THE NEW WORLD OF DIGITAL DRILLING ENGINEERING Increasingly sophisticated digital platforms become indispensable tools for drilling engineers – p14 SEPT/OCT 2023 As workforce evolves, well control training must too Official magazine of the International Association of Drilling Contractors www.drillingcontractor.org www.iadc.org Training providers focus on adding simulators, improving classroom experience, seamless delivery of virtual classes – p26 Volume 79 • Number 5 One-on-one with Valaris CEO Anton Dibowitz Company keeps focus on people-driven service delivery even as it invests in AI, robotics and sustainability – p40 ONE-TOUCH TUBULAR SIMPLICITY REVOLUTIONARY RIG-FLOOR EFFICIENCY AUTOMATED CONNECTION INTEGRITY WITH NEXT-GENERATION SAVINGS, SAFETY, AND VALUE weatherford.com/vero 50% FEWER 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 SEPT/OCT 2023 Volume 79 • Number 5 drillingcontractor.org iadc.org New apps like Field Development Planning (FDP) are opening up a new world for drilling engineers in terms of efficiency and capability. Read about these technologies on Page 14. Cover illustration is based on Aker BP’s FDP visualization. D I G ITALI ZATI O N O F D R I LLI N G 14 Digital twins building new engineering worlds in a digital ecosystem Intelligent software systems enhance drilling engineers’ decision making with rapid visualizations, real-time well plan updates BY STEPHEN WHITFIELD, ASSOCIATE EDITOR WELL CONTROL READINESS 21 Standardizing subsea BOP soak testing: Overview of value and recommended best practices BY PATRICK HILLARD AND LEONARD CHILDERS, IPT GLOBAL; AND AHMED OMAR, SEADRILL 26 Digital solutions bolster well control training as drilling workforce evolves Simulators, virtual and hybrid classes, and microlearning among ways training providers are adapting to students’ changing needs BY STEPHEN WHITFIELD, ASSOCIATE EDITOR I N N OVATIVE D R I LLI N G TECH N O LOG I E S 30 Amid growing uptake of MPD in deepwater, controlled mud level technology deserves another look BY ANTHONY SPINLER, ENHANCED DRILLING DECARBONIZING DRILLING 36 34 New contracting models needed to finance decarbonization programs, drive new solutions BY JESSICA WHITESIDE, CONTRIBUTOR 36 Companies zero in on cementing process to have outsized impact on well construction emissions BY STEPHEN WHITFIELD, ASSOCIATE EDITOR DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 3 TAB LE OF CONTE NTS D R I LLI N G AUTO MATI O N 38 Robotic system enhances safety by keeping personnel out of red zones on the drill floor during offshore riser operations DRILLING MARKETS & LEADERSHIP 40 Valaris CEO: No matter how industry evolves, people remain at the center of the drilling business BY JESSICA WHITESIDE, CONTRIBUTOR BY LINDA HSIEH, EDITOR & PUBLISHER IADC CONNECTION 44 From the President: Industry continues to tap into limitless potential of technology BY JASON MCFARLAND, IADC PRESIDENT 45 News Cuttings 46 Wirelines 47 Conference Calendar 48 Editorial Preview DEPARTMENTS 52 6 Drilling Ahead: Recognizing the counterproductive nature of ‘sustainable investing’ BY LINDA HSIEH, EDITOR & PUBLISHER 7 D&C News 12 Oil & Gas Markets 13 Videos 49 People, Companies & Products 51 Advertisers Index 8 D&C Tech Digest 10 News Briefs: Environmental, 52 Perspectives: Barrett Zuskind, Z-Tex Social and Governance Services – Curiosity helps people make the most of opportunities BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 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. SEPT/OCT 2023 Volume 79 • Number 5 Drilling Contractor (ISSN 0046-0702), the official magazine of the International Association of Drilling Contractors (IADC), is issued six times per year. DC is a wholly owned publication of IADC, which is also the publisher of the annual IADC Membership Directory. Drilling Contractor strives to ensure that the articles and information it publishes are accurate and reliable. However, DC cannot warranty the information provided in its editorial content, and publication in DC is not a guarantee that the material presented is accurate. DC wants to hear from its readers. Send your comments or inquiries to editor@iadc.org or Attn: Editor, Drilling Contractor Magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042 (please include your name, plus an email or phone number). We hope you will enjoy and benefit from DC’s editorial. However, should you wish to 4 complain, please contact the publisher. 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PUBLISHED BY IADC OFFICERS IADC 3657 Briarpark Drive Suite 200 Houston, Texas 77042 USA Chairman 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 Contributor Jessica Whiteside Vice Chairman Leif Nelson Division VP North America Onshore Mike Garvin Division VP International Onshore Miguel Sanchez Division VP Offshore Brian Woodward Division VP Drilling Services Tim McGarity President Jason McFarland A full list of IADC staff is available here: www.iadc.org/about/staff SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DEPARTMENTS • DRILLING AHEAD DRILLINGCONTRACTOR.ORG VIRTUAL PANEL DISCUSSIONS VPDS “Back to Basics: Improving Performance Through Digital Well Construction” ORIGINAL AIR DAT E: 24 AUGUS T 2023 Learn how SLB is leading the performance assurance charge — evolving drilling by combining its latest drill bit technologies, rotary steering systems and autonomous controls. These are crucial advances for building wells in the most efficient and consistent manner and enhancing real-time reservoir characterization for more precise trajectories that elevate well performance. On 24 August, Drilling Contractor hosted a live Virtual Panel Discussion, sponsored by SLB: • Wiley Long, SLB Product Champion PDC Bits, discusses the evolution of Smith Bits drill bits • Roberta Santana, SLB Product Champion PDC Bits, highlights the SnapScan app and dull- grading digitalization • Ziad Akkaoui, SLB Digital Champion, details autonomous downhole tools • Stephen Whitfield, Drilling Contractor Associate Editor (moderator) Sponsored by drillingcontractor.org/ vpd-access-back-to- basics 6 Recognizing the counterproductive nature of ‘sustainable investing’ BY LINDA HSIEH, EDITOR & PUBLISHER One of the most interesting sessions I attended at the IADC World Drilling Conference this year was a panel focus- ing on how the industry should finance its decarbonization initiatives (see p34 for our report). On the one hand, companies understand the needs of the energy transi- tion and are seeking ways to reduce the carbon footprint of drilling and rig opera- tions. On the other hand, change comes at a cost, so who will pay for that cost? While the panel looked more inward at whether operators or drilling contractors should shoulder the financing, there is also a broader perspective to the question, as we know that there is a general trend of investors and banks turning away from the oil and gas industry. But is shunning oil and gas actually a good sustainability strategy? Not accord- ing to a recent report from two econom- ics/finance experts from Yale and Boston College. In fact, they say that the so-called sustainable investing, which tends to direct capital away from industries like oil and gas, is counterproductive. The focus of sustainable investing is often to build a portfolio of low-emissions “green” firms – like insurance or finan- cial services companies, for example. At the same time, investments in so-called “brown” firms, or those with higher emis- sions profiles, get discarded. But those “green” firms likely had little to no emissions simply due to the nature of their business, the authors pointed out, and further investment in them is unlikely to yield innovations that will drive impact- ful, long-term emissions reductions. They “have little scope for further improvement in their impact,” the report said. And for “brown” firms that are starved of cheap capital, there is less incentive to make changes to their operations or methods of production. “Brown firms have approximately 260 times as much environmental impact as similarly sized green firms, and have substantially greater scope for change,” according to the report. ‘No form of energy is truly renewable’ Another interesting perspective on the energy transition was delivered recently by Scott Tinker, Director at UT Austin’s Bureau of Economic Geology. “No form of energy is truly renewable, as we have to either mine for it or dump the waste – such as used batteries and wind turbines – back into the ground,” he said at the 2023 AIEN International Energy Summit. Moreover, the energy transition is not about switching from current sources of energy to new sources of energy. “We’re just adding energy to meet demand and trying to lower emissions,” he said. Dr Tinker also highlighted how quickly nations can change their priorities when it comes to the energy trilemma. “Energy security underpins economic security, which in turns lets you invest in the environment and obtain climate security. If you start by focusing on low emissions, you will not get energy that is affordable or reliable. You need to focus on the ‘radical middle’ of this particular triangle,” he said. World events like the signing of the Paris Agreement at COP21, the COVID-19 pandemic and the war in Ukraine have all influenced where that middle ground moved to, pushing and pulling on people’s attention among energy security, econom- ic security and climate security. “Energy and economy are intertwined,” he said. “60% of the world’s population live with some sort of energy poverty. The emerging economies are desperate for affordable energy. Energy won’t end poverty, but we can’t end poverty without energy.” DC SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR Scan me to access “Counterproductive Sustainable Investing: The Impact Elasticity of Brown and Green Firms.” bit.ly/45gmxOa DRILLING & COMPLETION NEWS • DEPARTMENTS Transocean ultra-deepwater drillship to drill offshore Mexico under $518 million contract An independent operator awarded Transocean a 1,080-day contract for a sev- enth-generation ultra-deepwater drillship in the Gulf of Mexico offshore Mexico. Transocean will select the drillship from among the Deepwater Invictus, Deepwater Thalassa and Deepwater Proteus no later than one year prior to the earliest date in the commencement window. The contract will contribute approximately $518 mil- lion in backlog and is expected to com- mence between Q4 2025 and Q2 2026. The contractual dayrate is subject to a semi- annual cost adjustment with a baseline established on 1 July 2023. “The fact that our customers are secur- ing rigs well in advance of their programs and committing to long-term contracts clearly demonstrates the tightness of the market," Transocean CEO Jeremy Thigpen said. "Additionally, our ability to designate the specific rig closer to the commence- ment of the program provides us with increased flexibility ." Valaris set to reactivate DS-7 drillship for 12-well contract offshore West Africa Valaris was awarded a 12-well contract offshore West Africa for the VALARIS DS-7 drillship, which will be reactivated for this contract. It is expected to commence in Q2 2024 and has an estimated duration of 850 days. The total contract value is estimated to be $364 million. The contract requires minimal customer-specific upgrades to the rig and does not include the provision of any additional services. This is Valaris' seventh floater contract since mid-2021 that requires reactivation . Signing the strategic partnership agreement were (front row, from left) Musabbeh Al Kaabi, ADNOC Executive Director, Low Carbon Solutions and International Growth; Rovshan Najaf, SOCAR President; and Nicolas Terraz, TotalEnergies President, Exploration & Production. ADNOC bolsters its international gas footprint with investment in Caspian Sea Abu Dhabi National Oil Company (ADNOC) is acquiring a 30% equity stake in the Absheron gas and condensate field in the Caspian Sea. ADNOC will own a 30% participating interest in Absheron, with the State Oil Company of Azerbaijan (SOCAR) and TotalEnergies each holding 35% stakes. ADNOC’s investment into the Caspian region aims to create a substantial growth position as it enters the international gas market, and reinforces the energy partnership between the United Arab Emirates and Azerbaijan. Entering into a strategic partnership with SOCAR also elevates ADNOC’s long-standing partnership with TotalEnergies . Tullow and partners begin production from Jubilee South East project offshore Ghana Tullow, alongside its joint venture partners Kosmos Energy, Ghana National Petroleum Corp , Petro SA and Jubilee Oil Holdings, announced the successful startup of the Jubilee South East Project offshore Ghana. Two more producers and one water injector are expected to come on stream this year to help sustain gross Jubilee production over 100,000 bopd. This increased level of production is expected to be maintained at Jubilee over the next few years as multiple future drilling locations have already been identified. 'Clustered exploration' approach leads to 6 additional discoveries offshore Malaysia PETRONAS Carigali has made six oil and gas discoveries in five blocks off the coast of Sarawak, Malaysia: Gedombak in Block SK306, Mirdanga in Block SK411 , Sinsing in Block SK313, Machinchang and Pangkin in Block SK301B, and Kalung Emas in Block SK315 . The discoveries were achieved on the back of an intensive domestic exploration drilling campaign commenced in late 2022, which had also led to the discovery that year of Nahara-1 in Block SK306, one of PETRONAS Carigali's most significant oil discoveries within the last decade. PETRONAS Carigali attributes these successes to its "clus- tered exploration" approach, a unique style of prospecting suited for highly matured geological provinces. Borr jackups, Gerd and Thor, headed for work in Middle East and Southeast Asia Borr Drilling secured two binding letters of awards from undisclosed customers for its premium jackup s Gerd and Thor. The awards increase Borr's firm backlog by approximately 421 days, excluding optional periods . Gerd will work in the Middle East under a contract with a firm scope of 270 days and one unpriced optional scope of 60 days. Upon concluding its current contract with Addax in Q3 , the rig will undergo mobilization, statutory surveys and recer- tification before starting its new commitment in December 2023. Thor will work in Southeast Asia under a contract with a firm scope of two wells with an estimated duration of 151 days . This contract is expected to commence in December 2023 in direct continuation of the rig’s ongoing contact. DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 7 DEPARTMENTS • DRILLING & COMPLETION TECH DIGEST High-speed wireless communication system tested, qualified offshore Norway for subsea well completions Optime Subsea recently tested and qualified a high-speed wireless com- munication system for completion of subsea wells. The wireless communication sys- tem, part of Optime Subsea’s Remotely Operated Controls Systems (ROCS), was tested at the Wintershall Dea-operated Nova field , offshore Norway in 370 m water depth. “This is a game-changer for the oil and gas industry, which for 20 years has tried to solve this challenge,” said Trond Løkka, Chief Innovation Officer at Optime Subsea. “For the very first time, the complete wireless installation of the tubing hanger on the subsea tree was accomplished without relying on a wired drill pipe .” When completing subsea wells, the tubing hanger is placed on top of the wellhead, as a seal toward the rest of the subsea well. Normally the tubing hanger is controlled through a dedicated hydraulic umbilical that runs from the topside to seabed and adds a 20-30 f t control container topside. However, Optime Subsea’s ROCS remove s the need for both the umbilical and the topside hydraulic unit . For instantaneous data transfer from downhole to surface and back, Optime Subsea had relied on a wired drill pipe. Now, by replacing the wired pipe with a subsea wireless telemetry system , CAPEX investments and operating costs can be further reduced. With the new subsea wireless tele- metry system , part of Optime Subsea’s Remotely Operated Controls Systems, neither wired pipe nor a hydraulically controlled umbilical is needed to in- stall the tubing hanger on the subsea tree. It recently enabled the fi rst com- pletely wireless installation in Norway. “Think Wi-Fi from topside to seabed, to control well completion operations. We have proven that this is both pos- sible and reliable. In our view, this way of installing tubing hangers on sub- sea trees will become the new indus- try standard for subsea well comple- tion operations worldwide because of its substantial cost and environmental savings versus competing methods,” Mr Løkka said. While the first operation was per- formed on Wintershall ’s Nova field, Optime Subsea noted Aker BP’s support during the development of the wireless communication system. SABER completes testing in operational environment Enteq Technologies announced that its SABER (Steer-At-Bit Enteq Rotary) tool, an alternative to traditional rotary steerable systems , has completed down- hole drilling testing. The system is now proven to be effective in an operational environment. The trials took place at the Catoosa Drill Test Facility in Oklahoma, follow- ing initial testing in Norway earlier this year. During the drilling program, the SABER system was able to generate dog- leg in typical reservoir rock conditions. 8 An independent survey has been conducted to measure the well trajec- tory, as well as an expert review. Both confirmed the tool’s ability to provide sufficient steering forces for the target commercial applications. Rather than using pads or plates for steering, the tool uses an internally directed pressure differential system across the bit face. By removing these external contact points, the tool reduces wear and improves reliability while also achieving true at-bit steering . Nabors and Hess electrify Bakken drilling rigs Nabors has converted all four of its drilling rigs working in the Bakken for Hess Corp to highline power. Nabors installed its Canrig PowerTAP Highline Power Transformer Module to enable direct power from the utility grid. Oonsite backup generators ensure power goes uninterrupted if an outage occurs. Over the next five years, Hess expects these fully electric rigs will reduce green- house gas emissions from its Bakken drilling operations by approximately 50% and energy costs by approximately 70%. Powering drilling operations with elec- tricity also reduces noise and truck traf- fic. The use of electricity as the primary energy source increases rig reliability by providing a secondary power source, Hess said during the project’s pilot in 2022. Looking ahead, the operator said it also expects electrification of the rigs and access to highline power to reduce downtime. Nabors rigs have long been running on grid power. More recently, Canrig Drilling Technology, a division of Nabors, released its transformer technology. PowerTAP enables highline power utilization on any AC drilling rig where grid power is acces- sible, regardless of rig manufacturer. It is skid-mounted for easy transport to and from rigsites and easily installed any- where compatible utility electrical power is available using a standalone conductor cable reel. Field results from more than 20 PowerTAP modules deployed in the Lower 48 on Nabors and non-Nabors rigs indi- cate an initial average savings per rig of 20 metric tons of CO 2 e daily. Canrig also plans to introduce technologies to power additional wellsite equipment directly from the PowerTAP module and enable phase conversion capabilities where required. “We are committed to delivering responsible hydrocarbon production through smart, sustainable solutions. PowerTAP is one of many impactful tech- nologies we’ve purpose-built to simulta- neously lower costs and emissions for our customers ,” said Don Prejean, Canrig Senior VP. SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DEPARTMENTS • ENVIRONMENT, SOCIAL AND GOVERNANCE Hess highlights progress in 2022 Sustainability Report ADNOC brings net-zero goal forward by 5 years to 2045 Hess Corp recorded 2.2 million tonnes and 0.4 million tonnes of CO 2 e for its 2022 operated Scope 1 and 2 GHG emis- sions , according to the company’s new- est annual sustainability report. That compares with 2.5 million tonnes and 0.4 million tonnes, respectively, in 2021. Its 2022 operated Scope 1 and 2 GHG intensity was 18.5 kgCO 2 e/boe, and its US methane intensity was 0.39% After outperforming its five-year emis- sions targets in 2020, Hess is now work- ing toward new five-year reduction tar- gets for 2025. This includes reducing its operated Scope 1 and 2 GHG emissions intensity to 17 kg per boe and its meth- ane emissions intensity to 0.19% , as well as achieving zero routine flaring on oper- ated assets. Another milestone in 2022 was the signing of a forest preservation agree- ment with the government of Guyana , under which Hess will purchase REDD+ carbon credits for at least $750 million between 2022 and 2032 . In terms of workforce safety, Hess reported an increase in occupation- al safety incidents and releases in its ADNOC is accelerating its decarboniza- tion plan and moving its net-zero ambi- tion to 2045 from its previous target of 2050, and to achieve zero methane emis- sions by 2030 . The plan is backed by an initial $15 billion allocation to low-carbon solutions . In 2022, ADNOC’s upstream carbon intensity performance was approximate- ly 7 kgCO 2 e/BOE and its methane inten- sity was approximately 0.07% . Additionally, in 2022 ADNOC achieved greenhouse gas (GHG) emissions reduc- tions of approximately 4 million tonnes by using grid energy from solar and nuclear power to supply 100% of its onshore oper- ations, as well as approximately 1 million tonnes from energy efficiency and flaring reduction projects. Further, ADNOC started two pilot proj- ects this year to capture and permanently store CO 2 as part of its plan to expand its carbon capture capacity to 5 million tonnes per year by 2023. Separately, ADNOC recently signed a n agreement with Occidental to evaluate CCS hub opportunities in the U AE and US, with a view to develop a carbon management platform . The agreement is enabled by the UAE-US Partnership for Accelerating Clean Energy , which is expected to catalyze $100 billion in clean energy and carbon management projects by 2035. 