Now that our customers are exhibiting moderated growth, drill- ing contractors, too, will exhibit moder- ated growth. This creates an environment where we’ll likely see a much healthier business environment, possibly for the next few years.” As a result of this capital discipline, North American onshore drilling contrac- tors appear to have no plans to start a newbuild frenzy this time – even though the market is tight and top-tier drilling rigs have been practically sold out since mid-2022. The last newbuild cycle, which ended in 2015, was essentially a retooling of the industry with AC high-spec rigs, but that transition is no longer necessary. “There’s no need to build new rigs. We’d rather just work the rigs that we have,” Mr Hendricks said. That doesn’t mean there isn’t capacity to add rigs, he added, but drilling contrac- tors are focusing instead on upgrading and reactivating existing rigs. At Patterson- UTI, for example, while all of its rigs are at a minimum AC, high-spec rigs, additional work is ongoing to take drilling rigs built before 2013 and make them full super-spec rigs. These can be structural upgrades or other work related to the rig’s electrical or circulating systems. “That’s what we’ve been doing for the last year and a half, and we’ll contin- ue doing that for the foreseeable future because we just don’t see the need to build new rigs,” Mr Hendricks said. Facing challenges on people, emissions While a multi-year upcycle will be posi- tive for the drilling industry, it will also bring associated challenges. Among the most important will be staffing, especially for entry-level rig crews. “The type of work we do – working out- side in the weather and being away from home for 14 days at a time – it’s not appeal- ing to some people,” Mr Hendricks said, adding that even when companies find individuals who are willing to try it, many leave within the first 30 days. “They try it out, and they say, ‘It’s not for me.’ Turnover at the entry-level position is definitely one of our biggest challenges in the US onshore drilling space as an industry.” Automation – which has seen signifi- cant investments from drilling contractors in the past decade – is not yet reducing the number of people required to operate a drilling rig. A drilling rig still requires a lot of manual labor, not just during drill- ing or connections but also during rig moves. “Outside of a few very interesting prototypes, there’s not yet a wholesale automation of things like pipe handling in the onshore space that would allow for a reduction in the crew size,” Mr Hendricks said. In fact, the number of people that work on a drilling rig in the US has only grown in the past four years. “It’s because of the intensity of the drilling operation, which drives the need for extra personnel on locations to manage all the tasks around the drilling operation and keep up with the rig maintenance.” For example, in the Permian Basin, Patterson-UTI’s annual horizontal footage drilled has grown by 160% over the past five years. For drilling contractors, Mr Hendricks said he believes the primary value propo- sition of automatin existing rig systems is JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R 2023 CHAIR • IADC CONNECTION getting repeatability of the best-possible operation. Consistency around tasks like how the bit is set on bottom and how to steer the well, irrespective of the human driller’s level of experience, will help con- tractors to achieve higher efficiency across entire rig fleets. Then, the eventual auto- mation of pipe handling will eliminate the interaction of humans and machines in the red zone. Emissions reduction will be another key challenge for drilling contractors over the next few years. Patterson-UTI has been working at the leading edge of these efforts, launching innovations like EcoCell. This lithium battery hybrid power management system “allows the rig to act more like a hybrid vehicle because it’s not relying on engine power all the time and reduces fuel usage and emissions,” Mr Hendricks said. “I believe that, by working with the E&Ps, we can continue to make a difference and reduce emissions at the wellsite through technology and innova- tion.” Parallel efforts are also ongoing around using highline power and natural gas as alternatives to diesel, which have become more routine onshore. While drilling contractors will continue to invest in emission-reduction efforts and technologies like these, Mr Hendricks said there’s still a big question when it comes to the future of emissions reporting require- ments: Who owns the emissions from the prime movers, like the generators, on a drilling rig? “As a drilling contractor, we don’t deter- mine the specification of the operation. We don’t determine how many generators are required. We don’t determine if a generator gets replaced by a lithium battery solution. We don’t determine the fuel source. Those are all specified by the E&P company,” Mr Hendricks explained. This is a looming challenge that will only become more important as inves- tors, regulators and the public continue to scrutinize emissions levels in the coming years. Mr Hendricks said he believes the drilling industry will need to consider who is the real owner of these emissions and urged companies to have discussions that could lead to an industry consensus among drilling contractors, service provid- ers and E&Ps. Emissions reduction innovations like Patterson-UTI’s EcoCell will be critical in the coming years. The technology uses lithium batteries to store and dispense energy for use in drilling operations, which allows for a steady and optimized load to be maintained on a rig’s generators. The company says EcoCell can reduce rig fuel consumption by more than 20%. Goals as IADC Chairman Looking at his term as IADC Chairman, Mr Hendricks said he is excited about lead- ing a healthy and thriving industry as the association’s members work to advance safe working conditions for everyone on location, improve the onboarding of new employees and continue to push the limits of new drilling technologies. Compared with the first time he served as