LOW-CARBON DRILLING SOLUTIONS Emission-reducing technologies moving from concept to reality at the rig site – p14 MAY/JUNE 2022 Offshore medics shoulder increasing burdens Official magazine of the International Association of Drilling Contractors www.drillingcontractor.org www.iadc.org Industry may need to consider better support for health professionals facing staggering workloads on drilling rigs – p20 Volume 78 • Number 3 Optimism builds for strong offshore recovery Stable oil prices and governments’ renewed focus on energy security could lead to higher investments in offshore E&P – p30 Tip the Scales in Your Favor You might think that you can’t get high performance from water-based fluids, that they negatively impact your well economics, or that there really isn’t a well-developed, balanced approach between performance, sustainability, and economics. Well, M-I SWACO has developed one of the most complete portfolios of aqueous fluid solutions that not only deliver sustainability but competitive performance in drilling and drill-in reservoir drilling fluids and also include advanced digital management and automation. Aqueous fluid solutions—water-based drilling fluids that are more than just water. slb.com/AFS Copyright © 2022 Schlumberger. All rights reserved. 22-WCFL-1260840 TAB LE OF CONTE NTS Official magazine of the International Association of Drilling Contractors MAY/JUNE 2022 Volume 78 • Number 3 drillingcontractor.org iadc.org After six years of development, COSL Drilling Europe’s Energy Control System has been installed on three of its rigs working in the North Sea. Read our feature on low-carbon drilling solutions starting on Page 14. Image courtesy of COSL Drilling Europe. LOW-CARBON DRILLING SOLUTIONS 14 Low-carbon technologies moving from concept to reality at the rig site Industry continues to develop new ways to reduce emissions, not only through engines but also drilling waste, hydraulic ring line BY STEPHEN WHITFIELD, ASSOCIATE EDITOR H E A LT H , SA F E T Y, E N V I R O N M E N T & T R A I N I N G 20 Offshore medics shoulder increasing burdens amid heightened focus on health Industry may need to better support health professionals as pandemic-related testing/documentation and increased needs around rig crews’ mental wellbeing lead to staggering workloads BY STEPHEN FORRESTER, CONTRIBUTOR UNCONVENTIONAL DRILLING 25 Chesapeake drills U-turn lateral to optimize tight lease space BY JESSICA WHITESIDE, CONTRIBUTOR 25 28 Automated geosteering algorithm shows promising ability to match human geological interpretations BY JESSICA WHITESIDE, CONTRIBUTOR OFFSHORE TECHNOLOGIES & MARKETS 30 Higher oil prices foster optimism for recovery in offshore drilling market Industry is hopeful that investments in offshore E&P will grow as geopolitical events put new spotlight on energy security BY STEPHEN WHITFIELD, ASSOCIATE EDITOR D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 3 TAB LE OF CONTE NTS OFFSHORE TECHNOLOGIES & MARKETS 35 Case study: Chevron deploys below-tension-ring MPD to drill highly depleted reservoir in GOM BY JESSICA WHITESIDE, CONTRIBUTOR OPTIMIZING WELL INTERVENTION 38 Software applies real-time data, automation to redefine wireline sleeve shifting operations BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 42 Real-time force monitoring improves CT drillout efficiency BY JESSICA STUMP, TRAVIS THOMAS AND COLT ABLES, NOV IADC CONNECTION 44 From the Chairman: To propel itself forward, drilling industry must look to technical innovations BY JEREMY THIGPEN, IADC CHAIRMAN 46 Wirelines 47 Conference Calendar 48 Editorial Preview 45 News Cuttings DEPARTMENTS 6 Drilling Ahead: SEC proposes sweeping rules on climate-related risk disclosures BY LINDA HSIEH, EDITOR & PUBLISHER 7 D&C News 9 D&C Tech Digest 10 News Briefs: Environmental, Social and 12 37 49 51 52 Governance Oil & Gas Markets D&C Videos People, Companies & Products Advertisers Index Perspectives: Jamie Elrod, Baker Hughes – Industry must continue working to improve gender diversity within its ranks BY STEPHEN WHITFIELD, ASSOCIATE EDITOR MAY/JUNE 2022 Volume 78 • Number 3 Drilling Contractor (ISSN 0046-0702), the official magazine of the International Association of Drilling Contractors (IADC), is issued six times per year. DC is a wholly owned publication of IADC, which is also the publisher of the annual IADC Membership Directory. Drilling Contractor strives to ensure that the articles and information it publishes are accurate and reliable. However, DC cannot warranty the information provided in its editorial content, and publication in DC is not a guarantee that the material presented is accurate. DC wants to hear from its readers. Send your comments or inquiries to editor@iadc.org or Attn: Editor, Drilling Contractor Magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042 (please include your name, plus an email or phone number). We hope you will enjoy and benefit from DC’s editorial. However, should you wish to 4 complain, please contact the publisher. Our complaint policy is posted at