0.5 44 0.0.0.44 0.4 0.0.0.353535 0.0.0.323232 0.3 0.2 0.0.0.121212 0.1 0.0 0.0.0.101010 0.0.0.090909 2020 2021 2022 ■ ■ Hess has launched a new equipment movement procedure and leadership training to address an increase in TRIR. Bakken operations in 2022 . To address this, the operator implemented the Heavy Equipment Movement Procedure in the Bakken and began delivering third-par- ty leadership training to Hess’ worksite supervisors at workover operations to further reinforce worksite accountability . NSTA: Domestic gas supports UK’s net-zero goals North Sea gas is significantly clean- er and supports the drive to net-zero greenhouse gas emissions far more than imports, according to analysis by the North Sea Transition Authority (NSTA). The research shows that domestically produced gas is, on average, almost four times cleaner than importing gas in LNG form. The primary drivers for the difference are the processes of liquefac- tion , then transportation via shipping, and finally regasification . The report shows that the UK pro- duced 38% of its gas supply in 2022 , but that gas was responsible for only 24% of the associated total emissions . Murphy pushes its water recycling ratio to record high Murphy Oil’s new Sustainability Report shows that, from 2019 to 2022, the company achieved reductions in its greenhouse gas (GHG) emissions , meth- ane and flaring intensities by between 25-60% (see figure at right) . It also sur- passed last year’s water recycling record, increasing the percentage of recycled water to total water consumption from 17% in 2021 to 27% in 2022. Additionally, 31% of flowback and produced water in 2022 was recycled , up from 14% in 2021. 10 frfrfrom om 2019 to 2022 25% GHG emissions intensity intensit y 34% methane intensity intensit y 60% HIGHEST WATER WA TER RECYCLING RA RATI TITITI O in Company history histor y ZERO IOGP SPILLS in 2021 and 2022 flaring intensity intensit y Due to higher levels of activity, Murphy’s total recordable incidence rate increased from 0.28 in 2021 to 0.37 in 2022, although its lost-time incidence rate improved from 0.04 to 0.03. 51 UKCS platforms signed up to help gather data for offshore bird database Energy consultancy Xodus has signed up 51 platforms to its not-for-profit Offshore Bird Portal (OBP) since it launched in January. Oil and gas operators from across the UK Continental Shelf (UKCS) have signed up to aid in the recording and safeguarding of offshore species that visit assets based in the North Sea. Managed by Xodus, the OBP was estab- lished to improve the gathering of geo- graphic and seasonal data relating to sea- birds and migrants on offshore platforms and structures. The database will enhance scientific understanding and ecological awareness across the energy industry. SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR Learn more DEPARTMENTS • OIL & GAS MARKETS Is the oil and gas industry really underinvesting? Wood Mackenzie says no Plans for onshore drilling in Zimbabwe, Nigeria and Ghana are moving ahead and will likely boost the Sub-Saharan rig count in the coming year. Westwood: M&A deals and new drilling plans likely to keep global onshore rig demand on upward trend Onshore drilling activity remained strong in Q2 2023, with global rig demand on an upward trend, according to Westwood Global Energy Group’s Q2 report issued in July. Several big M&A deals were announced in this quarter, including the merger of Patterson-UTI and NexTier, forming a $5.4 billion oilfield services company. The UK’s INEOS Energy also entered the US market with its purchase of 172,000 acres of Chesapeake Energy’s Eagle Ford shale assets. In Canada, ConocoPhillips purchased TotalEnergies’ 50% stake in the Surmont oil sands. In Latin America, Seacrest Petróleo acquired Petrobras Norte Capixaba’s onshore assets, estab- lishing itself as the third-largest onshore oil and gas producer in Brazil. Several drilling campaigns also recently secured funding, signifying renewed interest in onshore projects. For example, ConocoPhillips announced it had approved funding for the develop- ment of the Nuna project in the Kuparuk River Unit in Alaska. The drilling cam- paign is expected to begin after pipeline installation is completed next year, with first oil in early 2025. Another example is Invictus Energy, which raised $12.7 million in capital to begin the next phase of drilling the Mukuyu-2 appraisal well 12 in the Cabora Bassa basin of Zimbabwe. Exalo’s 202, a 1,200-hp rig, has been con- tracted to drill the well. Also in Africa, TotalEnergies is now planning to kick off its delayed drilling campaign at the OML 58 onshore block in Nigeria. Drilling is expected to begin in 2024 and last for two to three years. In Ghana, the Ghanaian National Petroleum Corp (GNPC) plans to start its onshore exploration program in the Voltaian Basin in 2024. GNPC has been building capacity for exploration since 2017. It will tender for a rig in late 2023 or 2024. In Latin America, Gran Tierra Energy and Ecopetrol agreed to a 20-year exten- sion for the Suroriente Block. A novel term was added in the contract that allows for long-term investment in work programs and infrastructure to boost oil recovery efficiency in existing fields, as well as the incorporation of appraisal drilling. Gran Tierra has committed to a $123 million capital investment program for the block. Activity also remained strong in the Gulf Cooperation Council region, with multiple contracts awarded in Oman, UAE and Kuwait for work scopes encom- passing well intervention, water/gas injection, and rig equipment servicing. Despite concerns about underinvest- ment in upstream, peak oil and gas demand can be met in the 2030s without a substan- tial increase to current annual investment levels of $500 billion, according to a recent report from Wood Mackenzie. Current upstream spending is a little more than half of the 2014 peak of $914 billion (in 2023 terms), according to the report . This shortfall has led to the indus- try’s belief that it is underinvesting . “This was never Wood Mackenzie’s opinion” said Fraser McKay, Head of Upstream Analysis for Wood Mackenzie. “Our long-held view has been that spend- ing and supply would rise to meet recover- ing demand and that the upstream indus- try would not and could not reprise the ignominious years of ‘peak inefficiency’ during the early 2010s.” From 2024, Wood Mackenzie predicts oil demand growth will slow, reaching a peak of 108 million bopd in the early 2030s. The firm cited three main reasons for why it believes that spend levels not much higher than the current run-rate can deliv- er the supply needed to meet demand through to its peak and beyond : the devel- opment of giant low-cost oil resources, relentless capital discipline and a trans- formational improvement in investment efficiency. “Conventional greenfield unit develop- ment costs have been slashed by 60% in 2023 terms” Mr McKay said . “And US tight oil wells generate nearly three times more production today for the same unit of capi- tal than in 2014. New technology, capital efficiency and modularization have been leveraged to powerful effect.” Most of the industry’s oil and gas invest- ment for the rest of this decade will target advantaged resources: those with the low- est cost, lowest emissions and least risk. Beyond that, new supply will become more expensive to develop. “Counterintuitively, the half-a-trillion run rate will need to be maintained beyond peak demand,” Mr McKay said. Wood Mackenzie calculates nearly $400 billion per year would be required in the 2020s and nearly $250 billion a year in the 2030s (in 2023 terms) . SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DRILLING & COMPLETION VIDEOS • DEPARTMENTS DC Videos » Noble adds to CCS portfolio, considers CO 2 rig development bit.ly/3qAP425 » S&P: Offshore on upward trajectory bit.ly/3s7mjut » Newbuild cycle for jackups? More videos on DrillingContractor.org » Transocean, HMH, Equinor collaboration in Norway bit.ly/3OEuAhc » Young professional perspective on next-gen worker engagement bit.ly/3QB5vWN » Realizing rig automation vision DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 bit.ly/3DTVKf2 bit.ly/3qreUFM 13 DI G ITALI ZATION OF DR I LLI N G Digital twins building new engineering worlds in a digital ecosystem Intelligent software systems enhance drilling engineers’ decision making with rapid visualizations, real-time well plan updates BY STEPHEN WHITFIELD, ASSOCIATE EDITOR T he oil and gas industry is in the throes of a digital revolu- tion that is already creating step changes in the efficiency of well planning and well construction. As part of that revolution, digital twins – software-based representations of physical assets – are increasingly becoming a key tool in the push to drive greater efficiencies in all stages of E&P. Digital twins of production assets, like FPSOs and offshore supply vessels, are already commonplace, allowing operators to minimize downtime and maintenance costs. Lately, companies have also developed and continue to refine digital twins of the Highlights Ease of data sharing is driving work to develop an open-source platform for geological modeling and well planning based on OSDU architecture. Digital twins must balance between using automation to streamline well planning workflows and providing engineers with flexibility for more uncertain scenarios. Increasingly sophisticated predictive and real-time analytic capabilities prove the value of digital twins during drilling by helping to prevent NPT. 14 wellbore itself, generating efficiencies during both well planning and drilling. “We need these digital platforms and these digital twins,” said Arnfinn Grøtte, Manager – Drilling and Wells Digitalization at Aker BP, adding that the need to better understand available data is driving a lot of the operator’s digital transformation efforts. “We need new architecture that will allow us to use the data we have, and these are the kinds of systems we’re building.” Digital twins are already commonly being used to streamline the well design process and to serve a wide range of well con- struction functions, such as optimizing drilling parameters like rate of penetration (ROP) and weight on bit (WOB). Additionally, with their predictive capabilities, they alert operators to potential issues downhole like collisions or stuck pipe that could add non- productive time (NPT) to a drilling operation. Increasingly, the industry is also seeing open-source platforms aimed at easing the integration of data across multiple platforms. Such systems allow companies to more easily visualize a multi- tude of well construction scenarios and make better decisions. “We’re really tying together the system from the perspectives of geoscience, planning and design, and execution and even production, so that we have a common and rapid understand- ing of the changes happening downhole,” said Olivier Germain, Digitalization Program Director at Halliburton Digital Solutions. “With these systems, we’re seeing much more integration across the sectors. The operator is not working on its own but is working with multiple suppliers to optimize the well’s design, so that not only do you know where to drill the well, but you also improve the execution of the drilling program and its outcome.” SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DI G ITALI ZATION OF DR I LLI N G Above: Aker BP’s Field Development Planning application, de- veloped jointly with Halliburton and launched this year, can model multiple wellbores within a single field. The app allows the operator to analyze the risk profiles of each well as they relate to one another – for instance, it can visualize potential collision risk between wellbores. Right: Halliburton’s Digital Well Program, launched in 2019 as part of the company’s DecisionSpace 365 line of software solutions, enables users to streamline well planning by run- ning automated simulations of the well to be drilled and de- tecting potential issues that could arise during drilling. Automated simulations help to analyze risks in well construction One of Halliburton’s entries into the world of digital well plan- ning is DecisionSpace 365, an umbrella name covering a line of cloud-based geoscience, production, reservoir and drilling applications. Two of these applications are Digital Well Program and Well Operations Monitor, both launched in 2019, which allow users to design a well plan, create a digital twin of the planned well and monitor activities against that plan. To design a well using the Digital Well Program, two work- flows are available: factory and interactive. The factory drilling workflow essentially uses the concept of the program template or archetype, requiring inputs on target and surface location, the well template to be used and confirmation about the subsurface data. The program will run automated simulations of the drill plan, including well trajectory analyses, geological prognoses, well integrity analyses, well completion analyses and estimated drilling time and costs. If the system does not detect any issues with these variables, the user gets a green light. If issues are detected, the system will alert the user with either an orange or red light, depending on the severity of the issues detected, as well as provide analysis of the detected issues. As the user revises the well plan, the system will also run automated workflows using new engineering models and update the activity on the fly. Under the interactive workflow, users can analyze the risk probabilities of various scenarios based on a wide range of dif- ferent factors. For instance, if the user is unsure about how much WOB to apply, the system can run concurrent simulations of the well plan using different WOB levels. A green-orange-red indi- DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 15 DI G ITALI ZATION OF DR I LLI N G The Field Development Planning application allows Aker BP to model the optimal trajectory of each well within a field develop- ment so they can reach optimal targets. The app can also illustrate various drilling parameters, like rate of penetration, as heat maps displayed along the trajectory of a planned well. Using the app, engineers can now easily see visualizations of vari- ous wells instead of relying on Excel spreadsheets and reports to analyze data. cation is still provided for the entire well plan when using this workflow . “With the factory drilling mode, essentially you press a but- ton, and it automatically works for you,’” Mr Germain said. “ But in cases where you have a lot of unknowns and uncertainty, you need a more iterative process. Sometimes during the field plan- ning stage, you don’t have much information – you just have rough ideas. “The system models the uncertainties and does some scenario analyses. There can be different variations where, for instance, you run your simulation based on possible geo-pressures. This workflow is more like a scenario management, where you can try and refine different options to see which one works better as you acquire more data.” The factory drilling option applies to many brownfields with standardized operations worldwide , Mr Germain said, while the interactive workflow is typically used in greener field develop- ments where there may be greater uncertainty regarding subsur- face data. “Every user is different, every company is different, every well is different – that was the tricky part in developing this system,” he explained. “How much do you allow the user to manage, and how much do you put in the prescribed workflow? We’ve hit a balance where you can utilize a minimal workflow, but in cases where a customer wants more control over the planning, it can still incorporate their policies and their cases. It leaves room and, 16 more importantly, time for the user to do some of their own con- cepts in the design.” After the well is designed in the Digital Well Program, the Well Operations Monitor creates a digital twin of well operations, which enables users to monitor well activities against the well plan in real time. Used during drilling, this application provides advisory alerts on potential hazards that may increase NPT. Further, it records any adjustments made to the well plan during drilling and runs revised engineering models to determine what, if any, changes need to be made to the drilling program – for instance, if ROP or WOB need to be increased in a particular sec- tion of the well to achieve optimization. “We’re taking repetitive workflows and streamlining them,” Mr Germain said. “We’re making sure everybody’s aware of what is happening and making sure engineers are not using obsolete information to design or drill their wells. That’s a game changer and a big time saver.” Optimizing field development Aker BP was one of the first companies to adopt Halliburton’s Digital Well Program in 2019, and the applications’ automated workflows have become a key component of the operator’s efforts to improve the well design process for its wells. In particular, the company’s drilling engineers now have much better understanding of their data by using 3D visualization, ver- sus the old way of using spreadsheets to view and process data. SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR Have your cake and eat it, too. Celebrating 6 years of proven performance without compromise. Delta™ connections raise the standard in premium drill pipe connection and have been used onshore and offshore worldwide with over 8 million feet of pipe delivered. The Delta premium connection offers: • Minimal cost of ownership with an average recut rate of 6% • Extreme torque for today’s longer departures and more extended reach wells • Improved hydraulics for faster drilling and better hole cleaning • Streamlined designs for use of larger pipe, reducing vibrations for improved borehole quality © 2023 NOV Inc. All Rights Reserved. JIG 23-WBT-GP-DP-0936 DI G ITALI ZATION OF DR I LLI N G WellsX’s ECO digital twin platform leverages data from previ- ously drilled wells to inform the design of new wells drilled in the same field, or fields with similar geologies. “The digital twins help us understand all the subsurface data that we use to actually do the specific designs, and part of the challenge is being able to understand any changes in interpreta- tion,” Mr Grøtte said. “When it comes to the subsurface data set, there’s always some uncertainty – it’s very rare that you have perfect logs where the formation changes are 100% clear. By using the digital twin, you’re actually representing these different for- mations in layers, which makes it much easier for the engineers to understand when the data changes, how those changes affect the well designs, where we put the casings in, etc. We can contex- tualize the subsurface.” The next step in Aker BP’s digital well planning efforts is a new cloud application, Field Development Planning (FDP), that con- verts the manual process of collating field development data into an automated digital system. The FDP application can be used to model multiple wellbores within a single field. If the operator plans to drill multiple wells from the same asset, or within the same field, it can model the optimal trajectories of each well to reach the desired target. The FDP application, which Aker BP jointly developed with Halliburton, also provides alternative field development plans modeling different well trajectories with different risk profiles. These types of predictive capabilities allow the operator to spend more time focusing on removing or minimizing the risks associ- ated with challenging wells, Mr Grøtte said. “The wells are getting more and more complex. We need to free up engineers’ time to focus on the risks and make sure that we drill successfully to total depth. With the FDP, we’re essentially putting thousands of Excel spreadsheets and reports all into one digital twin,” he said. “Normally, when we do an offset analysis, we’re probably spending weeks gathering data and trying to orga- nize it. In the past it was all in Excel. But now you can easily look at 20 nearby wells – all the events, all the risks, everything that happened when we drilled those wells. You can make a data-driv- 18 en decision on what is the likelihood for something to happen and you can back it up with actual analysis generated very quickly.” Aker BP launched the FDP application in Q3 2023, after three years of development and testing. It will be integrated with the Digital Well Program so data can be transported automatically, eliminating the need to repeat data entry. In addition to its work on field development, Aker BP also recently announced a partnership with Halliburton, Microsoft and SLB on the construction of a data mesh platform aiming to enable multi-vender interoperability on geological modeling and well planning. The system will be based on the OSDU data platform, an open-source, cross-company, cloud-native reference architecture that outlines standards for data management in oil and gas operations. By being able to convert data into standardized formats, dif- ferent operators and third-party vendors can run data analytics on their own software without needing to rebuild any code. For example, a service company can utilize the data generated in the FDP platform to run analysis within its own existing platform, instead of having to build a modified software that’s integrated with FDP. The results can then be shared through standard and interoperable application programming interfaces (APIs). The type of data being targeted include subsurface data, well logs, well trajectories and fluid/rock properties. “Really, what this data mesh is doing is giving every vendor the possibility to build integrations into an app and share data with- out having to change their software to a new standard,” Mr Grøtte said. “That’s always part of the challenge when you’re adding third-party software – having to go back to change the core parts of the software instead of just adding some existing information to the data that exists.” The platform is scheduled for release in 2024. Predictive analytics to improve efficiency WellsX, a company founded in 2017 that provides digital solu- tions for drilling operations, is moving in the digital space with the development of ECO (Engineering, Control and Optimization). It is platform that integrates applied physics modeling with the Internet of Things to predict downhole hazards in real time. The ECO system contains three components. The drilling section plan component allows users to estimate the expected mechanical and hydraulic loads in the well for all types of process operations prior to the start of well construction. The calculations “We need these digital platforms and these digital twins. We need new architecture that will allow us to use the data we have, and these are the kinds of systems we’re building.” - Arnfi nn Grøtte, Aker BP SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR CONTROL WITH CONFIDENCE THROUGH ROBUST CHOKE DESIGNS CORTEC expansive choke valve line sets industry standards for robustness and adaptability. From wellhead production to drilling manifolds, CORTEC has the right choke model to suit your requirements. Privately owned and vertically integrated, we proudly design, manufacture and test all products within our U.S. facilities which uniquely positions CORTEC to offer unmatched levels of quality, delivery and customer service. Multi-Stage Trim Manually Adjustable Production Choke Learn more about CORTEC’s industry leading choke designs Visit uscortec.com/chokes Compact Drilling Choke with Electric Servo Motor CRAFTED FOR CONFIDENCE DI G ITALI ZATION OF DR I LLI N G The ECO platform uses surface and downhole sensor measurements to calibrate the current state of a wellbore. These mea- surements are then shown on a single interface, making it easier for rig personnel to stay within the corridors of the well plan. generated by the software take into account drillstring param- eters, friction coefficients, rheology and the density of the drilling fluid. The drilling roadmap component organizes various param- eters – ROP, WOB, estimated flow rates, section lengths, as well as the mechanical and hydraulic load estimates from the drilling section plan – for each planned interval. In the bit hydraulics component, users can select the bit configuration that will maxi- mize the bit impact force on the bottomhole. Once analyses is performed through these modules, the soft- ware builds a digital twin of the wellbore. By using surface and downhole sensor measurements – on drillstring parameters; mud density, rheology and temperature; drilling fluid; the well profile; and friction factors – the twin is always calibrated to the current state of the well. These parameters are visualized on a single interface, helping the driller and other personnel ensure they stay within the corridors established in the well plan. The software also provides predictive trend deviation analysis, integrated with hydromechanical analysis, to predict fluid gains and losses, pipe-sticking mechanisms, cleanup problems and washouts during well construction. Users are alerted to potential issues so they can decide whether to take mitigating actions. “ECO provides flexibility to configure the system per client needs, to function either in supervisory or fully automated modes. In both scenarios, actionable insights are delivered to decision makers in a timely fashion,” said Khaydar Valiullin, Co-Founder and CEO of WellsX. He also described the platform as self-learning – effectively, each well drilled becomes an additional data point. Users can replay the drilled well data with parallel real-time calculation of the mechanical and hydraulic loads, and they can analyze well logs to clarify lithological information of the reservoir. When the user plans future wells in the same field, or in different fields with 20 similar geologies, the system will leverage that previous data to inform the design of new wells. “The more we utilize the system, the more useful it becomes,” Dr Valiullin said. “Even if you don’t have offset data, the digital twin is running in the background so you’ll have examples of previous exploration drilling to give you a better idea of what you’re doing.” The technology has been in operation since 2019 for sev- eral operators and drillers working in Eastern Europe, including Hungary, Croatia and Serbia. It has also been deployed in the Volga-Ural region of Russia by an operator who sought to optimize well construction time for onshore wells in mature brownfields. During drilling, the ECO system’s predictive analytics tools alerted personnel to emerging hazards related to wellbore integrity and open-hole quality, such as stuck pipe, wash-outs and twist-offs. This capability enabled continual updating and optimization of the drilling plan after encountering potential hazards. The operator saw a 16% reduction in average construction time for directional wells drilled in the Volga-Ural region, as well as a 20% reduction in sidetrack wells, according to Dr Valiullin. He attributed a major part of the time savings to off-bottom activity, as automated analyses of the drilling plan revealed that up to 30% of the time spent conducting off-bottom activity in the drilling plan was NPT. While WellsX has had limited engagement in the North American market so far, it now has plans to participat e in a geo- thermal project in South Texas, Dr Valiullin added. Last year, ECO was approved for deployment by a major nation- al oil company in the Middle East after successful onshore and offshore implementation. In June, WellsX also announced a joint venture agreement to provide its technology for its clients in the Middle East. DC SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR WELL CONTROL READINESS Standardizing subsea BOP soak testing: overview of value and recommended best practices Proposal for API Standard 53 annex aims to unify testing methodology while considering different BOP configurations, potential for digital tools BY PATRICK HILLARD AND LEONARD CHILDERS, IPT GLOBAL; AND AHMED OMAR, SEADRILL The BOP soak test is an important yet often misunderstood part of deployment preparation for subsea BOPs. Although it helps improve both the safety and efficien- cy of drilling operations, this test remains an area lacking industry standardization, leading to potential uncertainties and inconsistencies in BOP performance. This article explores the history, challenges and potential to standardize an often-over- looked contributor to well control equip- ment reliability. The well control equipment evolution The first BOPs were sketched out by James Abercrombie and Harry Cameron on a sawdust-covered machine shop floor just east of downtown Houston in the early 1920s. Since then, the industry has come a long way. State-of-the-art equipment is used to set wellheads more than 10,000 ft below the water line, deploy, latch and remotely operate multiplex subsea BOPs, and then drill into ultra-deep, high-pres- sure hydrocarbon reservoirs. To safely accomplish these engineer- ing breakthroughs, rigorous verification requirements such as pressure testing, function testing, manufacturing specifica- tions, maintenance protocols and kick/ leak-off detection methodologies have been developed. These standards have regularly been adopted by state and fed- eral regulators and incorporated into API Standards and/or the Code of Federal Regulations, in the context of subsea BOPs and subsea BOP control systems. BOP soak test value The BOP soak test involves detailed evaluation of the multiplex electro/ hydraulic circuitry in both the primary and secondary control systems of the BOP. It applies a predetermined pressure to various operators and fluid circuitry for a required duration. During this test, subsea engineers meticulously inspect the BOP for visible leaks, weeps, drips, fogging and other indicators that inform necessary maintenance before deployment. In many instances, digital monitoring and pressure signal analysis are performed concurrent- ly to expedite the soak testing process and mitigate the need for extended trouble- shooting iterations. A robust soak test prior to subsea deploy- ment provides an essential assessment of the health of the BOP. It provides crucial insights into the BOP stack’s fitness for service by identifying potential issues that could affect its performance and availabil- ity once deployed. By physically inspecting the BOP and analyzing the stabilized pres- sure readings over a brief period, trained personnel can identify leaks or potential component degradation within each pres- surized fluid circuit. This not only facili- tates troubleshooting and smarter mainte- nance efforts but also offers stakeholders peace of mind by ensuring due diligence has been accomplished to protect person- nel, the environment and related assets. While soak testing remains the fore- most method to assess control system health before deployment, it’s imperative to understand the inherent limitations. Soak tests can’t replicate the multifaceted, real-world conditions a BOP would face when placed on a wellhead. These factors, such as stack movement (both tension and compression), fluctuating temperatures and varying hydrostatic pressures, can significantly impact system performance. Recognizing these challenges, some BOP owners have pioneered innovative testing procedures. One such approach involves placing the stack under tension during surface testing, simulating the separation forces encountered at interface connec- tions. This method has proven beneficial, unveiling issues related to the design of specific seals. Moreover, these insights have inspired the development of designs that are better equipped to handle such dynamic movement, ensuring enhanced reliability and operational efficiency. Thus, while current testing methodolo- gies provide valuable insights, it’s impor- tant to continually evolve, capturing the nuances of real-world operations in the form of recommended best practices. Recent industry performance data Technological advancements have prompted industry experts and regula- tors to develop stricter requirements for equipment verification. These improve- ments reflect a deeper understanding of the industry’s increasingly complex equip- ment, enabling refinement of testing pro- tocols to ensure they are fit for purpose. Historical data presents some signifi- cant findings. As outlined in the BSEE- sanctioned report, “Blowout Preventer (BOP) Maintenance and Inspection Study by the American Bureau of Shipping and ABSG Consulting Inc. (2013),” 61% of sub- sea BOP system failures were linked to the control system. Notably, the blue and yellow control PODs, along with the sur- face MUX control system, accounted for over half of these failures. The study’s mean time to failure revealed an average of 48 days of operation between compo- nent failures. It’s crucial to note that due to built-in system redundancies, some of these recorded failures signaled the need for upcoming repairs rather than indicat- ing a stack pull. Fast-forward to the current era, where detailed defect data is available from the Rapid-S53 database. In the 2018 and 2019 DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 21 WELL CONTROL READINESS Figure 2 (above): The BOP Reliability Systems Soak Test dashboard uses pressure trend identification algorithm technology, which in this case identified a leak in the subsea manifold regulator fluid circuit within a minute of function actuation. Figure 3 (right): Upon visual inspection, confirmation was made identifying an SPM valve with a failed seal plate while at maximum operating pressure. annual reports, the cumulative average BOP pulls hovered around the low 30s annually for the represented BOP stacks. It’s clear there is a marked improvement in these figures when juxtaposed with data from preceding years. Data from 2020 and 2021 present an even more encouraging narrative: The number of stack pulls averaged in the low 20s. Many BOP experts acknowledge the pivotal role of the rigorous soak tests con- ducted prior to deployment. Although this isn’t a normalized metric, it points toward enhanced reliability performance. The inference? The industry is lean- ing into the lessons learned and making strides in equipment reliability perfor- mance. Considering this positive trend, coupled with industrywide knowledge sharing, there has been clear progress in the pursuit of zero NPT. State of industry practices Current industry practices regarding BOP soak testing exhibit significant varia- tions in frequency, methodology and test duration. Many equipment owners and operators conduct these tests regularly 22 before deployment, while others perform them both before and after deployment. Additionally, there’s no standardized time- frame for these tests, with durations rang- ing from minutes to days. The complexity of these tests also varies, from two-step tests to procedures with 15 or more steps. Factors influencing the testing methodology include stack configuration, contractual agreements, deployment dura- tion estimates, maintenance planning, con- dition-based maintenance program matu- rity, crew proficiency and digital monitor- ing capabilities. Despite these differences, “boots-on-the-ground” inspections remain the most common means of leak detection. There is also significant promise shown in the latest digital trend recognition algo- rithms. For example, a proactive subsea team, along with a specialized team of remote BOP analysts, have been able to identify system anomalies within min- utes of pressure stabilization and pinpoint critical components within each fluid cir- cuit (Figures 2-4). This can significantly reduce troubleshooting and fault-finding efforts during an already stressful, fast- paced pre-deployment period. Standardization challenges Differences in BOP design and opera- tional philosophies among major OEMs also contribute to variations in soak test- ing practices. Each OEM has testing proce- dures tailored to their BOP designs, leading to a wide array of testing methodologies. For instance, OEMs have freedom regard- ing the rated pressure of the operating chambers in their BOPs. These rated pres- sures can vary from a few hundred psi up to 5,000 psi or more. The soak tests must accommodate these differences that exist not only between different OEMs but also in different models of operators within each OEM. SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR WELL CONTROL READINESS An example involves hydraulic wellbore connectors. Some connectors should not be locked with pressure exceeding 1,500 psi due to crushing effects that may be imposed on the wellhead, BOP mandrel or test stump. There are others that physical- ly cannot be latched above a specified psi because a relief valve has been installed on the closing circuit. Testing should also take into account the OEMs’ allowable return flow for control system valves. This has been discussed in API Standard 53 committee meetings for potential inclusion in the next revision of the standard. Normal return rates have been reduced by design improvements (e.g., highly polished tungsten seal sur- faces versus matte finishes on softer mate- rials). Control system OEMs may produce new designs that would lead to tighter systems with less return flow. Potential to reshape with technology Collaboration and digitalization can play a pivotal role in standardizing BOP soak testing practices. By working togeth- er within the API committee meeting structure, operators, contractors and ser- vice providers can develop a unified test- ing methodology and recommended best practices that consider the different BOP configurations and unique requirements throughout the industry. Digital tools can streamline this process, making it easier to apply uniform testing protocols across various operations and regions. In addition, digital applications can be designed to perform trend analyses, remove subjectivity from test results, and help identify testing missteps (e.g., valve alignment and trapped pressure in the wellbore). Digital twin displays can facili- tate collaboration and provide insights for the stakeholders as they strive to protect people, the environment and assets. Standardization framework Given the history of control system failures, the industry has recognized the need for enhanced testing measures, par- ticularly in soak testing. Drilling contrac- tors have been refining procedures and monitoring techniques. This initiative aligns with the specifications set out in the 5th edition of API Standard 53 from Figure 4: In same time frame as Figures 2 and 3. Utilizing client-specified system pressure leak-off rate criteria, a passed test was seen after about 40 minutes. December 2018. This edition introduced the requirement for soak testing subsea stacks prior to deployment. Specifically, Table C7 emphasizes the need to validate the BOP stack hydraulic circuits at the highest pressures anticipated during well control operations. The test’s duration is per the equipment owner’s stipulations, with the key acceptance criterion being a visual confirmation of no leaks. Standardized BOP soak testing should encompass all aspects of the pre-deploy- ment soak testing process, including test step duration, pressure limitations, con- figuration (mode) and testing conditions. It should also consider the varying envi- ronmental conditions in which BOPs are deployed, as well as the different types of BOPs and their specific requirements. Path forward The contributors of this article support the development of standardized recom- mendations for BOP soak testing for inclu- sion in the next edition of API Standard 53. This could be an informative annex that will help reduce subjectivity in visual leak verifications, leading to enhanced safety and reliability performance industrywide. Equipment owners would have the benefit of shared best practices as a starting point for their procedures. Improving the effectiveness of pre- deployment soak testing of BOP systems will reduce risks directly associated with its reduced availability to perform the intended critical functions. In addition, reducing unplanned BOP pulls will elimi- nate risks associated with retrieval and subsequent redeployment. This further safeguards people and the environment. A joint effort among stakeholders in crafting this methodology will enable swift and effective BOP assessments and stable health KPIs, and further reduce subsea NPT. The journey to improve the reliability and performance in drilling operations will not cease as we reaffirm our commit- ment to improving industry standards of performance and safety. DC Reference: American Bureau of Shipping & ABSG Consulting Inc’s Blowout