IADC Chairman in 2017, he believes the optimism permeating the industry today will drive a more productive and energetic term in 2023. “I’m certainly earmarking to travel to a number of meetings and confer- ences in various parts of the world so I can meet with IADC members and hear what their concerns are. We want to make sure that IADC’s programs are addressing the needs of our global membership.” Mr Hendricks also expressed strong sup- port for IADC’s ongoing efforts to promote the drilling industry’s value to external stakeholders. Being able to demonstrate our value to society and improving our public image will be essential to recruiting young talent, he said. “I applaud IADC’s efforts with universi- ties and the student chapter program in terms of getting the message out on what we do and why it’s important,” he said. “When I meet with students at IADC meet- ings, you don’t just meet students in petro- leum engineering. There’s also chemical engineers, mechanical engineers, electri- cal engineers – you get a cross-section, and I think that’s hugely important to help feed talent into our industry.” Regardless of the public’s perception of our industry, however, the fact remains that the world needs oil and gas. While many are choosing to focus solely on the energy transition and renewables, people who work in this industry know that it’s not really a transition but an expansion of global energy requirements for the foresee- able future. “The discussion should not be pitting one energy source against another. As the world’s population grows, we’re going to need all energy sources,” Mr Hendricks said. “Our industry may not be loved, but we’re needed. And we’re going to do our best to help meet the world’s energy needs in a safe and sustainable way. I am proud of our industry’s ability to produce afford- able energy that makes peoples’ lives bet- ter.” DC D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 43 IADC CONNECTION • 2023 OFFICERS IADC Board of Directors elects 2023 officers ANDY HENDRICKS, Chair – Patterson-UTI SCOTT MCREAKEN, Secretary/Treasurer – Northern Ocean Mr Hendricks has served as President and CEO of Patterson-UTI since October 2012 and as a director since June 2017. He previously served as the company’s Chief Operating Officer from April 2012 through September 2012. From May 2010 through March 2012, he served as President of Schlumberger Drilling & Measurements. Prior to that, he had worked for Schlumberger in various worldwide locations and capacities since 1988, including serving in numerous exec- utive positions since 2003. Mr Hendricks holds a Bachelor of Science in petroleum engineering from Texas A&M University. LEIF NELSON, Vice Chair – Seadrill Mr Nelson has served as Seadrill Management’s Executive VP and Chief Operating and Technology Officer since June 2015. Prior to joining Seadrill, he held various operational positions around the globe for Transocean. Mr Nelson is a graduate of the Colorado School of Mines with a BSc in petroleum engineering. JEREMY THIGPEN, Past Chair – Transocean Mr Thigpen joined Trans- ocean as the company’s CEO in April 2015. He had previously spent 18 years at National Oilwell Varco (NOV), where he served as Senior Vice President and Chief Financial Officer. During his tenure at NOV, he spent five years as President of the Downhole and Pumping Solutions business and four years as President of the Downhole Tools group. He also served in various manage- ment and business development capaci- ties. Mr Thigpen earned his Bachelor of Arts in Economics and Managerial Studies from Rice University and completed the Program for Management Development at Harvard Business School. 44 Mr McReaken was named as CEO of the Northern Drilling and Northern Ocean Groups in Decem- ber 2018. He has been a part of the Seadrill group companies since 2012, where he previ- ously served as CEO and Director of Sevan Drilling and Chief Financial Officer of North Atlantic Drilling. Mr McReaken has almost 20 years of experience in the offshore drilling industry, which includes various leadership roles in the United States, North Sea, West Africa and South America. He began his career at Arthur Andersen and is a Certified Public Accountant and Certified Internal Auditor. He holds a degree in business administra- tion from The University of Texas at Austin. TIM McGARITY, Division VP Drilling Services – NOV Mr McGarity serves as Director, Western Hemi- sphere Offshore at NOV’s Rig Technologies. During his tenure with NOV, he has worked both land and offshore in operations and business devel- opment. Prior to coming to the oilfield, Mr McGarity worked in international ship- ping for CP Ships as the manager of the its government/military team. He holds a Bachelor of Science from Texas A&M Galveston and is a veteran of the United States Marine Corps. MIKE GARVIN, Division VP North America Onshore – Patterson-UTI Mr Garvin serves as President at Patterson-UTI Drilling Company. He pre- viously held the position of Senior Vice President, Operations. Prior to that, Mr Garvin worked for Ensco as the Senior Deepwater Operations Manager, oversee- ing the construction of a fleet of deepwater semisubmersible rigs in Singapore and then starting up and managing operations in various locations around the world. Prior to that, Mr Garvin spent 27 years with GlobalSantaFe and its predecessor and successor companies, holding various operations and support leadership posi- tions. Mr Garvin earned a Bachelor of Science degree in engineering from California Polytechnic State University in 1994. BRIAN WOODWARD, Division VP Offshore – Noble Corp Mr Woodward is Vice President of Corporate Services at Noble, where he manages the com- pany’s human resources, information technology, supply chain, and HSE functions. He previ- ously served as Noble’s Global Operations Manager and has held various roles in operations, marketing, investor relations and HSE. Mr Woodward graduated with a BBA in management from the University of Texas at Austin and received an MBA in oil and gas management from Robert Gordon University in Aberdeen. MIGUEL SANCHEZ, Division VP Interna- tional Onshore – Nabors Drilling International Mr Sanchez is Vice President, International Operations for Nabors. He started his career with BP in Venezuela in 1997 before moving to the US, where he held several upstream and downstream roles for BP. He then moved to the services industry, working for Key Energy Services, Saxon Energy Services, Parker Drilling and Weatherford Drilling International. He holds a Bachelor’s in business administration; a Finance Graduate pro- gram from Universidad Metropolitana in Venezuela; and a Master’s degree from the Arthur D. Little School of Management. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R EDITORIAL • IADC CONNECTION IADC: An association by our members, for our members FROM THE PRESIDENT With the start of the new year, I’ve been reflecting on the idea of purpose. At IADC, our purpose is our members. One of my favorite aspects of working here is the member-driven, member-led mentality that resonates throughout the associa- tion. “How will this add value to our mem- bers?” lies at the core of every decision we make. This perspective permeates the cul- ture of our organization. I was introduced to this concept of always putting the mem- bers first early on in my career at IADC when a colleague and mentor, Ken Fischer, shared an article that really encapsulates what it means to be a member-centric organization. The article, “Association Management Adages & Aphorisms,” was published in an association management magazine in 1995. It remains as relevant today as it was when I first read it. One of the most impactful insights from the article is this idea: “The asso- ciation is its members, not its staff. Never forget that members own the associa- tion.” Everything IADC has accomplished in its 80+ years of existence has only been possible due to the dedication of our members volunteering their time, effort and expertise for a collective cause. Our members volunteer an astonishing 20,000+ hours every year in a variety of capacities. Another insight from the arti- cle reads, “The people who pay the fare decide where the ship will go. Likewise, the people who pay the dues….” IADC’s energy, resources and focus go into the projects and goals our members deem most important. A great example of how our members guide the association’s course of action is through their influence on the con- tinuous transformation of our well con- trol training accreditation programs. Investigation reports from Macondo con- cluded that a different approach to well control training was needed. This topic was discussed at length during IADC Well Control Committee meetings, resulting in members deciding that the association’s resources could be utilized to completely redevelop its well control training pro- gram at the time, which was WellCAP. This decision led to the establishment of the WellSharp Advisory Panel, comprised of members who collaborated to deter- mine what this new era of well control training should consist of and how to go about implementing those changes. After hundreds of hours of work put in by doz- ens of volunteers, IADC’s revamped well control training program – WellSharp – launched in 2015 to provide a higher level of comprehensive well control training standards. The WellSharp Advisory Panel and Well Control Committee continue to meet and find ways to further enhance our well control training offerings. The needs of the industry change over time, and our focus must shift accordingly. These mem- bers remain flexible, always integrating industry feedback in order to fine-tune our programs. Recent well control training offerings have been created to meet these ever-shifting industry needs. These pro- grams include KREW, WellSharp Live and WellSharp University. Another excellent example that high- lights IADC’s member-driven nature involves the current project to revolution- ize our Incident Statistics Program (ISP) database. The ISP has been tracking safety and incident information for the drilling industry since 1962. There are currently 73 active participant companies, and over 280 million manhours were reported in 2021. Members expressed a desire to make the process of entering and accessing ISP data more user friendly. The ISP database currently utilizes Microsoft Access, which may have been cutting-edge technology when it was released in the 1990s but is now outdated and has resulted in the ISP data entry process becoming time con- suming and redundant. This reminds me of another insight from the association Jason McFarland, IADC President management article: “ ‘We’ve always done it that way’ isn’t necessarily a reason to change, but it isn’t a reason to keep doing something the same way either. It’s prob- ably a reason to review the procedure.” The fact that members were expressing a desire for the ISP process to change pro- vided ample reason for the procedure to be reviewed. The IADC ISP Subcommittee has been discussing different options, vetting partner vendors and presenting a plan of action. This initiative, like all others that came before it, is being implemented by our members, for our members. The ISP’s proposed new incident statis- tics system will involve an online portal with secure modern features. It will enable a streamlined process with increased effi- ciency for members and better participant experience, as well as improved report- ing integrity and timeliness. We’ve never done it this way before, but in this case, the improvements and changes are both necessary and welcomed. Toward the end of the “Association Management Aphorisms & Adages” article, there’s a section that reads: “You’re in the wrong line of work if you don’t believe what you’re doing makes a difference – to your members, your industry or profes- sion, and society at large. Associations are in the business of working to constantly further and improve something for others.” I wholeheartedly and steadfastly believe that what IADC is doing makes a differ- ence to our members, the drilling industry and society. As an association, it is our responsibility and our honor to continu- ously advance the drilling industry