www.drillingcontractor.org. Subscriptions are free to operational personnel employed by contract-drilling firms or by major, national or independent oil companies. Publisher reserves the right to refuse non-qualified subscriptions. Paid subscriptions are available at $210 per year, US; $280, outside the US. Single issues are $36. For advertising rates or information, call Drilling Contractor at +1-713-292-1945 or check our website at www.drillingcontractor.org. Postmaster: Please send address changes to Drilling Contractor magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042. © 2022 Drilling Contractor. All rights reserved. Printed in the USA. PUBLISHED BY IADC OFFICERS IADC 3657 Briarpark Drive Suite 200 Houston, Texas 77042 USA Chairman Jeremy Thigpen Phone: +1 713 292 1945 drilling.contractor@iadc.org www.drillingcontractor.org EDITORIAL STAFF Vice President, Editor & Publisher Linda Hsieh Vice Chairman William Andrew “Andy” Hendricks Secretary-Treasurer Scott McReaken Division VP North America Onshore Mike Garvin Creative Director Brian C. Parks Division VP International Onshore Miguel Sanchez Associate Editor Stephen Whitfield Division VP Offshore Brian Woodward Contributors Stephen Forrester Jessica Whiteside Division VP Drilling Services Robin Macmillan President Jason McFarland A full list of IADC staff is available here: www.iadc.org/about/staff M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R IADC IADC Advanced Rig Technology CONFERENCE & & EXHIBITION EXHIBITION CONFERENCE SILVER SPONSORS 30-31 AUGUST 2022 HYATT REGENCY AUSTIN HOTEL AUSTIN, TEXAS EVENT SPONSOR www.iadc.org/event/iadc-art-2022 For more information contact IADC by phone at +1.713.292.1945 or via email at iadcconferences@iadc.org DEPARTMENTS • DRILLING AHEAD SEC proposes sweeping rules on climate-related risk disclosures BY LINDA HSIEH, EDITOR & PUBLISHER New Professional Membership Available to individuals who are sole proprietors • Maintain contact with a large, professional network • Continue participation in industry events and groups Benefits include: • Access to Member pricing for all conferences and technical publications • A digital listing in IADC’s Membership Directory Professional Membership is also available to recent graduates who were Members of an IADC Student Chapter! HELPING MEMBERS STAY CONNECTED www.iadc.org/membership/ become-a-member/#professional 6 We knew it was coming, but now it’s really on our doorstep : The US Securities and Exchange Commission (SEC) has finally announced its proposal to require com- panies to include climate-related disclo- sures as part of their audited financial statements. The required information also would include disclosure of a company’s greenhouse gas (GHG) emissions . In a statement, SEC Chair Gary Gensler said he believes the proposal would pro- vide investors with “consistent, compa- rable and decision-useful information for making their investment decisions, and it would provide consistent and clear report- ing obligations for issuers.” The goal, he said, is to ensure that climate-related risks are disclosed more efficiently and effec- tively to meet investor demand . The proposed changes would require a registrant to disclose information about: • The registrant’s governance of climate- related risks and relevant risk manage- ment processes; • How any climate-related risks identified by the registrant have had or are likely to have a material impact on its business and consolidated financial statements ; • How any identified climate-related risks have affected or are likely to affect the registrant’s strategy, business model and outlook; and • The impact of climate-related events and transition activities on the line items of a registrant’s consolidated financial statements . For registrants that have publicly set climate-related targets or goals, the pro- posed amendments also would require certain disclosures . Further, the proposed rules would require a registrant to disclose informa- tion about its direct GHG emissions (Scope 1) and indirect emissions from purchased electricity or other forms of energy (Scope 2). In addition, a registrant would be required to disclose GHG emissions from upstream and downstream activities in its value chain (Scope 3) . The SEC asserts that the proposed dis- closures are similar to those that many companies already provide based on dis- closure frameworks like the Task Force on Climate-Related Financial Disclosures and the Greenhouse Gas Protocol . What now? The SEC’s 500+ page proposal is already widely deemed to be not only far-reaching but also prescriptive . Obviously, it will require time for companies and industry groups like API and IADC to fully review and assess the changes being proposed before they can understand how compa- nies and industries will be impacted. On the other hand, it’s not hard to see the potential for unintended, negative con- sequences when a federal agency tries to implement such large-scale changes. “We are concerned that the Commission’s sweeping proposal could require non- material disclosures and create