Preventer (BOP) Maintenance and Inspection Study Final Report for the Bureau of Safety and Environmental Enforcement., June 2013. DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 23 WELL CONTROL READINESS RECOMMENDED BEST PRACTICES When to perform a Soak Test • Before Deployment • Consider performing abbreviated soak testing after initial recovery, before BWM begins Test Step Duration and Leak off rate 2 Primary configuration Modes: 1. Drilling (No PIPE) 1 hr (Per POD) 2. Non-Drilling (PIPE) 1 hr (Per POD) • Configure BOP and allow Regulated Readback pressures to stabilize for 15 minutes. • Apply MOPFLPS pressure for 30 minutes. Total System Pressure Leak Off Rate should not exceed a maximum of 3 psi/min over 5 minutes. If MOPFLPS is less than normal operating pressure start at normal operating pressure • Rated working pressure (by OEM) for 30 minutes. Total System Pressure Leak Off Rate should not exceed a maximum of 3 psi/min over 5 minutes. • With Digital testing, along with visual inspection, these steps can usually be validated in 15 minutes Minimum and Maximum Pressures • Non-shearing BOPs (Blind, Pipe, VBR). • Minimum: MOPFLPS pressure • Maximum: RWP by OEM. • Sealing and non-sealing shear BOPs • Minimum: Normal operating pressure • Maximum: rated working pressure, or, highest pressure required to meet well shearing requirements. • HP Close: RWP (Time at HP close may be abbreviated) When latched to a test stump without digital monitoring • • • • When latched to a test stump with digital monitoring • Using software solutions to ensure no pressure differential across BOPs. • Keep FSVs open when any BOPs are closed in Wellbore. • Ensure there is always a wellbore bleed path when closing multiple BOPs ***Never close shear rams (UBSR, LBSR, or CSR) or other rams (e.g., UPR, LPR, MPR) without a bleed path. To prevent high differential pressures from occurring, ensure the wellbore has no fluid. If fluid is present in wellbore during soak testing, soak test FSVs in open position while critical path functions are soak tested in closed position. Ensure there is always a wellbore bleed path when closing multiple BOPs ***Never close shear rams (UBSR, LBSR, or CSR) or other rams (e.g., UPR, LPR, MPR) without a bleed path. Leaking POD Valves and Regulators • Volumes to be physically taken and recorded for OEM tolerance reference. • Reference OEM documentation in procedure for clarity. Digitization of leaks • If digital monitoring is available, collect physical fluid leak volumetric measurements, digital LOR data, digital ROC data for further correlations. BOP Control systems with Fluid Recovery Unit • Since it is less likely to find leaks visually, digital monitoring is especially useful and can expedite fault finding with system fully intact. • By way of digital timeline of LOR increase • Pressure trend anomaly correlation to a particular function. Adjusting Regulators • 500 psi (or less) increments allow for quicker stabilization with BOPs on Deck QA/QC • Use of two person HOLD POINTS - Quality checkpoints that shall be completed before moving forward with a procedure. • This may require verification by more than one party. Measurement verification, Workflow approvals, multi- party collaborations, Troubleshooting, BOP and Test joint compatibility. QA/QC • Critical hold points should require an Area Authority Approval to proceed. Sr. SSE, TP, STP, DSL, OIM, CM, ARM HPU System (e.g., 5K system) • • • • Function Lock Outs • Perform Function Lock outs whenever available. Software or Physical (Shear Rams particularly) • This can be digitally verified as a QA/QC function Test Joint Installation • Verify Seals on test joint if applicable. • Confirm BOP configuration is compatible with Test Joint size prior to installation in wellbore BWM Time/Scope Constraints Do not abbreviate Soak Testing without an MOC. All Accumulators Isolated except one 12x15 gallon accumulator rack. System Pressurized to 5000 psi HPU Pumps OFF Isolated racks should be bled below 4000 psi Table 1: The full proposed initial draft submitted to the API Standard 53 subcommittee on soak testing best practices 24 SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR WELL CONTROL READINESS RECOMMENDED BEST PRACTICES (CONTINUED) Prior to soak test, complete: • EDS • EHBS • Function test • Acoustic testing • Pressure testing • Setting of accumulator Pre-charge Pre-deployment electrical integrity tests After soak test • • • • Remedial actions Administrative • Include a section for handwritten notes for each test section of your RSOP. This will assist in creating maintenance actions within your maintenance management systems. Digital Troubleshooting • Monitoring Pilot readback will give a good indication to where an issue is rooted. E.g.: working pressure – pilot pressure = differential • Pressure trend shape recognition can be informative to the root cause of pressure oscillations. • Remote monitoring can expedite troubleshooting if communication between onshore and offshore teams is in place prior to beginning tests. Troubleshooting PODS Isolating Systems • Certain OEMs have control POD “test” capabilities. When fault finding, there may be an advantage to placing POD stingers inside of their test ring to determine where the leak or leak off is originating from. (CAUTION: Start with lower pressures as to not wash stinger seals.) Drift BOPs Skid BOPs to Well Center Check Stack and LMRP Bullseyes once Stack is picked up on first joint of riser. Complete all Pre-deployment testing administrative duties For acronyms not currently existing in STD 53 POD – Point Of Distribution RSOP – Rig Specific Operating Procedure LOR – Leak Off Rate ROC – Rate Of Change BWM – Between Well Maintenance MOPFLPS – Minimum Operating Pressure For Low Pressure Seal Sr. / SSE – Senior / Subsea Engineer TP – Toolpusher OIM – Offshore Installation Manager DSL – Drilling Section Leader ARM – Assistant Rig Manger STP – Senior Toolpusher CM – Chief Mate DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 25 WELL CONTROL READINESS Digital solutions bolster well control training as drilling workforce evolves Simulators, virtual and hybrid classes, and microlearning among ways training providers are adapting to students’ changing needs BY STEPHEN WHITFIELD, ASSOCIATE EDITOR W ell control training courses play a critical role in the development of skilled rig crews in the drilling indus- try. The ability of rig personnel to respond quickly and efficiently to well control events can save significant time, money and potentially lives. The fundamentals of well control training have been the same for decades – recognizing the hydrostatic pressure of the fluid in the wellbore and the formation pressure, as well as the different lines of defense to prevent lost circulation and potential blowouts. However, well control training providers understand the need to Highlights Training experiences via simulators are not only more immersive but also can be more basin-specific, simulating downhole environments very similar to what crews might see in the field. Training providers are working to ensure their teaching methods are effective not only in classrooms but also when delivered in a virtual or hybrid environment. Adaptive learning, microlearning and continuous instructor training are among other key focus areas of improvement. 26 adapt to the changing industry, incorporating more digital tech- nologies into their classrooms and embracing the virtual e-learn- ing courses that became prevalent during the COVID-19 pandemic. As operators and drillers continue to focus on digitalization, well control instructors are following suit. “Our world is changing at an accelerated rate, and it’s going to be necessary to ramp up our training capabilities if we’re going to equip our students with the skills needed to succeed,” said Ken Smith, VP of Well Control Training at Wild Well Control. “The evolution of technologies and the rapid demographic shifts are going to make this essential. In-person training is going to continue to be valuable as it reinforces core learning methodolo- gies and provides opportunities for collaboration, but I think the future of training will reflect a digital design in both presentation and delivery.” The industry is also adapting to a new workforce of younger personnel with more diverse backgrounds. The people coming into the industry today grew up with technology in a way their predecessors did not, and they respond to different methods of teaching. Well control instructors are constantly looking for new ways to reach their students, whether it’s through Zoom classes, specialized coursework or advanced simulators. However, even as the nature of well control training changes, instructors know that the concepts of well control are still the same. “We talk about automation, but if it all goes pear shaped, you still have a human being on a choke. It’s about understanding the basic concepts. Once the concepts have been learned, we can adapt to technology,” said Scotty Hooper, Head of Well Control SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR WELL CONTROL READINESS Above: To accommodate the needs of an evolving workforce, Well Control School began offering training courses that al- low for a mix of both in-person and remote students in the same class. These classes utilize PowerPoint presentations, rather than traditional whiteboards, to more easily share notes with both types of students. Right: Another new element in WCS’ training efforts is the in- corporation of physical and cloud-based simulators. They can model pressure, temperature and rheology, among other things, and provide a training experience where stu- dents can freely make mistakes and learn from them. Instruction and Development at Well Control School (WCS). “As the equipment evolves, the technology level of the people evolves, but what doesn’t change is the basic understanding of the con- cepts behind what they’re doing. Anybody can turn a valve, but why am I doing that? The way we might do the job does change, but the concept doesn’t.” Training in the virtual age WCS, an affiliate company of Cudd Well Control, has leapt head- first into the digital ecosystem. In April, the company announced it was incorporating physical, portable and cloud-based simula- tors from Applied Research International (ARI) into its in-person and online training courses. ARI’s drilling simulator models pressure, temperature, rheology, drill cuttings transportation and filter cake formations. It also models drill string dynamics, including effects like drill string whirling, vibration, twist, stick-slip and bit bouncing. Instructors can configure the geographical profile of the well, including adjustments for rock hardness, rock porosity, rock permeability and formation pressure. “With these new simulators, the student is actually learning something, not just operating software and watching a video. It goes along with our basic philosophy of enveloping the student in well control. That’s what we do with our curriculum, and now it’s coming through simulations,” said Dana Varisco, President of WCS. Mr Hooper described the simulators as a means to present well control lessons in a different manner than the conventional methods of having students read from a textbook or look at an instructor diagram on a whiteboard. Instead, the simulators pro- DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 27 WELL CONTROL READINESS lesson planning and moving toward basin-specific lessons: “If I’m going out to Texas to drill, why would I assume those formations are going to look like they do in Wyoming?” The SME Friday talks have also spawned an internal podcast, “Onsite with TD,” where Mr Deer speaks with SMEs about current issues surrounding well control. Ryan Hays, Director of Business Development at WCS and a Senior Well Control Instructor, cited the SME talks and podcast as examples of how WCS continues to adapt to a new way of working and meet students where they are. “The industry has changed,” Mr Hays said. “The old status quo was that you had one man preaching how it’s going to be, and everybody had to do it that way. Now you have teams of diverse people working together daily sharing different points of view to make training better for everyone.” In February, Wild Well Control announced a partnership with Endeavor Technologies for the use of well control-focused drilling simulators that feature proprietary computational fluid dynamics and hydraulics models. The simulators are being added to Wild Well’s training centers across the US. vide an immersive training experience where students can make mistakes and learn from those mistakes. “Putting concepts into practice is the key benefit of using simu- lators. You can sit in a training class and be taught concepts and theories, but a simulator enables you to actually put that theory into play and practice those concepts. You can think, well, what if I do this in this situation? And if that didn’t work, you can find out why it didn’t work,” he said. However, simulators are just one example of how a digital sys- tem can help instructors reach students in new ways. Another example is virtual training, said Toney Deer, Director of Training and a Senior Well Control Instructor at WCS. The company has offered online training options since 2001 through its System 21 e-learning courses but has seen a surging interest in virtual classes in recent years, with the pandemic forcing companies to embrace distance learning options. Although the industry has returned to normal operations since, virtual training still serves a critical function as the workforce has become more accustomed to the remote work lifestyle. To accommodate this shift, WCS rolled out virtual training in 2020 that features live instruction presented to students over Zoom with an instructor, as well as training courses that allow for a mix of both in-person and remote students in the same class. In these classes, instructors bypass the traditional whiteboard and instead use PowerPoint presentations, where notes can be written directly onto the slides. Mr Deer also stressed the importance of ongoing instruc- tor training. Earlier this year, the company began hosting SME Fridays, a monthly virtual event where WCS instructors meet with a subject matter expert from an operator or drilling contrac- tor company to learn about key issues they’re facing in the field. The instructors can then incorporate those insights into their les- sons. Mr Deer cited an example from a recent meeting where an SME stressed the importance of moving away from standardized 28 Improving the in-person experience At Wild Well Control, adapting to new training challenges is a norm. During COVID, for example, in addition to their on-demand library of e-learning courses, the company began offering access to IADC WellSharp Live online training programs. Another challenge since the pandemic is that the students undergoing well control training are now coming from much more diverse backgrounds, with fewer people coming from petro- leum engineering and more people coming from computer sci- ence, data analytics and even non-STEM related fields. The latter type of students are sometimes less familiar with the equipment used to maintain well control, as well as how surface operations and pressures can affect issues downhole. Recognizing that in-person training is particularly valuable for these types of students, Mr Smith said, the company has been working to bolster that classroom experience. “Facilitation is a huge way to bring up the guys who have a lower level of understanding,” he explained. “You can work with teams and pair the newer people up with the more experienced guys. The students do a lot more talking with the in-person class- es. With the online classes, the instructors do a lot more talking. It’s just the nature of the beast.” Improving the in-person experience also means adjusting the way students are taught, and Mr Smith pointed to adaptive learn- ing as one key strategy. This involves, for instance, structuring homework assignments to fit the learning styles of each student – some students may receive assignments laden with visual aids, while others may have lessons more focused on written questions and answers. The company is also exploring microlearning, an educational strategy that breaks complex topics down into short- form, stand-alone units of study that can be viewed as many times as necessary at a student’s convenience. In line with this mindset, Wild Well Control has a heavy focus on continuous improvement of not only the training materials but also the curriculum delivered by its instructors. Internally, the instruction team continuously reviews and adapts the lessons to optimize the content and instructional delivery. This process is critical to keeping the material fresh and relevant, as well as to ensure accuracy of content. “I think adapting our training to align preferred learning methods with current knowledge and skill levels is going to be SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR WELL CONTROL READINESS a must. A lot of this can be done with our homework and our side learning tools. Microlearning is going to continue to be refined so it can accompany the in-learning experience with easy-to-digest, engaging homework, leading to a much better experience. I look at the younger generation and how they’re digesting material vs the traditional ways, and clearly that is the future.” Simulators are also set to play a role in bolstering the in-person experience, primarily through Wild Well’s partnership with Endeavor Technologies. The partnership, announced in February, calls for Endeavor to provide drilling simulators for well control training simulator rooms across Wild Well’s seven training cen- ters across the US. The simulator implementation is expected to be completed by year-end. The appeal of Endeavor’s simulators is in its computational fluid dynamics model, which consists of a circulation system that solves and analyzes problems involving fluid flows, Mr Smith said. There is also a proprietary hydraulics model that demonstrates the flow and pressure of the drilling fluid, which the simulator uses in a multi-layered approach to model the complex physical phenomena that occur inside the hydraulics system. These phenomena include the state, movement and interactions among the drilling fluid, gas, cuttings, formation, surface and underground equipment. While most simulators are more drilling-focused, the fluid dynamics and hydraulics model provide a specific well control focus, Mr Smith said. “A lot of companies out there make drilling simulators, but that doesn’t help us a lot because we’re focused on well control. There is some drilling on our simulators, but we’re not teaching you how to drill through a formation. We’re teaching how to control a well and control the gas in the well,” he explained. Another feature of the Endeavor simulators is their capability to simulate specific well intervention operations, such as installing packers and the upper completion, fishing and cement squeeze. Mr Smith also touted their ability to enable a more granular level of training by simulating, for example, the higher pressures and temperatures of the Haynesville Shale or the slower drilling seen in the Bakken. Outside of the classroom or the virtual training session, stu- dents also will have access to simulation-based exercises they can undertake to bolster the well control concepts that they’re taught by the instructors. “The education received ensures the principles are understood prior to running a simulator, but I compare the concept to running a motorcycle: You need a core of understanding prior to riding the bike,” Mr Smith said. “The simulator is like riding the bike. You need to truly understand the principles so that, by the time you’re using the simulator, you’re focusing on muscle memory and developing a deeper under- standing of the knowledge you’re getting in class.” DC TIME FOR A CHANGE? LISTEN TO THE EXPERTS "With over 68 years in the rental tool business, we are continuously adapting and evolving to our customers' needs. TSC Drill Pipe's PTECH+™ connection is an intricate part of that evolution." - CustomerTestimony (832) 230-8228 ContactUs@drillpipe.com www.drillpipe.com C O N N E C T I O N DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 29 I N NOVATIVE DR I LLI N G TECH N IQU E S Amid growing uptake of MPD in deepwater, controlled mud level technology deserves another look By taking opposite pressure management approach to SBP method, CML achieves similar benefits while widening deployment window BY ANTHONY SPINLER, ENHANCED DRILLING The oil and gas industry is constantly evolving, driven by the need for more efficient and sustainable exploration and production methods. EC-Drill and its con- trolled mud level (CML) systems have grown from an initial concept of two sys- tems used in the North Sea to a technology that has drilled almost 100 offshore wells and, within a few months, has gone from one CML-capable rig in the Gulf of Mexico (GOM) to having its third. This article delves into the world of CML, exploring its benefits and underly- ing principles, showing the potential to reshape the future of offshore drilling. Similar benefits as SBP but achieved differently Managed pressure drilling (MPD) is one of the most prominent components of the offshore market today. Drilling contrac- tors have stated that approximately 80% of deepwater rig tenders require MPD capability. In almost all cases, the speci- fications are toward surface back pressure (SBP) technology, which is well estab- lished on land and offshore. Drilling engi- neers and executives may have heard of CML but must familiarize themselves with the breakthroughs driving adoption. CML, introduced in 2010, is an MPD technique that combines innovative pump technologies and advanced drilling prac- tices to optimize the extraction of oil and gas reserves from the initial liners to completions. Since the wellbore is open, similar to conventional drilling, it enables well-known and established drilling and well control procedures to improve drilling 30 efficiency, increase recoverable reserves and reduce the environmental footprint. Pressure in the wellbore is controlled by changing the equivalent mud weight in real time by adjusting the height of the mud column in the riser; this provides greater flexibility during drilling opera- tions and enables operators to navigate through challenging geological formations with improved accuracy with less pres- sure-induced risk. CML offers several advantages similar to SBP, including enhanced wellbore sta- bility, reduced nonproductive time, better control over wellbore pressures and the ability to mitigate kicks and prevent blow- outs. But it does so in the opposite way to SBP. The EC-Drill CML pump systems pro- vide more than MPD, including pre-BOP and pre-riser installation for cuttings transfer and riserless mud recovery. Top- hole sections that cannot use SBP can still utilize CML equipment, providing addi- tional environmental and cost savings at applicable water depths. Underbalanced vs overbalanced MPD, predominantly known and used as SBP since 1968, offers a revolutionary approach to drilling through reservoirs. Unlike conventional drilling, SBP uses mud weight less than the formation pres- sure, causing the well to be hydrostatically underbalanced when not applying back pressure. As such, reservoir fluids can, and are, sometimes allowed to flow into the wellbore as it operates on the pore pres- sure side of the formation. This technique is particularly beneficial in unconvention- al reservoirs, tight gas formations and mature fields. SBP starts with an under- balanced mud weight and increases the pressure through a rotating control device (RCD) and choke, thus increasing the pres- sure from above at the rig floor. In doing so, the pressure returning from the bottom of the hole increases when SBP is applied. CML utilizes a balanced mud weight for the drilling window and lowers the height of the mud column to reduce the effec- tive bottomhole pressure. Therefore, the hydrostatic pressure profile increases with depth – the opposite of SBP. The wellbore pressure will then match the operating window’s typical trend and allow for lon- ger sections, especially in deepwater envi- ronments that would otherwise require frequent casings. CML is conventional drilling where the balanced mud weight is utilized and only available offshore. In deepwater, the EC-Drill system places an approximately 16.5-ton subsea pump at roughly 1,200 ft (366 m) below the water surface, and the pump’s output maintains the desired riser level to establish the required bottomhole pressure (BHP). Since CML does not insert an RCD into the wellbore, it performs MPD during all drilling operations: drilling, trip- ping, liner and casing running, measure- ment, cleaning, completions, or whatever product or tool customers want to put down the hole. The author estimates that only 30-40% of operational time offshore can utilize SBP; with CML, potentially 100% can be done when the riser is in position. Enhanced Drilling estimates that EC-Drill operations in the GOM have shown utilization during approximately 85% of all drilling opera- tions (drilling, cementing and tripping) and 50% of completions. Smoother drilling One unique aspect of CML is that it is similar to conventional drilling, as the subsea pump does not close the well- bore. With SBP’s use of an RCD, operations require multiple calculations: a lowered mud weight and then applying addition- al pressure. As SBP operations contin- ue, the well often requires an entirely different mud weight and conducting a SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR I N NOVATIVE DR I LLI N G TECH N IQU E S mud rollover. The new lower mud weight cycles into the well, so back pressure must increase again to reach the required BHP, or a higher mud weight must be applied to transition out of utilizing SBP. CML eliminates these situations by applying a balanced mud weight to the well, starting the BHP closer to the frac- ture gradient than SBP. Then, the pressure is lowered to manage the BHP. One could say that SBP approaches the MPD solu- tion from the pore pressure side, risking an influx, while CML approaches the MPD solution from the fracture pressure side, risking losses. For operators concerned about the incredibly costly and environ- mental expense of losses, CML provides the tool to manage losses effectively while lowering the risk of operating from the pore pressure side of the pressure window. Further, there is an additional ease of use for cementing and completion opera- tions, which require managing increas- ing pressures as these operations proceed. Excess pressure in cementing results in costly losses and a possible poor cement job, risking catastrophic failure. Excess pressures in completion operations result in a damaged reservoir that could impact everything from initial production to total recovered reserves. With CML, as the pres- sure rises, lowering the riser level man- ages the pressure profile and creates what looks like a saw tooth: Pressure goes up during the operation, then the pressure is reduced by CML maintaining the window throughout the cementing or completion. As experienced in several cases with the EC-Drill system, completion results reached top-quartile performance. Effectively finishing both – the alpha and beta phases of completion operations – without damaging the formation has resulted in flow rates exceeding the drill- ing rig’s ability to flare. As one customer explained, “Wells estimated to have a 5- to 10-year lifespan are now turning out to be 10- to 15-year wells.” The exact flow rates are proprietary to the operator. For example, various drilling operations require heavier/denser fluids using water- based drilling fluids or heavy brines like CaBr2 and ZnBr2. An overpressure of these fluids can damage everything from the casing shoe to the reservoir. The ability to lower the overall BHP by reducing the riser Figure 1: The EC-Drill CML system can help to eliminate intermediate casing strings while navigating tight pressure windows in deepwater wells. fluid level enables standardizing on other proven technologies and fluids. An issue offshore is that the casing string length sometimes exceeds the water depth, which heavily impacts the value proposition of SBP-based MPD. Even if the SBP drills the well, it cannot manage the pressure while installing these longer liners/casings. This issue does not affect CML, which can apply MPD techniques while installing all casing sizes. In addi- tion, for operators who strive for a robust separation between the primary and sec- ondary barrier, CML provides a clear tran- sition from the barrier envelope to stan- dard well control procedures. Additional steps are not required to roll over the mud or close the BOP while tripping, as it already uses a balanced mud. Operators and drilling contractors can operate with well-established and proven well control procedures while also having MPD. Improving sustainability Apart from the operational advantag- es, CML also contributes to environmen- tal sustainability. By optimizing drilling operations, these techniques minimize the number of wells required to extract equiv- alent hydrocarbons, reducing the overall DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 31 I N NOVATIVE DR I LLI N G TECH N IQU E S Figure 2 (left): CML has potential to help the industry achieve dual-gradient drilling so that offshore wells can be drilled like land wells. Figure 3 (right): By reducing well costs and increasing recoverable reserves, CML can allow operators to add more wells to a drilling program while maximizing project ROI. surface footprint and ecological impact. Moreover, CML results in less fluid and mud losses, minimizing the environmen- tal impact of creating them. Additionally, the reduced need for re-drilling due to wellbore instability, as well as rig time savings, decrease the carbon footprint. Dual gradient Dual-gradient drilling (DGD) represents the pinnacle of managing pressure down- hole, which the industry has yet to achieve. As stated by one offshore operator: “It will enable us to drill offshore like we drill land wells.” As analysis and application continue on CML, it reveals that DGD may not be as far away as previously thought. Traditionally, DGD utilizes a lighter mud weight, typically seawater, in the riser on top of the applicable drilling mud below the mud line. With CML, the lighter mud weight is air on top of the controlled mud height. For example, in a typical deepwater well in the GOM, using a 12.5-ppg mud weight, the seawater depth and 12.5-ppg mud weight produce the same annular pressure profile, with CML lowering the mud height 2,500 ft (762 m). No device is needed near the mud line as previously thought to achieve DGD. To maintain a tight drilling window, standard DGD practices would fall short, whereas a CML system performs constant BHP-enabling MPD while never changing the mud weight. Shifting financial model The combined outcome of these ben- efits can transform development project economics for operators adopting CML technology. Well architecture simplifi- » Shell Senior VP of Wells: CML system shows promise in US Gulf of Mexico Watch DC’s one-on-one conversation with Michael Collins. bit.ly/45g78xG 32 cation and drilling operational improve- ments reduce well cost, and completion results increase recoverable reserves. As shown in Figure 3, that combination of reduced well costs and increased recover- able reserves in wells 1-4 changed well economics and allowed additional wells (5-7) to pass the hurdle rate. Several offshore operators have stated that they now require their drilling teams to justify not using MPD, signifying that MPD has proven to result in lower overall costs and faster well completions due to less nonproductive time from pressure- related incidents. MPD is a proven offshore technology for SBP and now for CML. While CML holds immense promise, it has similar challenges to SBP. Implementing these advanced techniques requires spe- cialized equipment, well-trained person- nel and significant upfront investments. However, as the oil and gas industry seeks to strike a balance between energy demands and environmental sustain- ability, the future of CML appears bright. Ongoing R&D efforts will lead to further optimizations and cost reductions, mak- ing CML a standard offshore practice. As one operator customer shared, “SBP is the right technology for exploration drill- ing as we are dealing with high levels of uncertainty. CML is the right technology for development drilling as we should be able to plan the pressures we need to achieve best-in-class drilling, cementing and completions.” DC SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR Under The Patronage of H.H. Sheikh Mohamed Bin Zayed Al Nahyan, President Of The United Arab Emirates 2-5 October 2023 Abu Dhabi, UAE Decarbonising. Faster. Together. ADIPEC, the world’s largest energy exhibition and conference, brings together the ideas, ambition, technology and capital needed to accelerate the urgent, collective and responsible action that can decarbonise and future-proof our energy system. ADIPEC in Numbers 160,000 15,000 2,200 1,600 54 350 30 10 Energy professionals Conference delegates Exhibiting companies Conference speakers NOCs, IOCs, NECs and IECs Conference sessions Conferences Country pavilions Register as a visitor Register as a delegate www.adipec.com Supported by Partners TOTAL TOT_21_00008_TotalEnergies_Logo_CMYK JFB 30-34 Rue du Chemin Vert 75011 Paris +33 (0)1 85 56 97 00 www.carrenoir.com TONS RECOMMANDÉS CYAN Platinum sponsors MAGENTA Ce fichier est un document d’exécution créé sur Illustrator version CS6. Date : 26/05/2021 TECHNIQUE YELLOW Gold sponsors CMYK Solid Logo Master Stacked Host city Official hotel partner Official travel partner Venue partner Knowledge partner Strategic insights partner Technical Conference organised by ADIPEC brought to you by DECARBONIZING DRILLING New contracting models needed to finance decarbonization programs, drive new solutions Contractual incentives for fuel savings, earlier collaboration between operator/contractor, and long-term contracts among potential strategies Sustainable contract models BY JESSICA WHITESIDE, CONTRIBUTOR While there is agreement within the drill- ing industry that emissions reductions must be prioritized, there is no consen- sus on who should pay for the technolo- gies and tactics required to achieve those reductions. “We have a responsibility to have an open debate about how we go for- ward,” Darren Sutherland, Vice President – Europe & Africa at Borr Drilling, said at the 2023 IADC World Drilling Conference in London. Mr Sutherland was among several participants on a panel session focused on how the upstream industry should finance its decarbonization efforts. He noted that drilling contractors face distinct challenges in accessing the resources needed to finance decarboniza- tion initiatives, such as more limited bank lending options and higher debt costs for bond issues. “We don’t have easy access to money. We’re going to have to earn it and use our own cash if we need to.” There’s also a stark contrast in finan- cial backdrop between the operator and offshore drilling contractor sides of the business. For operators: relatively consis- tent dividend payouts, share buybacks and debt reduction. For drillers: no dividends for several years, few share buybacks except as part of a transaction, and operat- ing cash flow that has gone consistently downhill the past few years, at times drop- ping below CAPEX. At the same time, they’re also still deal- ing with “discount” trends on dayrates. “That’s the trend even now as the markets are on the way up. There’s a continual pressure: reduce your costs, reduce your costs. And it can’t continue because it’s not sustainable,” Mr Sutherland said. It can also be challenging for drillers to justify investing in emissions reduction when the benefits go to the operator, said Darrel Pelley, Managing Director Technical The panel featured (from left) Brage Johannessen, Parker Wellbore (moderator); Darren Sutherland, Borr Drilling; Ian Ferguson, Shell; Ellen Hald, Equinor; Darrel Pel- ley, Transocean; and Michael Strauss, Ensign Energy (moderator) 34 Marketing at Transocean. For example, cost savings achieved when reducing fuel use on the rig typically accrues to the oper- ator, not the contractor. “Typically fuels are furnished by our customers. As a result, every drop that we save, the fuel savings flow straight back to them,” he said. “They control the well design. They set the order of activities. In some cases, they even dictate the way our power plant is con- figured, which further limits our ability to optimize power plants and maximize our fuel efficiency.” To combat some of these challenges, Mr Sutherland called for the industry to adopt more sustainable contracting strat- egies. Such strategies would give drill- ers “contracts that we can hang our hat on,” which can be taken to the bank for financing, or can help give confidence to shareholders and banks that investments in newbuilds or equipment upgrades will generate returns. “It’s really important that we have a look at the contracting model in the context of anything to do with decarbonization performance and efficiencies in our busi- ness,” he said. Under traditional dayrate arrangements, finding ways to cut days off the well – which reduces emissions by requiring less diesel to be burned – can mean savings for the operator. For the contractor, however, that translates to a reduction in forecasted revenue, Mr Sutherland said. “How do we get that balance back whereby if I’m sav- ing you a significant amount of money, I get a significant amount of money back?” Rather than slipping into the age-old discussion of how big the bonus should be, the industry has to step back and look at contracts differently, urged Ian Ferguson, General Manager Wells Operations – UK & Norway at Shell. To incentivize pursuit of higher-cost decarbonization options, contractors and operators will need to figure out arrangements that are mutually beneficial. He added that there’s “probably a discussion to be had on longer-term deals” that enable design and equipment spec choices that consider decarboniza- tion efforts into account. “Maybe in that new base contract we’re saying, ‘Actually, it should also include SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DECARBONIZING DRILLING greenhouse gas emissions and efficiency.’ And there’s various ways you can get that,” Mr Ferguson said. “You get it by drilling a quicker well, by managing energy use, by choosing the fuel supply.” Because the bulk of emissions from drilling operations comes from the burn- ing of diesel fuel, decarbonization efforts have focused on initiatives such as rig electrification, alternative fuels, or fuel and energy efficiency approaches. Some opera- tors are looking at incentive arrangements to share the benefits of fuel savings with contractors. Equinor, for one, has included fuel incentives in its rig contracts. “It’s vital that drilling rigs perform effi- ciently and have as low a fuel consump- tion as possible,” said Ellen Hald, Manager, Lower Carbon Solutions in Drilling and Wells at Equinor. Existing solutions like engine management systems, exhaust heat recovery and hybrid solutions will not be sufficient to close the gap toward emis- sions goals, she said. “This emphasizes the need for both smart energy usage on our rigs and that we need new solutions in our toolbox,” she said. “Strong collabo- ration between operators and suppliers have been essential for development of our industry in the past and will be important for safe and sustainable energy transition going forward.” Shell, too, has begun bolting incentiviza- tion for decarbonization performance onto its contracts while incorporating language around aligned values, including decar- bonization, into its sustainability clauses, Mr Ferguson said. “We have made cleaner well operations one of our five key pil- lars for how we want to improve how we deliver our wells activities between 2020 and 2050.” He pointed to Shell’s partnership with Diamond Offshore on an engine manage- ment system on the Ocean Endeavor semi- submersible as a “role model” for this sort of approach. “What we’ve done is said, ‘Where we save diesel, we will pass that benefit on to you in the form of an incentive,’” Mr Ferguson said, describing this decision as “a natural thing to walk into once we understood it… Why not just make that the norm?” For contractors, they see earlier involve- ment with their customers’ drilling pro- grams as a cost-effective way to increase collaboration and, therefore, efficiency. For example, at what Mr Pelley called the tactical level, he noted that contractors can reduce fuel consumption during rig moves simply by adjusting the transit speed. “There’s a diminishing value once your engine load is getting up to 70-80%.” At a more strategic level, the operator and contractor can also better collaborate to identify decarbonization technologies that give maximize value, with an under- standing of the time and costs associ- ated with first piloting and then deploying those technologies at scale, Mr Pelley said. For some larger decarbonization proj- ects where upgrade costs can run into the millions, contractors need significant terms on their contracts to pay that back. “We cannot invest unilaterally,” Mr Pelley said. “Commercially, operator participation is absolutely critical right now.” DC DECARBONIZING DRILLING Companies zero in on cementing process to have outsized impact on well construction emissions Solutions being deployed include well planning and emissions monitoring software, as well as technologies with reduced Portland cement BY STEPHEN WHITFIELD, ASSOCIATE EDITOR As the world continues to move toward a low-carbon future, the oil and gas indus- try’s ability, to not only reduce its emis- sions but also to quantify its emissions reduction performance, has become