and to make improvements that will better the lives of our members. We’re grateful for how our members show up for us, so that we can continue to show up for them. DC D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 45 IADC CONNECTION • NEWS CUTTINGS IADC issues updated ISP reporting guidelines Paul Mosvold (left), President and COO of Scandrill, received the 2022 IADC Con- tractor of the Year award from Joe Rovig, President, Rig Technologies/Aftermar- ket Group at NOV, at the IADC Annual General Meeting on 4 November. Paul Mosvold named 2022 IADC Contractor of the Year Paul Mosvold, President and COO of Scandrill, was named 2022 IADC Contractor of the Year in November. The annual award, which was established in 1988 to recognize an individual drill- ing contractor’s outstanding lifetime achievement in technical innovation, safety and economic efficiency within the drilling industry, is the only industry award reserved exclusively for drilling contractors. A member of IADC’s Executive Committee and North America Onshore Advisory Panel, Mr Mosvold was appoint- ed to his current position at Scandrill in 2014. He has spent much of his profes- sional career with the company, starting in 1982 when he worked as a roustabout and roughneck on a Scandrill barge rig. Following graduation from Houston Baptist University in 1988, Mr Mosvold worked primarily in shipping, includ- ing a stint as Operations Manager at Palmer Navigation, an independent ship- ping company, where he traveled exten- sively in the Middle East, India and South America. He returned to Scandrill in 1997 as Marketing Manager and later became VP of Health, Safety and Environment before taking over in his current role. IADC has updated its Incident Statics Program (ISP) reporting guidelines in its entirety for the first time in 12 years. The revised guidelines are now available as an evergreen document for public access on IADC’s website. The revisions were made by IADC’s ISP Subcommittee, which operates under the Health, Safety, Environment & Training (HSET) Committee. The group focused pri- marily on updating outdated links to con- tact various regulatory agencies, such as the US Food and Drug Administration, as well as incorporating answers to frequent- ly asked questions into the document. Additionally, an online question submis- sion form was added for users to submit inquiries about the ISP reporting guide- lines; a link can be found at iadc.org/isp. These revisions were the first step in a wider-scope project to update the entire ISP system. The ISP Subcommittee is now working to update the system with an online portal that will allow real-time access to reports and data. Work on the online portal began in January and is expected to continue through late summer 2023. Scan me to access the updated ISP reporting guidelines. bit.ly/3kkAU1L Nigeria Chapter holds 2022 Annual General Meeting in Lagos, elects officers The IADC Nigeria Chapter held its Annual General Meeting on 17 November in Lagos. The event was attended by 35 delegates. At the meeting, the officers gave an overview of the chapter’s financials and a draft budget for 2023, and then held elec- tions. The 2023 officers elected include: Valentine Iheasirim, Chair Abioye Shokoya-Eleshin, Vice Chair Anne Sobo, Secretary Stella Okene, Treasurer The Nigeria Chapter’s membership has grown from 46 members in 2021 to 56 members in 2022. 46 Pictured at the IADC Nigeria Chapter meeting are (from left) Ann Dominic, Nige- ria Chapter Social Media Manager; Hisham Zebian, IADC VP Eastern Hemisphere; Abioye Shokoya-Eleshin, Chapter Vice Chair; Chuks Enwereji, former Chapter Chair; and Juliet Adesunloye, Chapter Administrative Officer. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R NEWS CUTTINGS • IADC CONNECTION IADC recognizes Sarah Kern, Nathan Moralez with Exemplary Service Awards Helmerich & Payne’s Sarah Kern and BP’s Nathan Moralez each received IADC Exemplary Service Awards on 3 November at the 2022 IADC Annual General Meeting in New Orleans, La. Ms Kern, who serves as Senior Industry Affairs Analyst at H&P, recently com- pleted a term as Co-Chair of the IADC Young Professionals Committee and now leads the IADC Advanced Rig Technology (ART) Committee as Co-Chair. She also serves on the Program Committees for the IADC ART Conference and the IADC/SPE International Drilling Conference. Mr Moralez, BP Senior Rig Automation Engineer, has been active with the IADC ART Committee since 2015 and has served as Chair of ART’s Data, Controls and Sensors Subcommittee since 2018. Sarah Kern (left) and Nathan Moralez (right), pictured with IADC President Jason McFarland, received Exemplary Service Awards in November. IADC Brazil Chapter honors 23 rigs at annual safety awards Pictured at the IADC Brazil Chapter’s safety awards ceremony in December are (from left) Leandro Luzone, Chapter Secretary; Adriana Pais, Chapter Administra- tor; Mardonildo Filho, Chapter Chair; Marcelo Pombo, Diamond Offshore, whose Brasdril subsidiary received an award for the Ocean Courage; Aristeu Andreatta, Chapter Vice Chair; and Roberto Paschoalin, IADC Regional Advisory for Brazil. The IADC Brazil Chapter recognized 23 rigs, owned by eight contractors, at its annual safety awards ceremony on 3 December. The awards are given to rigs that have operated in Brazil for 12 months without a lost time incident (LTI). The rigs honored at the awards cer- emony are: Brasdril: Ocean Courage Constellation: Alpha Star, Brava Star, Gold Star, Lone Star Helix: Siem Helix 1, Siem Helix 2 Ocyan: Norbe VI, Norbe VIII, Norbe IX, ODN I, ODN II Seadrill: West Carina, West Jupiter, West Saturn, West Tellus Transocean: Corcovado, Driller III, Mykonos, Petrobras 10000 Valaris: DS-15 Ventura: Carolina, SSV Victoria SAPC holds Q4 2022 meeting in Dubai, reelects chapter officers IADC’s Southern Arabian Peninsula Chapter (SAPC) held its Q4 2022 meet- ing on 11 November in Dubai. The meet- ing saw 97 people in attendance. The meeting also featured three guest speakers: Maria Conceicao, Founder of the Maria Cristina Foundation; Ravi Mishra, Regional Manager – Middle East at Axess