a pri- ority. One component of the well construc- tion process with significant potential for emissions efficiency is cementing. Studies have shown the production of cement to be an emissions-intensive process involv- ing heating kilns to very high tempera- tures, as well as calcination, a chemical reaction that occurs when raw materials like limestone are exposed to those high temperatures. Other steps like quarrying and transport also add to the emissions footprint. That’s why operators like BP are work- ing on reducing their use of cement in well construction, while cementing solu- tions providers target reducing the car- bon footprint of cement production, said Emmanuel Therond, BP Technical Advisor. One part of BP’s work in this area is its Well Design Optimizer software pro- gram, launched last year. It’s a tool that its engineers can use to estimate green- house gas (GHG) emissions as they are planning wells. Cementing is one of four components that the software measures, along with fuel usage, planned testing and planned casing, Mr Therond explained in at the 2023 IADC World Drilling Conference. The software uses pre-established emissions factors to obtain estimates of CO 2 generation from various activities. Emissions factors are representative val- ues that attempt to relate the quantity of 36 a pollutant released into the atmosphere with an activity associated with the release of that pollutant. When multiplied by activity indicators input by the drilling engineer, the software can provide an esti- mate of the CO 2 emissions that the given activity will generate. Mr Therond noted that the software is not a tool for reporting or calculating emissions; the estimates generated by the software are only shared within BP and with its third-party contractors. The goal, rather, is to help personnel decide if any actions can be taken through better well planning to help reduce emissions. “This is a tool for estimating emissions so that drilling engineers can understand what options they have to reduce emis- sions without compromising the well’s construction,” he said. “It might sound very simplistic, but I think this is the first step, so we can start understanding and acting upon these numbers. Right now, we don’t have the tools that allow us to have quality conversations with the drilling engineers.” One of the first projects where BP deployed the Well Design Optimizer was an offshore well drilled last year in the Mediterranean Sea. The process began by entering data related to: rig type (drillship); number of days planned to drill the well (183); estimated diesel consumption (31 tonnes/day); the type of well testing (flaring); the specific gravity of the gas flared dur- ing testing (0.70); duration of testing (1 day); Reducing the use of carbon-intensive Portland cement in well cementing op- erations can help the industry to reduce its overall emissions profile, said Patrick Lynch, Regional Business Development Lead – Low Carbon Ventures at Halli- burton, at the IADC World Drilling Con- ference in London on 21 June. the production rate during well testing (50,000 standard cu ft/day); and the slurry densities for each hole section in the well. From these inputs, the software gener- ated an emissions estimate for the well, multiplying select variables by given emissions factors for each variable. It esti- mated that the well would generate nearly 24,000 tonnes of CO 2 over its lifetime, and only 2% of that would come from cement usage. Since that is within the 1-5% aver- age range BP typically sees, it confirmed no action was required to revise the well plan and cement usage. If the estimates had been abnormally high, however, the operator could have taken early steps to alter the design. Reducing Portland cement in completions Halliburton is also working to help operators reduce emissions from cement- ing through its Verified Integrated Design Application (VIDA) and Envana Catalyst emissions monitoring software. VIDA is a design modeling software that identifies the risk mitigation factors within a well’s design; it can also be paired with Envana Catalyst to provide a comprehensive esti- mate of the amount of CO 2 generated by SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DECARBONIZING DRILLING specific pieces of equipment used on a well during the well’s lifecycle. To get these estimates, the drilling engineer first inputs basic data for the planned well, including the number of days planned to use a given piece of equip- ment. Those inputs are then automati- cally transferred to the Envana Catalyst program, which runs them against other inputs and emissions data stored in a his- torical database from equipment used on similar wells drilled by Halliburton clients. Using the inputs provided by the drill- ing engineer, as well as the historical data, the Envana Catalyst program calculates emissions estimates for the rig’s equip- ment and displays the results within VIDA. Once the well is drilled, the emissions data from the equipment is input into Envana to provide additional data points for future well designs. “We have the information from years and years of our operations, and thousands of calculations in different geography iterations,” said Patrick Lynch, Regional Business Development Lead – Low Carbon Ventures at Halliburton. “We’ve learned a lot because, if you’re simulating cement- ing operations around the world, there are a lot of different options you can take with the blend.” The software systems, when combined, can provide a granular breakdown of which parts of the drilling and completions process are generating the most emissions. At the World Drilling conference, Mr Lynch discussed a pair of cementing operations, one from an offshore well and one from onshore. For the offshore well, users input the expected pumping hours and idle hours for the rig’s cement pumping unit, along with the location of the well, the estimated mileage transporting the cement from the manufacturing site to the rig, the type of cement used (Portland cement), the batch mixer and the liquid additive system. From those inputs, the Envana system estimated that 98% of the emissions gener- ated from cementing would come from the production of the cement blend, with the remaining 2% split among the batch mixer, cement pumping unit and the liquid addi- tive system. The onshore well saw similar results: It was estimated that 81% of the cement job’s emissions would come from the cement A 2020 report by McKinsey & Company, citing 2017 data from the Global Cement and Concrete Association, showed that the majority of CO 2 emissions generated during cement manufacturing came from the preheating and precalcinating pro- cesses, where raw materials are exposed to high temperatures. blend, 14% from the consumption equip- ment (the cement pump truck, storage bin and the bulk truck), and the remaining 5% from transportation of the cement to the wellsite. These examples were indicative of a larger trend Halliburton noted in its emis- sions data, Mr Lynch said – that the pro- duction of cement accounted for more than 90% of the total emissions from its oil well cementing operations. This highlight- ed the importance in reducing the amount of cement used. In 2021, the company launched its NeoCem E+ and EnviraCem systems, which contain a reduced amount of Portland cement mixed with locally sourced byproducts. Compared with the company’s conventional cementing sys- tem, the NeoCem E+ system contains 50% less Portland cement while EnviraCem cement contains 70% less. Using locally sourced byproducts is the key differentiator for these solu- tions, Mr Lynch said. When companies create cementing solutions with reduced Portland cement, they often sub it out with mined materials that can only be found in limited locations around the world. This leads to additional CO 2 emissions from the extraction and the logistics of transporting them to a facility for processing. Because NeoCem E+ and EnviraCem “are heavily comprised of locally produced products and some minor manufactured components, they can provide reduced CO 2 emissions in our cementing opera- tions,” Mr Lynch explained. “The point is, rather than having a single source for the raw materials in our cement and then transporting that around the world, we’re trying to take away the transport-related aspect of the emissions wherever pos- sible.” In addition to emissions-related ben- efits, the reduced-Portland cement sys- tems can also better withstand the down- hole demands from continual pressure and temperature changes throughout the life of the well compared with conven- tional cement systems. He credited this to Halliburton’s approach to specifically tai- loring its reduced-Portland cement blends to the needs of specific cementing jobs. “We can leverage our database of lab test- ing along with our physiochemical under- standing of the materials to create tailored engineered systems designed to produce specific properties downhole. Every cement is specifically engineered to do an efficient job, and we’re seeing benefits in properties like thickening, fluid stability and fluid loss control,” he said. DC DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 37 DR I LLI N G AUTOMATION Robotic system enhances safety by keeping personnel out of red zones on the drill floor during offshore riser operations Technology incorporates robots with visual detection systems, adaptive control software to automate repetitive bolting operations BY JESSICA WHITESIDE, CONTRIBUTOR Installing and removing the bolts that con- nect the massive sections of a marine drilling riser is a labor-intensive job that requires crews to work with heavy equip- ment and hydraulics in the restricted- access “red zone,” where risk of injury is high. Transocean is aiming to eliminate that risk to personnel by handing the bolt- ing task to robots instead, keeping work- ers safely off the drill floor during riser operations. The offshore driller partnered with Houston-based ARC Specialties and Offshore Robotics to develop the robotic riser system, resulting in two designs for use with flanged connections on NOV and Cameron risers. The Cameron design was deployed on Transocean’s Deepwater Conqueror and Deepwater Poseidon ultra- deepwater drillships in the Gulf of Mexico in 2022. The NOV design was anticipated to be deployed in July, also in the Gulf of Mexico, for the first-ever riser deployment of Transocean’s eighth-generation ultra- deepwater drillship, Deepwater Titan. This would mark the first application of the robotic riser system on a rig with 20,000- psi well control capabilities. “It’s a very exciting time for Transocean and the industry,” Travis McGuire, Operations Performance Manager – Special Projects for Transocean, said at the 2023 IADC World Drilling Conference in London in June. “It’s been an incredible opportunity and experience.” Manual riser bolting challenges In deepwater drilling, connecting the riser joints together may require hundreds of bolts, each of which weighs approx- imately 55 lb and must be torqued to approximately 18,000 ft-lb – roughly 180 times more torque than a car wheel nut, Mr McGuire said. Traditional riser running or pulling operations requires six crew members working continuously in the red zone, with additional people supporting the operation, such as drillers, toolpushers, crane operators, floorhands, roughnecks and subsea engineers. Each thousand feet of riser string deployed equates to about eight hours of personnel exposure to the red zone, where the heavy, repetitive work of moving bolts and other equipment and using a 250-lb torque wrench can leave crew members susceptible to hand, finger, foot or back injuries. That’s a stark contrast to the robotic sys- tem, which requires virtually no personnel exposure to the red zone. Humans are only needed if a validation or other check is required, which would take up to a half- hour, Mr McGuire said. The robotic system also holds advan- tages in terms of efficiency. It’s capable of making up or breaking out 4-5 joints per hour, compared with an average 3.5-4.5 joints per hour with manual handling. Moreover, those crew members can now use that time to work on other tasks, he noted. “Those five and six people can now do other activities that are much more valu- able than picking up 55-lb bolts, putting them into a hole, holding onto a torque wrench and torquing up. We can do all of that in a much more efficient manner.” Transocean’s pursuit of a robotic riser system was spurred in part by a fatality on another company’s rig during riser opera- tions in the Gulf of Mexico in 2020. That incident prompted the question, “How do we get people further away from heavy iron and put them in a better place to do their job?” Mr McGuire said. How the robots work Travis McGuire with Transocean talked at the 2023 IADC World Drilling Conference in June about how the company is using a robotic riser system to automate bolt installations and removals, thereby reducing personnel red zone exposure. 38 The patented system developed by Transocean and its partners is set up on the spider deck and incorporates two large robotic arms. The arms are equipped with tools that enable them to pick up and manipulate the riser bolts and place stab- bing guides to ensure proper alignment of SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DR I LLI N G AUTOMATION connections. Cameras capture images of the location and orientation of the bolts and other equipment; a control system then analyzes these images and other sen- sor information and communicates with the robotic arms to ensure that factors such as position and rotational angle are correct before the robots place and torque the bolts. The robots can also perform other tasks, such as installing or removing a hole cover or filling hydraulic lines. Robotic arms like these are more com- monly used in controlled environments, such as manufacturing plants, not the harsh, dynamic conditions of an offshore drilling rig. The design team incorporat- ed adaptive control software to help the robots perform consistently even when wind or waves affect the motion of the drillship and riser, for example. The robotic system is integrated with the rig’s restricted zone access manage- ment system to ensure people stay away from the robots, which will stop if a person gets too close. There is also a direct link “You’ve got something like this that completely changes how you’ve ever done anything before – put big yellow robots out on the rig floor. And once you take that step, you start to think, what else is possible?” - Travis McGuire, Transocean back to onshore operations assurance pro- cesses, which continuously monitor how activities are running on the rig. Next step in offshore automation The introduction of the robotic riser system has been a positive experience for Transocean and has stimulated idea creation for other potential automation applications, Mr McGuire said. “You’ve got something like this that completely changes how you’ve ever done anything before – put big yellow robots out on the rig floor. And once you take that step, you start to think, what else is possible? How can we use these things to leverage other ideas?” What about the common concern that automation is going to displace traditional rig jobs? “I don’t think we’re near that point right now,” Mr McGuire said. Looking at all of the processes that a drilling operation entails, there are so many small activities that could be automated, but “somebody’s going to be there to be a part of that pro- cess.” DC Mastering Well Control Challenges: Where Advanced Engineering Ensures Safe Solutions Wild Well Control is at the forefront of cutting-edge engineering and well control services within the oil and gas industry. Prioritizing safety and ingenuity, our experienced professionals promptly handle wellbore complications, demonstrating expertise in intricate situations. Our distinguished rapid response encompasses sealing maneuvers in the harshest of circumstances. Moving beyond conventional drilling, Wild Well's skilled engineering unit partners with clients to reinstate standard drilling conditions. Our proficient well control staff guarantees the secure management of well control occurrences, drawing upon extensive proficiency in both established and innovative methodologies. Contact us for all your well control needs. Contact / WILDWELL.COM us for all your well control needs. | +1 281.784.4700 / WILDWELL.COM +1 281.784.4700 DRILLING MARKETS & LEADERSHIP Valaris CEO: No matter how industry evolves, people remain at center of the drilling business People-driven service delivery remains the company’s key to success even as it ramps up investments in AI, robotics and sustainbility BY LINDA HSIEH, EDITOR & PUBLISHER This year, Valaris is celebrating its 100- year anniversary. It was in 1923 that Charles Rowan and his brother, Arch, pur- chased their first land rig to drill near Corsicana, Texas. Together, the brothers would form Rowan Drilling, which ulti- mately merged with Ensco in 2019 to form what is now Valaris. Through M&As over the years, the two companies built a rich heritage encom- passing a multitude of other drilling busi- nesses, like Pride, Atwood, Dual Drilling, Penrod, Forasol Foramer, Marine Drilling, Skeie Drilling, and even non-drilling busi- nesses like LeTourneau, an equipment manufacturer, and Era Aviation, a com- mercial airline company. In recognition of this milestone, DC recently spoke with Anton Dibowitz, who joined Valaris as President and CEO in December 2021. How do you think Valaris has evolved over the past century? Like a lot of other offshore drillers, we started as a US-centric onshore drilling company. As technology evolved, we start- ed drilling in shallow water in the Gulf of Mexico, before going deeper offshore and expanding internationally. Our operations now span six continents, and our fleet con- sists of 11 drillships, five semisubmersibles and 35 jackups, as well as two managed deepwater units. We’ve come a long way. In that time, technology has obviously changed massively. Just in the 25 years since I joined the industry, there have been huge changes in the way we drill, the tech- nologies we use to drill and the efficiency with which we drill. In more recent years, one of the ways we’ve really evolved as a drilling con- tractor is the extent to which we partner with operators. We’re no longer just taking instructions to drill the well – we’re also bringing our expertise to the table much earlier in the process. There’s now a huge amount of integration between us and the customer, which helps us to be more effi- cient and, in turn, helps our customers to be more efficient. If you think about a dual-activity drill- ship, the efficiency comes from “feeding the beast,” if you will. What I mean is, you can have highly sophisticated equip- ment on the rig, but the logistics need to be there, the people need to be there, the supply chain needs to be there, and third- party service companies need to be there. By getting into the process a lot earlier and acting as a problem solver for our custom- ers, we’ve really achieved a step change in the efficiency of our drilling operations. Is there anything that you feel hasn’t changed during the past 100 years? People have always been at the center of our business, and they continue to be. How our people interface with technol- ogy and equipment, as well as the safety systems that our people use, have evolved tremendously, but our fundamental focus on people has not changed. For example, a few years ago we start- ed our BOLD program, which stands for Building Organizational Leadership Development. It’s about having open con- versations about safety and being trans- parent on near-misses. While the drilling business is a capital- intensive business, ultimately this is a service business. We deliver service to customers with capital-intensive assets, but at the end of the day, it’s the people who make the difference. Even the most highly sophisticated ultra-deepwater drillships today still need well- trained and competent crews to deliver a successful operation, said Anton Dibow- itz, Valaris President and CEO. That won’t change even with automation. 40 How do you see Valaris evolving over the coming years? SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR IADC DRILLING MIDDLE EAST Conference & Exhibition 14-15 NOVEMBER 2023 L E A L M É R I D I E N K H O B A R , A L S A U D I K H O BA R A R A B I A PLATINUM SPONSORS DIAMOND SPONSOR GOLD SPONSORS SILVER SPONSORS EVENT SPONSORS www.iadc.org/event/middle-east-2023 For more information, contact IADC by phone at +31.24.675.2252 or via email at europe@iadc.org DRILLING MARKETS & LEADERSHIP want to use technology to help people do their jobs more efficiently and more safely. What are some ways in which you see the energy transition changing either Valaris or the wider drilling industry in the coming years? The Valaris DS-12 drillship was the first vessel in the world to receive the ABS En- hanced Electrical System Notation EHS-E in 2021. Valaris says it will continue to in- vest in rig equipment upgrades as part of efforts to reach its goal to reduce the company’s Scope 1 emissions intensity by 10-20% by 2030. First, there are still great opportunities for the use of technology. We’ve deployed the Valaris Intelligence Platform (VIP), which collects data on the rig and uses machine learning, positioning ourselves for more advanced AI solutions. By uti- lizing data that historically wasn’t being used, the system is alerting us to potential issues, either with the wellbore or with rig equipment, which we can address early on before they become major problems. We’re continuing to progress our ability to assess data from multiple sources on a real-time basis. It’s going to allow us to go beyond human capability to drive real- time decision making on the rig. Another way in which we’re using AI is for red zone management, by keeping people away from large, moving equip- ment and potential dropped objects. With this type of technology, ultimately, we won’t need to have our people avoiding equipment; we will be able to make our equipment smart enough that they will avoid people. That’s where we’re headed. We’re also doing a lot of work with automation. On our DS-17 drillship, which is starting up operations for Equinor in Brazil’s Bacalhau region, we just installed 42 the ATOM RTX system from NOV. These are robotic arms on the drill floor that can perform a variety of tasks, such as transferring pipe stands to and from the well center, auto doping, etc. In our case, per the contract requirements, these are going to be used for automatic doping of the drill pipes. The system has been used onshore, but this is the first application on a rig floor offshore. We’re starting by using these arms for simpler tasks like pipe doping, but there is great potential for them to take on other activities, which will help us keep crews out of harm’s way while also driving consistency in our operations. How have those robotic arms been received by the rig crews? I think they’re quite happy about it. Look, there’s always something else that a crew can do. If we can take a repetitive task off their hands so they have 5-10 extra minutes to plan the next job, that’s a good thing. We have to remember that technology is a facilitator for people. Like I said earlier, people are the heart of our operations. We First, I want to make it clear that drill- ing contractors and drilling rigs will be needed for multiple decades to come, even under the most aggressive scenarios for the energy transition. It’s overly simplis- tic to think you can just flip a switch to renewables. This needs to be a managed process, and we need to consider what would be the cost to the world of not hav- ing reliable and affordable energy. Of course, drilling contractors will have to evolve as the energy transition contin- ues. Maybe in the future we’ll be drilling more gas wells instead of oil wells, more carbon capture, utilization and storage (CCUS) wells, or even offshore geothermal wells. We’ll also need to continue investing in our operations and equipment to lower our overall carbon footprint. At Valaris, we’ve set a goal to reduce our Scope 1 emissions intensity by 10-20% by 2030, compared with a 2019 baseline. I believe that is a credible target range that we can achieve with existing technologies. For example, I mentioned that we’ve launched the VIP platform to optimize our rigs’ power generation. Another example is the VALARIS DS-12 drillship, which was the first vessel in the world to receive the ABS Enhanced Electrical System Notation EHS-E back in 2021, recognizing the rig’s upgraded electrical system to optimize its power plant performance. The result is fewer generators used and, therefore, reduced emissions. So far we’ve seen a reduction in the order of 5-7%, which is a good start. We’ve also done the same upgrade on the DS-17 drillship that’s starting up operations in Brazil. We’re also looking at upgrades that allow for the electrification of jackups and enable floaters to use biofuels. Both options hold great potential to reduce emissions. However, there are challenges around access and infrastructure. On top of that, there is also a cost component to SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR DRILLING MARKETS & LEADERSHIP doing these types of upgrades, which is something where we need the operator’s support. In today’s market and with higher inter- est rates, the cost of capital is meaning- fully higher. Reducing emissions intensity is very important to us, as well as to our customers, and we want to do our part in helping them to provide responsible energy to the world, but we have to be very disciplined about where we allocate our capital. How do you see that difficulty in accessing capital impacting drilling contractors now and in the future? I think it’s clear that we’ll need to man- age this business differently than how it was managed before. Companies will have to be much more disciplined about manag- ing their balance sheets, which means not speculatively building new rigs and not speculatively reactivating rigs. Overall, we have to be much more thoughtful about bringing assets to the market. Generally across the industry, that’s exactly what we’re seeing so far. For our own part, Valaris has said that we won’t reactivate a rig unless we can generate a meaningful return on the reactivation cost, and that’s what we’ve done. Can you talk about Valaris’ joint ven- ture with Saudi Aramco, ARO Drilling? What is your outlook for the drilling market in Saudi Arabia, and what is allowing such a large newbuild pro- gram there? ARO Drilling has stated that it’s committed to building 20 new jackups over a 10-year period. Saudi Aramco is the world’s largest user of jackups in the world, and the Saudi mar- ket for high-spec jackups continues to be incredibly attractive. Their newbuild program is focused as much on fostering local content in the Kingdom as it is on security of rig sup- ply. The first two rigs of the ARO 20-rig program, which are expected to be deliv- ered before year-end, are being built in the United Arab Emirates, but the next 18 are going to be built at the International Maritime Industries’ yard in Ras Al Khair in the Kingdom. That’s going to be the world’s Valaris recently started deploying NOV’s ATOM RTX system in Brazil. The system uses robotic arms to perform a variety of tasks on the drill floor. second-largest rig yard when it’s completed and will contribute toward supporting local jobs and the building of local capabilities. Each newbuild will also be built against 16 years of contract term – you just don’t see that anywhere else in the world. Economically speaking, these rig projects not only make sense but are highly attrac- tive. It’s definitely exciting for Valaris to be able to partake in the amazing growth story going on there. DC Video Training Courses The IADC Bookstore now offers various options for corporate licensing of video training courses, resulting from the expansion of IADC’s long-standing partnership with Moxie Media. See the newly updated video training content here: store.iadc.org/ product-category/ education-training/ video-training-courses Phone: +1-713-292-1945 bookstore@iadc.org IADC TECHNICAL RESOURCES PRACTICAL TOOLS TO ENHANCE EXPERTISE Copyright © 2023 International Association of Drilling Contractors DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 43 IADC CONNECTION • EDITORIAL Industry continues to tap into limitless potential of technology FROM THE PRESIDENT Technology is a powerful and dynamic resource. It enhances almost every aspect of our lives, from communication to healthcare to transportation. People are constantly finding innovative applications for different kinds of technologies. We’ve entered an era where technology that can teach itself is widely accessible to the general public. Thanks to advances in arti- ficial intelligence (AI), we can now have an informative, human-like conversation with language-processing chatbots. The benefits of technology are seeping into just about everything we do, and drill- ing a well is no exception. Digitalization in well planning and rig operations has been steadily increasing in recent years, with meaningful advancements in auto- mation, robotics, AI and machine learn- ing. Employing these technical resources allows us to enhance safety on the rig while increasing efficiency and prioritiz- ing sustainability in innovative ways. Over the years, our industry has accom- plished impressive and impactful techni- cal advances. One recent example, report- ed by DC in the July/August 2023 issue, is the collaboration among Transocean, HMH and Equinor to drill fully automated hole sections in Norway. The use of “smart modules” not only reduced the potential for human error but also gave drillers more time to focus on other tasks, like red zone management. (Also see link to video with Transocean and HMH on Page 13). Earlier this year, DC also reported on how NOV turned its vision of a personnel- free rig floor into reality. The ability to move the driller’s cabin to the ground was made possible through automation and robotics and opens up a new world of pos- sibilities in terms of future rig design. AI and machine learning have also enhanced the use of alerts to deal with potential operational or safety threats. An excellent example is Patterson-UTI’s Rules Engine Exchange (REX), a cloud-based alert system for monitoring equipment and maximizing performance. As DC reported 44 in the July/August issue, Patterson-UTI is now building infrastructure for the REX system to run directly on the rigs instead of through the cloud system, shortening the time it takes to process data and get alerts out to the rig crews. These are just a few recent examples of how the drilling industry is harnessing the potential of technology. In reality, our industry has designed and implemented countless notable technological advance- ments over the years. Yet when the average person thinks of the drilling industry, do they think about how technical and progressive it is? Perhaps even more importantly, do the up- and-coming bright minds deciding on their future careers know? Are they aware of the industry’s increasingly diversified uses of robotics due to advances in AI, cloud com- puting and the Internet of Things? Or how about the immense amounts of real-time data collected through computer vision and equipment sensors? Or the use of 3D modeling to create realistic visuals of drill- ing processes and the subsurface? (See DC’s report on digital drilling engineering on p14). If you’re thinking the answer is “prob- ably not,” you’re correct. IADC partnered with Brunswick Group this year on the Industry Value Initiative to help us gain a baseline understanding of perceptions of the industry, including misunderstand- ings and opportunities among prospec- tive drilling industry employees. The data showed that the industry’s perception issues are apparent when asking audienc- es to describe the drilling industry – “high paying,” “profitable,” “risky,” “global” and “polluting” were in the top descriptive atti- tudes, while “safe” and “sustainable” were seen as not descriptive. “Technical” and “technology” were also not top of mind. But don’t worry, there’s some good news. While the research showed that interest in a drilling career was low among the groups surveyed, it also showed a sig- nificant increase in career interest after Jason McFarland, IADC President exposure to tested messaging. That means the more familiar people are with the industry, the greater their interest in a career in drilling. General awareness of the industry is modest, which suggests an opportunity to grow familiarity across all regions and audiences. How do we grow that familiarity? The surveys revealed that when individuals are interested in learn- ing more about the drilling industry as a potential career, family and friends with industry experience are two of the most trusted sources of information. This data also revealed that messaging around how the industry uses various technologies can contribute to attracting new talent. Job security, skill development and growth opportunities were all high priorities for these groups while seeking a new job or career. As the drilling industry continues to develop new technologies, the roles of the rig crew will change – but we will always need people. Through the introduction of new automation and digi- talization systems, there lies an opportu- nity for the potential of skill development, career growth and job security for those already working in the industry and for those who decide to join us in the future. There’s more to come out of IADC’s Industry Value Initiative and the data that has been gathered. There’s also much more to come as we stand on the precipice of what’s possible in terms of automation on the rig and in the wellbore. In addition to safety, efficiency and sustainability, these technical advancements can also help us attract the next generation of talent. Each of us can impact how others, including potential new-hires, perceive the indus- try. It’s within our power to introduce the world to the drilling industry we all know and love. DC SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR NEWS CUTTINGS • DEPARTMENTS » IADC DrillingIn video series features wellbore hydraulics, hole cleaning book As part of the IADC Technical Publications Committee's DrillingIn book review series, Chairman Fred Growcock interviewed author Mark S. Ramsey in July about his book, "Practical Wellbore Hydraulics and Hole Cleaning." The book presents explanations, equations and descriptions important for wellbore hydraulics, including hole cleaning. Topics such as the impact of temperature and pressure of fluid properties are covered. bit.ly/45qEBVE Author Mark S. Ramsey (left) discussed his book with Fred Growcock, Chair of the IADC Technical Publications Committee, in a new video podcast. The book can be purchased through the IADC Bookstore at https://store.iadc.org. IADC welcomes Ghanaian delegation to Houston HQ On 11 July, a delegation of representatives from Ghana's Takoradi Technical University (TTU) visited IADC's Houston headquarters to learn more about the association's accreditation programs and the student chapter program. Pic- tured, from left, are Mike DuBose, IADC; Reverend Professor John Frank Eshun, Vice Chancellor, TTU; Brooke Polk, IADC; John Bentil, TTU Dean of Engineering; and Kwame Acheampong, President of Ghantex. PDEU student chapter hosts career development webinar On 15 July, the IADC Student Chapter at Pandit Deendayal Energy University (PDEU) hosted a webinar, “Campus to Corporate: Evolution of Mindsets.” During the webinar, Reddimi Sai Sampath Reddy, Flow Assurance Engineer at Wood, shared his insights and experi- ences on transitioning from academic life and developing the skills and mind- sets required for success in the corporate world. Mr Reddy discussed the importance of a clear vision and goal for career and personal growth, as well as the value of networking in building a professional brand and reputation. IADC releases new training program for H 2 S management in drilling IADC is introducing a new training pro- gram, H 2 S Safe, geared toward individuals who have the potential to be exposed to H 2 S or an H 2 S environment. H 2 S (hydrogen sulfide) is a highly toxic and extremely flammable gas that can be encountered during drilling operations. The program, which took more than a year to create, aims to satisfy an industry need for a drilling-specific H 2 S training standard. It consists of a core curricu- lum and H 2 S Safe Plus, an optional add- on supplement. Four classroom hours are required for teaching the H 2 S Safe cur- riculum. An additional classroom hour is required if adding H 2 S Safe Plus. Course length for the program excludes the knowledge assessment time. Instructor-led training (both in person and virtually) for the initial and repeat delivery of this course is required. Skill demonstra- tion and knowledge are both incorporated into the course content. The program meets and exceeds the ANSI standard as it pertains to drilling. DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 Scan me to learn more about the H 2 S Safe program. bit.ly/444VNix 45 IADC CONNECTION • WIRELINES US Department of Labor expands requirements to submit injury and illness data The US Department of Labor announced a final rule that will require certain employ- ers in designated high-hazard industries to electronically submit injury and illness information to the Occupational Safety and Health Administration (OSHA). The final rule will take effect on 1 January 2024 and includes the following submission requirements: Establishments with 100 or more employees in certain high-hazard indus- tries must electronically submit informa- tion from their Form 300-Log of Work- Related Injuries and Illnesses, and Form 301-Injury and Illness Incident Report to OSHA once a year. These submissions are in addition to the submission of Form 300A-Summary of Work-Related Injuries and Illnesses. ■ Establishments are required to include their legal company name when making electronic submissions to OSHA from their injury and illness records. OSHA will publish some of the data col- lected on its website to allow employers, employees, potential employees, employee BOEM proposes new requirements for offshore decom The US Bureau of Ocean Energy Management (BOEM) has proposed changes to modernize financial assur- ance requirements for the offshore oil and gas industry, covering the costs associated with the decommissioning of offshore wells and infrastructure. The proposed rule would establish two metrics by which BOEM would assess the financial risk. First, the bureau would use credit ratings from a nationally rec- ognized statistical rating organization, or a proxy credit rating generated through a statistical model. BOEM would require companies without an investment-grade credit rating to provide additional finan- cial assurance. Second, BOEM would consider the current value of the proved oil and gas resources on the lease itself when determining the overall financial risk of decommissioning, given that any lease with significant reserves still available would likely be acquired by another operator, which would then assume the liabilities in the event of bankruptcy. The bureau said in a statement that the proposed regulatory changes would “provide additional clarity and reinforce that current grant holders and lessees bear the cost of ensuring compliance with lease obligations, rather than rely- ing on prior owners to cover those costs.” Scan me to read the BOEM’s proposed requirements. bit.ly/3Qv9h45 North Sea database adds application to drill CO 2 wells The UK North Sea Transition Authority (NSTA) launched a revamped version of the Wells Operations Notifications System (WONS) in July. Among the changes is a new function that allows companies to apply to drill a wellbore specifically linked to a carbon storage license. The system has also made it a higher priority to consider reusing or repurpos- ing wells as part of the decommission- ing process, with system amendments allowing the NSTA to gather more accu- rate information on final well abandon- ment. There are more than 12,500 well- 46 bores in the UK North Sea, with around 5,500 wells plugged and abandoned. Further, the system now allows users to record more detailed information on the identity and role of companies responsible for the wellbore. The WONS was originally launched in 2002. Scan me to access the NSTA’s Wells Operations Notification System. bit.ly/3Qwhfdj representatives, current and potential cus- tomers, researchers and the general pub- lic to use information about a company’s workplace safety and health record to make informed decisions. The final rule retains the current requirements for electronic submission of information from Form 300A from establishments with 20-249 employees in certain high-hazard industries and from establishments with 250 or more employ- ees in industries that must routinely keep OSHA injury and illness records. IADC comments on BLM leasing recommendations On 24 July, the US Department of the Interior’s Bureau of Land Management (BLM) published recommended revisions to the Onshore Oil and Gas Leasing Rule. The proposed changes would impact the BLM’s oil and gas leasing regulatory framework by modifying current fiscal terms and leasing processes. If put into effect, the proposed modifi- cations would make oil and natural gas exploration more expensive. Royalty rates for drilling on public lands would increase from 12.5% to 16.67%, as per provisions in last year’s climate and tax reconciliation law. The rule also proposed increasing the minimum lease bond amount from $10,000 to $150,000. While IADC respects the BLM’s efforts in modernizing its regulatory framework and preserving public lands, these changes would increase the economic and logisti- cal obstacles involved in developing new energy projects. Domestic oil and natu- ral gas supply may