Group; and Davendra Rajcoomar, Operations Manager at the Callen Group. Each of the current chapter officers also were reelected for another year: Wayne Bauer, Chair Doug McEwan, Vice Chair Gareth Burrows, Secretary William Devoto, Treasurer The SAPC is based in Dubai and primarily represents member compa- nies in the UAE, Oman and Qatar. The chapter holds quarterly meetings in addition to social functions, includ- ing an annual golf tournament and gala dinner that often attracts more than 1,000 attendees. The next SAPC golf tournament is scheduled for 16-17 March and will mark the 25th anniver- sary of the event. The chapter has also scheduled its Q1 2023 meeting for 10 February in Dubai. D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 47 IADC CONNECTION • WIRELINES BOEM announces Lease Sale 259 in US Gulf of Mexico will be held on 29 March The US Bureau of Ocean Energy Management (BOEM) has proposed to hold Lease Sale 259 in the US Gulf of Mexico on 29 March. Under the terms of the US Inflation Reduction Act, BOEM must hold Lease Sale 259 no later than 31 March. In response to BOEM’s announcement, IADC issued a statement urging the Biden Administration to complete its pre-lease obligations in a forthright and responsive manner. “With the Administration having sold over 32% of the Strategic Petroleum Reserve’s 714-million-barrel reserves, the nation’s emergency crude stockpile is now at its lowest level since 1984. In this con- text, the urgency for increasing offshore exploration and production in the United States cannot be overstated. Signaling a sincere commitment to stabilizing global energy markets via increased domestic offshore hydrocarbon production would bring much needed certainty to tenuous global energy markets,” IADC President Jason McFarland stated. In January, the BOEM also issued its Final Supplemental Environmental Impact 115 bids received in UK’s 33rd offshore licensing round The UK’s 33rd offshore oil and gas licensing round attracted 115 bids across 258 blocks and part-blocks from 76 companies, the North Sea Transition Authority (NSTA) announced in January. The round was opened in October as part of efforts to boost the UK’s energy security. To encourage quick production – in as little as 18 months, the NSTA said – four cluster areas that have known hydrocar- bons have been prioritized in this licens- ing round. That compares with an aver- age time of nearly five years between the dates of recent discoveries and first production. The 33rd round attracted similar inter- est to the 32nd licensing round in 2019, which received 104 applications from 245 blocks and part-blocks. In 2019 a total of 768 blocks and part-blocks were offered, compared with 931 in this round. Of the 931 blocks and part-blocks of- fered in the UK’s 33rd offshore oil and gas licensing round, 258 received bids from 76 companies. The NSTA said it will prioritize licenses for blocks that have the potential to produce quickly. Statement (EIS) for both Lease Sale 259 and Lease Sale 261. The latter sale will need to be held by September 2023 as directed by the Inflation Reduction Act. The EIS iden- tifies baseline conditions and potential impacts of oil and gas E&P. Scan me for more information on GOM Lease Sale 259. bit.ly/3Qd1Oob API signs MOU to support Ukrainian energy sector API and the State Enterprise “Ukrainian Scientific Center for Standardization, Certification and Quality Problems” signed a memorandum of understanding (MOU) to promote the adoption of API oil and gas standards and cooperate on a range of activities, such as: Promoting the adoption and utilization of API standards in Ukraine’s oil and natu- ral gas industry; Facilitating participation on API Standards Committees by Ukrainian sub- ject matter experts; Driving standards harmonization in Ukraine and facilitating greater standards cooperation in the region; Encouraging the exchange of informa- tion and capacity building between the two organizations; and Jointly organizing standards, training, certification and safety activities. EPA issues new rule on heavy-duty engine emissions API, AMEXHI, IOGP renew collaboration agreement The US Environmental Protection Agency (EPA) adopted a final rule that sets more stringent emissions standards for a wide range of heavy-duty engine operating conditions. The rule also changes key provisions of the existing heavy-duty emission control program, including test procedures, regulatory useful life and emission-related war- ranty. The EPA said its aim is to reduce air pollution from heavy-duty engines and vehicles. It estimates the new rule will reduce NO x emissions from heavy-duty API, the Asociación Mexicana de Empresas de Hidrocarburos (AMEXHI) and the International Association of Oil & Gas Producers (IOGP) have renewed a memo- randum of understanding (MOU) focused on cooperation and enhancing operational performance in North America. The MOU establishes mechanisms for partnership and coordination, includ- ing joint forums; technical workshops on areas such as offshore safety; and the sharing of good practices on environmen- tal performance, sustainability, emergency response and other areas. 48 vehicles in 2040 by more than 40%. By 2045, a year by which most of the regu- lated heavy-duty engine fleet will have turned over, it estimates that NO x emis- sions from heavy-duty engines will be almost 50% lower than they would have been without the new rule. Scan me to read the EPA’s new rule on heavy-duty engine emissions. bit.ly/3WjtIQO JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R UPCOMING IADC EVENTS • IADC CONNECTION 2023 IADC HEALTH, SAFETY, ENVIRONMENT & TRAINING Conference & Exhibition 18-19 APRIL 2023 H YAT T R E G E N C Y HOUSTON WEST H O U S T O N , IADC HSE AND S U S TA I N A B I L I T Y ASIA PACIFIC IADC Drilling Onshore C C O O N N F F E E R R E E N N C C E E T E X A S CONFERENCE & EXHIBITION & & E E X X H H I I B B I I T T I I O O N N 23-24 MAY 2023 GRAND HYATT KUAL A LUMPUR KUAL A LUMPUR, MAL AYSIA 18 MAY 2023 H YAT T R E G E N C Y HOUSTON WEST HOUSTON, TEXAS IADC International Tax SEMINAR 8-9 JUNE 2023 SEMINAR G R A N D H YAT T S