diminish as a result, decreasing the ability of the US to meet national and global demand. In response to the proposal, IADC President Jason McFarland said in a state- ment issued on 27 July, “The increased costs to drilling contractors is an obvious detriment to oil and natural gas explora- tion and will affect our members unfavor- ably. As a voice for the drilling industry, IADC looks forward to collaborating with industry stakeholders in providing feed- back to BLM in order to seek balance in how this ruling is developed.” SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR UPCOMING IADC EVENTS • IADC CONNECTION IADC/SPE MANAGED PRESSURE DRILLING & UNDERBALANCED OPERATIONS IADC Annual General MEETING MEETING Conference & Exhibition 3-4 OCTOBER 2023 G R A N D H YAT T D E NVE R D E N V E R , C O L O R A D O 8-10 NOVEMBER 2023 H YAT T IADC DRILLING MIDDLE EAST REG ENCY A U S T I N , AUSTIN T E X A S 6-7 FEBRUARY 2024 NORRIS CONFERENCE CENTER, CITYCENTRE H O USTO N , TE X AS Conference & Exhibition IADC HEALTH SAFETY ENVIRONMENT & TRAINING Conference & Exhibition 14-15 NOVEMBER 2023 LE A L MÉRIDIEN K H O B A R , AL S A U D I KHOBAR A R A B I A IADC DRILLING CASPIAN Conference & Exhibition IADC DRILLING AFRICA Conference & Exhibition 7- 8 F E B R U A R Y 2 0 24 F O U R S E AS O N S H OT E L B A K U , A Z E R B A I J A N 20-21 FEBRUARY 2024 HILTON W I N D H O E K , HOTEL N A M I B I A To register for these and other conferences please visit us online at www.iadc.org/conferences/upcoming. DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 47 IADC CONNECTION • DRILLING CONTRACTOR DON’T MISS OUT ON OUR NEXT ISSUE! EDITORIAL PREVIEW November/December 2024 Drilling Outlook Solids Control & Cuttings Management NOV Annual Rig Census IADC Year in Review: Safety, Regulations, Student Engagement AD CLOSING: 5 OCTOBER MATERIALS DUE: 12 OCTOBER OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS DRILLINGCONTRACTOR.ORG IADC.ORG DISTRIBUTION: IADC Annual General Meeting [8-10 NOVEMBER, AUSTIN, TEXAS] IADC Drilling Middle East Conference & Exhibition [14-15 NOVEMBER, AL KHOBAR, SAUDI ARABIA] News 48 Visit DrillingContractor.org for the latest drilling industry news and videos Odfjell Drilling confirms new rig contracts, enters partnership with Equinor Utica Resource Operating selects biosurfactant-based solution for multi-well completion program Noble drillship secures one-well options offshore Malaysia Velesto confirms contract with PTTEP for jackup Deepwater well stimulations completed in US Gulf using Trendsetter’s STIM Photo Gallery: DC attends IADC World Drilling in London SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR PEOPLE, COMPANIES & PRODUCTS • DE PAR TM E NTS Patterson-UTI acquires drill bit provider Ulterra Patterson-UTI Energy has com- pleted its acquisition of Ulterra Drilling Technologies. The transaction was first announced in July. In addition to a growing presence in the dynamic Middle East market, the bit pro- vider also has sales, manufacturing and repair facilities across North and South America and Asia. Further, Ulterra’s BitHub data platform complements Patterson-UTI’s PTEN+ data platform. “We believe the combination of data systems from Patterson-UTI, NexTier and Ulterra will create the most compre- hensive set of data for drilling and comple- tions in the United States,” said Andy Hendricks, Patterson-UTI CEO. Patterson-UTI’s merger with NexTier was announced in June and is expected to close before the end of 2023. ExxonMobil to boost CCS footprint with Denbury acquisition ExxonMobil entered into a definitive agreement to acquire Denbury in an all- stock transaction valued at $4.9 billion. The acquisition will provide ExxonMobil with the largest owned and operated CO 2 pipeline network in the US at 1,300 miles, including nearly 925 miles of CO 2 pipe- lines in Louisiana, Texas and Mississippi, as well as 10 strategically located onshore sequestration sites. In addition to Denbury’s carbon capture and storage assets, the acquisition includes Gulf Coast and Rocky Mountain oil and natural gas operations. The transaction is expected to close in Q4 2023. Semco Maritime nets contract from TotalEnergies in Denmark Semco Maritime was awarded a five- year contract for the provisioning of field support personnel for core crew and campaign positions from TotalEnergies Denmark. The contract began in July 2023 and covers offshore positions for production operators, permit coordinator assistants, HSE supervisors and labora- tory technicians. The two companies had also previously agreed to a construction service contract in November 2022. Shell to sell off interest in Indonesia’s Masela Block Shell has agreed to sell its 35% par- ticipating interest in Indonesia’s Masela Production Sharing Contract, which includes the Abadi gas project, to Indonesia’s PT Pertamina Hulu Energi and Petronas. The transaction is targeted to be completed in Q3 2023. BiSN alloy qualified for P&A, abandonment for Sasol BiSN worked with operator Sasol in Mozambique to qualify its Wel-lok tool for rigless P&A and intervention operations. The collaboration involved deploying the BiSN alloy via perforations in 95/8-in. cas- Petrobras invests in SLB digital platform for E&P SLB has been awarded a five-year contract by Petrobras for an enterprise- wide deployment of its Delfi digital platform. The contract scope covers Petrobras’ digital transformation from exploration, development and produc- tion operations, including moving subsurface workflows to the cloud to accelerate decision making. The award represents one of Petrobras’ largest investments to date in cloud-based technologies. GD Energy Products adds new Canadian facility GD Energy Products has expanded its Canadian reach with the opening of a sales, service and repair facility in Grande Prairie, Alberta. The new loca- tion will feature more than 11,000 sq ft of work space, including a dedicated pull-through wash bay and two pull- through service bays with a 10-ton crane. EnerMech wins five-year contract with TotalEnergies ing to isolate formation activity from a gas-bearing silt layer and create a suit- able regional seal within a 10-m thick shale interval. The project established the viability of the alloy to replace traditional cement. FET announces partnership with UnderOcean in Brazil Forum Energy Technologies (FET) appointed UnderOcean to represent its subsea operations in Brazil. The partner- ship will see UnderOcean provide business development and engineering support on behalf of FET’s Subsea Technologies prod- uct line. UnderOcean will also deliver ser- vices for FET’s remotely operated vehicles. Integrated solutions specialist EnerMech received a five-year con- tract by TotalEnergies EP Congo for crane and lifting maintenance at a new facility to be built at Pointe-Noire. The work scope also includes spe- cific maintenance of crane and lifting equipment, as well as onshore and offshore parts supply for three off- shore sectors. The agreement further includes riser pulling systems, moor- ing and tensioning systems. Chesapeake sells Eagle Ford acreage to SilverBow Chesapeake Energy sold off its remaining Eagle Ford assets to SilverBow Resources for $700 million, bringing the total proceeds from its Eagle Ford exit to more than $3.5 bil- lion. The sale incorporates approxi- mately 42,000 net acres and approxi- mately 540 wells in the condensate- rich portion of its Eagle Ford asset located in Dimmit and Webb counties. Chesapeake expects the transaction will close this year. DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 49 DE PAR TM E NTS • PEOPLE, COMPANIES & PRODUCTS Expro to deploy shear and seal solution in deepwater GOM field Expro has secured a contract with a major operator for the first deployment of its single shear and seal high-debris 15K ball valve assembly. The multifunctional single shear and seal mechanism will form part of a full subsea deepwater completion/interven- tion system being designed by Expro for a deepwater subsea field at about 6,600 ft (2,000 m) in the Gulf of Mexico. The mechanism is designed to answer the operator’s requirement for a single- valve subsea solution rather than the conventional double-valve system, while offering the reassurance of risk reduction through an additional safety barrier. Expro’s high-debris single ball system, which delivers shear and post-shear seal on a multitude of sizes of coiled tubing, slickline and electrical cable, is a solution for both gas and liquid. It is NACE MR0175 Expro’s single shear and seal high- debris 15K ball valve assembly will form part of a full subsea deepwater com- pletion/intervention system for a deep- water subsea field in the Gulf of Mexico. compliant and qualified for sour hydrogen sulfide environments. The mechanism has been qualified to API 17G standard for the performance and design of subsea well intervention equipment. AGR, Add Energy consolidate services under one brand Add Energy and AGR are combining their services in drilling, wells and reservoirs, as well as energy transi- tion technologies such as CCUS and geothermal, under the AGR brand. This move follows the recent acquisition of AGR and Add Energy by ABL Group. Add Energy’s asset integrity manage- ment division will not be consolidated into AGR. Separately, Add Energy was recent- ly awarded funding from the Ocean Energy Safety Institute (OESI) to devel- op a method to standardize blowout event consequence analysis to support consistent risk measurement of well control events. OESI awards funding for research projects that can improve safety and environmental sustainabil- ity of oil and gas operations. Products Mobile app introduced for real-time frac monitoring Intelligent Wellhead Systems (IWS) launched the inVision Mobile App for completions operations, which provides real-time access to key wellsite opera- tional data. The app allows users to inspect pad progress and current well activity. When running frac and wire- line data through IWS safety and effi- ciency controls, users can analyze frac and wireline plots remotely. New safety barrier designed for hazardous applications Pepperl+Fuchs’ KCD2-SCS-EX2 is a two-channel, dual-function analog input (AI)/analog output (AO) intrinsic safety barrier in a compact 12.5-mm housing. The two channels of the KCD2- SCS series interface modules can be configured individually for AI or AO control signals. They can also function as a power supply for SMART 2-wire transmitters. For AI signals, the control side can be operated either as a current source or current sink via selectable DIP switches on the front panel. 50 New packer offers economic option for isolation assurance Halliburton’s new Obex EcoLock is a compression-set packer that helps to pre- vent sustained casing pressure. The packer serves as a mechanical barrier to mitigate low-pressure gas or fluid migration and deliver isolation assurance. It can be a cost-effective alternative to inflatable and expandable packers for ensuring isolation assurance independent of losses or cir- culation pressures. The packer provides V6-rated isolation and can support multi- ple-stage cementing with optional integral cementing ports and an internal closing sleeve. It is currently available for 7-in. and 9 5/8-in casing designs. Halliburton’s Obex EcoLock casing annu- lus packer is designed to deliver isola- tion assurance independent of losses or circulation pressures. Completions and workover system targets subsea CCS sites Aquaterra Energy is offering a comple- tions and workover system that specifi- cally supports carbon capture and stor- age (CCS) developments. Deployable from jackups, semisubmersibles or light-weight intervention vessels, the system will allow operators to safely perform workover and intervention operations in low-tempera- ture and high-pressure CCS subsea sites without concerns of gas leakage. The patent-pending technology is designed to address issues that can occur when working with stored and pressur- ized CO 2 , – for example, sweet corrosion and ultra-low temperatures that standard low-alloy carbon steels cannot safely han- dle. The solution is based on Aquaterra’s ISO13628-7 completion and workover riser system, which incorporates the company’s proprietary AQC-CW connectors. SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR AD INDEX AADE Fluids 2024............................................53 Abaco Drilling Technologies..................54 ADIPEC...................................................................33 Burgess Manufacturing...............................5 Cortec Fluid Control..................DIGITAL, 19 DrillingContractor.org Virtual IADC Drilling Middle East 2023 Conference & Exhibition......................... 41 Nabors Drilling Solutions.............................11 Noble Corporation......................................... 51 NOV Wellbore Technologies................... 17 Oil States................................................................9 Panel Discussion............................................6 TSC Drill Pipe.....................................................29 EW Pumps...........................................................35 Weatherford.........................................................2 IADC Bookstore...............................................43 Wild Well Control...........................................39 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! 9,970+ Followers 30k+ Followers 5,365+ Followers 2.93K Subscribers 2,326,945+ Views DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023 51 DEPARTMENTS • PERSPECTIVES Barrett Zuskind, Z-Tex Services: Curiosity helps people make the most of opportunities BY STEPHEN WHITFIELD, ASSOCIATE EDITOR For much of his life, Barrett Zuskind has been driven by a curious nature, a sense of adventure, and a love of oil and gas. As a child, he spent summers on his grand- father’s ranch in Caldwell, Texas, hunting, fishing, wrangling cattle and doing odds- and-ends jobs. However, the one thing he enjoyed the most on the ranch was getting to visit the Desta Drilling land rig. His grandfather – who owned a pipeline company – started taking him up the rig floor when he was just 8 years old. He would get to meet with rig crews and watch in awe as the com- plex machinery that makes up a drilling rig worked in sync to make a hole in the ground. By the time he reached junior high school, he knew he wanted to learn as much about those rigs as he could. That curiosity has led Mr Zuskind to a career that’s spanned several sectors of oil and gas drilling, from casing and pres- sure control equipment sales to operations management and now, running an oilfield equipment sourcing and repair company. His jobs have required him to travel to near- ly every basin in the US, from the Bakken and the Eagle Ford all the way to Alaska. The willingness to take on new challenges as they come, he said, has been critical in helping him make his way through a changing industry. “If you want to really thrive, you have to know something that other people don’t. You can’t just sit there and only do what you’re told,” Mr Zuskind said. “It’s impor- tant to see and do as much as possible. If you get a chance to work with equipment 52 you’ve never worked with before, say yes. Volunteer to work in different areas. You never know what’s going to be critical.” While studying petroleum engineering at the University of Oklahoma from 2007-2011, Mr Zuskind spent his summers intern- ing wherever he could. One summer was spent working as a floorhand on an H&P FlexRig in the Eagle Ford, another summer was spent working on MWD equipment for Baker Hughes, and during a third sum- mer he served as a production engineering intern for a small operator in Oklahoma. By the time he entered his senior year of college, he already had several full-time job offers from drillers, operators and service companies. He ended up deciding to join Unit Drilling as an operations engineer, under the prom- ise that he “would not be stuck in a cubicle.” He quickly worked his way up to Gulf Coast Engineering and Sales Manager. Working primarily in East Texas and Louisiana, he served as the point person for rig upgrades and for negotiating daywork contracts with operators. The experience of finding work for Unit’s rigs, he said, was a delicate bal- ancing act. “It’s a big numbers game,” he recalled. “You have to look at dayrates, when you can plan a rig move if you have to move it, and what region you’re looking to work in. Some operators may have windows where they want to drill two or three wells, or they might want a six-month drilling window. You’re trying to balance everything so that you can keep all of your rigs running.” After spending three years with Unit, Mr Zuskind built up his experience working for several oilfield service companies and NorAm Drilling, a Permian-area drilling company. This gave him the chance not only to see different rigs working in dif- ferent areas like the Bakken, Marcellus, Permian, DJ Basin and Alaska, but also to engage directly with drilling engineers and rig crews. In 2020, motivated both by a nagging feeling that he needed to do more with his career and by the pandemic-induced industry downturn, Mr Zuskind decided to go into business for himself. That year, he founded Z-Tex Services, a consultancy that sources and refurbishes aftermarket rig equipment for drillers and operators, mainly in West Texas. Barrett Zuskind, Vice Chairman of the IADC Permian Chapter, said the chapter is actively focused on building member engagement through sponsored net- working events and a program recog- nizing short-service employees. “At the time, I saw that a lot of companies were good at handling their own one or two pieces of equipment, but I didn’t see any companies that were good at everything,” he said. “So I formulated this plan to be a one-stop shop for drillers. If you had a leaking cylinder, call Barrett. If your BOP needs a recertification, call Barrett. If you need a mud pump overhauled, call Barrett. It took some time, but we’ve grown a cus- tomer base that now really understands and enjoys the concept.” Mr Zuskind first got involved with IADC in 2011 while he was at Unit Drilling, simply as a means to network with other people in the industry. More recently, he’s stepped up his involvement, particularly through the newly reinvigorated IADC Permian Chapter, serving as Events Chair in 2022 and as Vice Chairman this year. The chapter has been focusing on build- ing member engagement by providing sponsored networking opportunities, like hosting its first Permian Basin Regional Forum last year, as well as its annual golf tournament. This year, the chapter also created a Rewards and Recognition Committee, which has launched a pro- gram to recognize short-service employees (SSEs) working in the Permian who show outstanding dedication to their employer’s HSE policies. Winners of the SSE Employee of the Month award then receive a $1,000 check from the chapter. DC SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR A M E R I C A N A S S O C I A T I O N O F D R I L L I N G E N G I N E E R S FLUIDS S 2 0 2 4 FLUID April 16-17, 2024 | Marriott Marquis | Houston, Texas THE PREMIER TECHNICAL CONFERENCE AND EXHIBITION The future is fluid~ CALL FOR ABSTRACTS ! “The future is fluid. Each act, each SUGGESTED TOPICS: decision, and each development Automation Case Histories creates new possibilities and eliminates others. The future is ours to direct.” - Jacque Fresco Discover new possibilities. Converse with your industry peers at the 2024 premier fluids conference. Share your technical knowledge and expertise on fluids for Drilling, Completion, Cementing and Fracturing. Submit an abstract related to one of our diverse set of technical topics for consideration. Detailed abstract guidelines and submission information can be found at: www.aade.org Cementing and Zonal Isolation Completion Fluids & Spacers Corrosion Data & Analytics Deepwater Digital Transformation Digital Solutions Displacements Drill-In Fluids Drilling Fluids Emerging Technologies Environmental Initiatives ESG Fluids for Extreme Conditions Fracturing Fluids Geothermal Fluids Gravel Pack Fluids Hole Cleaning Hydraulics and Rheology Lost Circulation Openhole Completions Regulatory Compliance Recycling and Reuse of Fluids Solids Control Technologies Sustainable Initiatives for Fluids Test Equipment and Procedures Underground Storage Waste Management Wellbore Integrity Wellbore Stabilization September 30, 2023 Abstracts will be due October 20, 2023 Authors notified of acceptance February 16, 2024 Papers will be due March 15, 2024 Slide presentations will be due STUDENTS Students in good standing with their academic departments are invited to submit a maximum 250-word abstract on a non-commercial topic of interest at www.aade.org using the link for Student Poster and Presentation Contest. December 31, 2023 Student abstracts will be due Those students selected to participate in the poster and presentation competition will be notified of acceptance by January 15, 2024 A ADE AMERICAN ASSOCIATION of DRILLING ENGINEERS