A N A N TO N I O R I V E R WA L K S A N A N T O N I O , 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 LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 49 IADC CONNECTION • DRILLING CONTRACTOR DON’T MISS OUT ON OUR NEXT ISSUE! EDITORIAL PREVIEW March/April Innovating While Drilling* Drill Pipe and BHAs Finding the Right Drill Bit Extended Laterals Hydraulic Fracturing Advances Competing for Talent in a Global Market DISTRIBUTION: AADE National Technical Conference & Exhibition [4-5 APRIL, MIDLAND, TEXAS] OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS DRILLINGCONTRACTOR.ORG IADC.ORG IADC HSE&T Conference & Exhibition [18-19 APRIL, HOUSTON, TEXAS] AD CLOSING: 17 FEBRUARY MATERIALS DUE: 24 FEBRUARY * “Innovating While Drilling® (IWD)” is a trademark of the International Association of Drilling Contractors and Drilling Contractor. Videos 50 Visit DrillingContractor.org for the latest drilling industry news and videos Brazil’s ANP sees human factors as next frontier in drilling safety and performance IADC Brazil Chapter wraps up busy 2022, looks ahead to new goals in 2023 PwC: Proposed SEC climate disclosure rules could mean big changes for drilling contractors Machine learning model helps ConocoPhillips optimize ROP in Eagle Ford operations JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R PEOPLE, COMPANIES & PRODUCTS • DE PAR TM E NTS Patterson-UTI promotes Holcomb, Garvin to new roles James “Mike” Holcomb has been promoted to the new position of Chief Operating Officer of Patterson-UTI Energy, while Mike Garvin has been promoted to President of Patterson-UTI Drilling. Mr Holcomb joined Patterson-UTI in 1988 through its acquisition of Robertson Onshore and has held numerous leader- ship positions at the company over the years. For the past decade, he has served as President of Patterson-UTI Drilling and has held numerous leadership positions with IADC. Mr Garvin began his career with an onshore drilling contractor in California, and since then has held key leadership and operational roles at Patterson-UTI, GlobalSantaFe, Transocean and Ensco. Mr Garvin also currently serves as IADC Division VP North America Onshore. Bishop Lifting rebrands, expands footprint with Worswick deal Bishop Lifting Products has rebranded under the name of Bishop Lifting, which now includes Matex, American Wire Rope & Sling, LA Crane, Western Sling and Delta Rigging & Tools. Meanwhile, its rental branches will become Bishop Lifting Rentals. This includes Delta Rigging & Tools and Morgan City Rentals. Bishop Lifting recently also complet- ed its acquisition of Worswick Group Holdings, including Certified Slings and Supply. This is Bishop’s 11th acquisition since 2012. Worswick has 10 operating locations across Florida, and the company said Certified Slings and Supply will main- tain its local branding. GDEP announces partnerships with US Well Services, Catalyst GD Energy Products (GDEP) announced it will supply 3,000-hp pumps, each pow- ered by an electric drive motor, for US Well Services’ Nyx Clean Fleet  e-frac system. The pump were specifically designed for the Nyx Clean Fleet. Two of these pumps will be placed on each trailer, and each 6,000-hp Nyx trailer will take the place of 2.5 conventional diesel units. Separately, Catalyst Energy Services has selected GDEP’s Thunder 5000, a quin- tuplex pump with an 11-in. stroke rated for 5,000 hp, to safely maximize flow at a slower operating speed in its patents- pending frac solution, VortexPrime. The pump contributes to the proprietary tech- nology within VortexPrime that reduces the number of trucks in its fleet from 20 to just eight, enabling faster setup and take-down. ABS establishes maritime software as a service company ABS Wavesight is a new maritime soft- ware as a service (SaaS) company that is integrating ABS’ Nautical Systems and My Digital Fleet platforms, which are collec- tively installed on more than 5,000 vessels across the global fleet. My Digital Fleet is an AI-driven analytics and performance Seadrill to acquire Aquadrill Seadrill has announced it will acquire Aquadrill in an all-stock trans- action. The combined company will own 12 floaters – including seven 7th- generation drillships – three harsh- environment rigs, four benign jack- ups, and three tender-assisted rigs. Additionally, seven rigs will be man- aged under strategic partnerships. ABL Group adds HOSE International to portfolio ABL Group has acquired the opera- tions of well control equipment spe- cialists HOSE International. HOSE’s UK business will become part of ABL’s global operations. Over the past three decades, HOSE has completed approxi- mately 2,300 inspections on more than 700 drilling rigs. Molinaro takes new positions for DLS Archer Gerardo Molinaro, previously CFO of DLS Archer, has been appointed to serve as VP of Land Drilling. He will oversee operations in Argentina and Bolivia for Archer and its subsidiaries DLS Argentina, DLS Archer and Archer DLS Bolivia. Pason invests in IWS Catalyst Energy Services’ VortexPrime frac solution will incorporate GDEP’s Thunder 5000 pump to maximize flow at a slower operating speed. visualization platform, and Nautical Systems provides comprehensive tools for fleet management to improve reliability and performance. Viking Completions awarded new contracts in MENA Dubai-based Viking Completion Tech- nology was awarded multiple contracts to deliver its well completion manufacture and design services to major operators in the Middle East and North Africa (MENA) region, including in the UAE, Iraq and Oman. The contracts encompass Viking’s completion packers, sliding side doors, landing nipples and associated comple- tion accessories. Pason Systems has increased its non-controlling investment in Intelligent Wellhead Systems (IWS) through the acquisition of outstanding common shares of IWS for $7.9 million and an agreement to invest up to $25 million in preferred shares of IWS. Schlumberger becomes SLB, acquires Gyrodata Schlumberger has announced a new name, SLB, symbolizing its ambition to be a global technology company driv- ing the future of energy. The new SLB brand will focus on four main areas: new energy systems, industrial decar- bonization, digital at scale, and oil and gas innovation. In separate news, SLB acquired Gyrodata. Gyrodata’s wellbore place- ment and surveying technologies will be integrated within SLB’s Well Construction business. D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 51 DE PAR TM E NTS • PEOPLE, COMPANIES & PRODUCTS Apache awards Expro intervention, integrity services contract Expro announced it received a $50 million well intervention and integrity services contract with Apache Corp in the North Sea. It encompasses pumping and optimization operations across all of Apache’s North Sea assets, including Beryl Alpha and Bravo, and Forties Alpha, Bravo, Charlie, Delta and Echo. Under the contract, Expro will provide services including slickline, e-line, cased hole and pressure pumping, as well as technologies like Octopoda and CoilHose. Equinor to implement smart contracts on Johan Sverdrup, Troll Equinor has implemented Data Gumbo’s smart contract platform to automatically calculate and execute payments for inte- grated drilling and well services for Johan Sverdrup and Troll assets. The operator will use the dayrate portions of the broader contract format for two assets worked by one platform and four drilling rigs. The platform will apply agreed busi- ness logic to data shared between Equinor and its suppliers and create charges and invoices. Rolls-Royce explores new fuels for diesel engines Rolls-Royce is partnering with Finland-based Neste on the implemen- tation of sustainable fuels for diesel engines; Rolls-Royce’s Power Systems business unit makes engines under the mtu brand. In May 2022, Rolls-Royce approved mtu diesel engines for power genera- tion for renewable diesel (also known as HVO) and other EN15940 fuels. The company says its testing has shown up to 90% greenhouse gas reduction, up to 80% less particulate emissions and an average of 8% nitrogen oxides reduction. Power Systems is gradually releas- ing its mtu engine series for sustain- able fuels such as HVO and e-diesel for use in other industries, such as the rail, marine and construction industries. Products Multi-activation circulating sub aims to reduce rig time NXG Drilling Services’ recently launched NXG-MACS (multi-activation circulating sub) was designed to be activated on demand, without the need to drop a ball or dart. The 6 3/4-in. ver- sion of the tool is now being commer- cialized following testing. WEG variable speed drive helps boost efficiencies WEG has introduced a variable speed drive (VSD), CFW900, for driving and controlling three-phase induction and permanent magnet motors. It can be used in a wide range of applications, including oil and gas, due to its high overload capacity. The VSD has a thermal management function that allows for use in extreme temperature environments. It can mea- sure the ambient temperature and con- figure itself by varying its switching frequency. It also comes with Bluetooth connectivity, and its human-machine interface allows for parameter monitor- ing with customized layout and com- ponents. 52 Automation system launched for surface well testing Halliburton’s new FloConnect system, launched at ADIPEC 2022, automates sur- face well testing operations while moni- toring and measuring factors related to the production of hazardous effluents. It helps reduce operational variability and optimizes workforce deployment, allowing more time and focus on data monitor- ing, collection and quality. The platform combines data visualization capabilities with interactive analytics to aid decision making, as well as identification and reso- lution of potential issues with a given well. Another technology launched at ADIPEC, BrightStar, is a look-ahead resis- tivity service that reveals structure and fluid boundaries ahead of the bit, enabling proactive drilling decisions and hazard avoidance to reduce operational risks while providing reservoir characterization and enhanced formation evaluation. The service detects changes in the formation ahead of the bit and reduces the uncertain- ty of the formation boundary positions. Ikon Science issues new versions of Curate, RokDoc systems The new version of Ikon Science’s Curate cloud-native subsurface knowledge man- agement system focuses on enhancing col- laboration in data on an enterprise scale. Updated features include a real-time chat function as drilling operations progress. Additionally, the system’s “Well Viewer” app now features the implementation of file-linked, depth-referenced images, which can be dragged, viewed and navigated within a single log-to-core data view. Ikon Science also released RokDoc Version 2023.1 with expanded functional- ities in machine learning and rock phys- ics, as well as new tools to visualize well details and metrics. JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R AD INDEX American Association of Drilling Noble Corporation........................................53 Engineers National Technical Conference and Exhibition..................56 Oil States.............................................................56 IADC IADC Drilling Onshore Conference & Exhibition......................... 41 IADC Health, Safety, Environment & Training Conference & Exhibition......5 TSC Drill Pipe...................................................... 21 Weatherford.........................................................2 IADC ISP Rig Recognition Plaques......39 Wild Well Control..............................................7 Global Sales Manager Drilling Contractor / IADC Houston HQ 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 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! 9,125 + Followers 30k+ Followers 5,350+ Followers 2.79K Subscribers 2,289,425+ Views D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023 53 DEPARTMENTS • PERSPECTIVES Stephen Foster, Scandrill: Moving from US Army to the oilfield opens new career opportunities BY STEPHEN WHITFIELD, ASSOCIATE EDITOR The oil and gas industry draws folks from all walks of life to work in different disci- plines, but when it comes to drilling, it is the men and women working on the rig who are the backbone of the business – the pressure washers, the floorhands, the motor hands and everyone else that puts in long hours to keep a rig running. Stephen Foster, HSE Coordinator at Scandrill, started his drilling career as one of those crew members working on the rig floor. The work started out as just a steady job – a way to support his growing family – but this past summer it began to blossom into a career when he moved into a new safety role with the company. “There are so many different routes to take in the oilfield, so many different facets of the industry, so many different ways to move up,” he said. “I’ve learned that you don’t have to be stuck at all in this industry. If you figure out what excites you, you can move.” Mr Foster grew up in Pineland, Texas, a small town less than 40 miles from the Louisiana border. Upon graduating high school in 2009, he went straight into the US Army and received technical training to serve as an intelligence analyst. Over the next eight years, he went on to serve in campaigns in Iraq and Afghanistan and peacekeeping missions in South Korea, doing everything from military intelli- gence to coordinating drone flights, kinetic targeting and leading a battalion intel- ligence section as a noncommissioned officer. He left the Army in 2017, a result of earlier conversations with his brother, a 54 directional driller in South Texas, about joining the oilfield. Although Mr Foster’s brother unexpectedly passed away before he made the career switch, another family connection took him to Scandrill, and he soon began working as a floorhand on a rig in Henderson, Texas, 40 minutes from his home. He recalls his first two days on the rig as being fairly easy, but on the third day, he started to wonder if he had made a mistake. “We were pulling out of hole, and it was about an 18,000-ft trip. It was wet day, and it was overwhelming. I remember telling my wife that I might not be cut out for this. But she told me I had made my decision and needed to see it through.” Mr Foster powered through that ini- tial rough stretch and eventually found himself enjoying his time on the rig and particularly the friendships he developed with other crew members. “If you’re not in the oilfield, you have the idea that these are rough individuals. And, yes, they are not people you’d want to mess with, but they’re also the kind of people that would give you their shirt off their back if you didn’t have one out there,” he said. Bridge between management and crew Mr Foster would go on to spend much of the next two years working floors for Scandrill rigs. That was followed by a brief stint as a motor hand and two more years as a derrick hand in East Texas, Oklahoma and West Texas. In mid-2022, he took a new role with Scandrill as HSE Coordinator when he realized that it was an opportunity “to do something that can make a difference in the bigger picture.” He now primarily focuses on incident management – analyzing incidents on a rig site, updating procedures to help prevent those incidents from happening again, and communicating those proce- dures to the personnel on the floor. In effect, he serves as a bridge between man- agement and the rig crews, something he can do well because of his years working on the floor. “I understand exactly what those floor- hands are going through and what they’re trying to accomplish. A lot of times, the accidents that happen are just due to their ‘go-get-it” nature. They’re trying to get a Stephen Foster is applying the knowl- edge he gained working on the rig floor to his new position as Scandrill’s HSE Coordinator. Knowing how floorhands think and what drives their decision making helps him to have more effec- tive conversations around safety. job done, so they’ll push a little harder, a litter further, maybe cut a corner. I can approach them knowing why they made the decisions that they made and explain why that decision isn’t the best one to make,” he said. His new position also afforded him an opportunity to get involved with IADC. Under an IADC program that provides a complimentary registration to the Annual General Meeting to a young professional working for a drilling contractor member company, Mr Foster attended the 2022 conference in New Orleans. He not only got the chance to hear industry executives talk about challenges and opportunities within the industry, but he also got the chance to engage with many of them. The experience has encouraged him to get more involved with IADC in the future, he said, and it has inspired him to continue working his way up the ladder. “At first I felt like a fly in the milk bowl with all these influential people, but as I got to talking to them, I saw that they were all just normal people doing a job,” he said. “There were people there that I got to meet who I admired on a personal level because they started on the rig floor and worked their way up to influential positions both in their companies and the industry. That’s something I was able to see myself doing.” DC JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R AMERICAN ASSOCIATION OF DRILLING ENGINEERS Innovating to Secure America’s Energy Future 2 0 2 3   NATIONAL TECHNICAL CONFERENCE AND EXHIBITION 4-5 April 2023 | Bush Convention Center | Midland, Texas REGISTER TODAY CONFERENCE TOPICS: Connect with your peers and learn from industry leaders about new technologies and strategies to produce powerful outcomes. Exhibition and Conference programs will cover topics including case histories, improvements and innovations in drilling operations. Come listen, learn and see innovation at work. A ADE Find more information on sponsorships, exhibiting and registration: aade.org AMERICAN ASSOCIATION of DRILLING ENGINEERS • • • • • • • • • • • • • • Automation/AI Bits & Cutters Case Histories Cementing & Zonal Isolation Delaware/Permian Basins Digital Technologies Drill Pipe & Tubulars Fluid Loss/Lost Circulation/LCM Fluids Fracturing Geothermal Applications Supply Chain & Sustainability Tools Torque & Drag/Lubricity A AD E AMERICAN ASSOCIATION of DRILLING ENGINEERS