confusion for investors and capital markets,” API said in a statement issued on 21 March. “As the Commission pursues a final rule, we encourage them to collaborate with our industry and build on private-sec- tor efforts that are already under way to improve consistency and comparability of climate-related reporting.” The proposal is open for public com- ment through 21 May (or longer as indus- try groups like IADC request extensions), and it’s expected that there will be a flood of comments and perhaps even legal chal- lenges . While the proposal will likely undergo a multitude of changes before a final rule is in place, and even though it may be years before there’s an effective date for requiring the disclosures, the time to pay attention is now. DC M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R Scan me to view a Fact Sheet for the SEC’s proposed rule. bit.ly/3vr9k4H DRILLING & COMPLETION NEWS • DEPARTMENTS Zama unitization process is finalized in Mexico Talos Energy has received the final Unitization Resolution from Mexico’s Ministry of Energy regarding the Zama field . Among other things, the resolu- tion affirms the appointment of Pemex as operator of the unit. Unitization was required after determination that the field is located within both the Talos-operated Block 7 and an adjacent Pemex-operated block. It provides for joint development of the entire reservoir . Talos will maintain a 17.35% partici- pating interest in Zama , and the com- pany anticipates submitting a Unit Development Plan for approval by the working interest partners within six to 12 months, a critical step before the parties can make a final investment decision in 2023. New production starts up from PowerNap, Colibri Shell has announced the start of pro- duction at PowerNap, a subsea develop- ment in the US Gulf of Mexico with an estimated peak production of 20,000 bbl/ day of oil equivalent (BOED) . PowerNap is a tie-back to the Shell-operated Olympus production hub in the prolific Mars Corridor. “Shell has been producing in the Mars Corridor for more than 25 years, and we continue to find ways to unlock even more value there,” said Zoe Yujnovich, Shell Upstream Director. Separately, Shell – through subsidiary BG International – announced the start of production on Block 22 and NCMA-4 in the North Coast Marine Area (NCMA) in Trinidad and Tobago. The start-up of Colibri follows the amendment to the Block 6 production- sharing contract for the Manatee field . This will allow for the delivery of gas both domestically and internationally through Atlantic LNG. Project Colibri is a backfill project that is expected to add approximately 30,000 BOED of sustained near-term gas produc- tion, with peak production expected to be approximately 43,000 BOED through four subsea gas wells tied back to the existing Poinsettia Platform . While working for Shell, the Maersk Voyager drillship will deploy the RigFlow solution to help digitalize well construction workfl ows. Maersk Drilling announces multiple new contracts for 7th-gen drillship, 2 harsh-environment jackups Maersk Drilling has been awarded contracts with Shell for the provision of the seventh-generation drillship Maersk Voyager for drilling services offshore multiple countries. The contracts were expected to commence by April , with a total firm duration of one year. The total contract value is approximately $107.5 million, including a mobilization fee but excluding integrated services expected to be provided and potential performance bonuses. The contracts include an addi- tional one-year option. To support a strong operational per- formance in the campaigns, Maersk Drilling and Shell have agreed to imple- ment the RigFlow solution delivered by Maersk Drilling subsidiary Horizon56. RigFlow standardizes and digitalizes the core workflows involved in well con- struction, including real-time exchange of information between onshore plan- ning units, the offshore drilling teams, and the service companies supporting the operations. Separately, Maersk Drilling has been awarded a contract for the Maersk Resolve. The harsh-environment jackup rig will work for an operator in the UK sector of the North Sea starting in April , with an estimated duration of 150 days. The contract value is approximately $16.9 million, including mobilization and demobilization fees. The contract con- tains options to add additional work scopes with a total estimated duration of 85 days to the campaign. The Maersk Resolve had been warm- stacked in Esbjerg, Denmark, since com- pleting its previous contract in the UK North Sea in January 2022. Additionally, Maersk Drilling has been awarded contracts for the harsh-envi- ronment jackup rig Maersk Resolute. It will plug and abandon a total of 31 wells in the Dutch sector of the North Sea in support of a rig-sharing agreement between TotalEnergies and Petrogas . The contracts are expected to com- mence in Q2/Q3 2022, in direct continu- ation of the rig’s current contract, and will include the plugging and abandon- ment of 11 wells with TotalEnergies and 20 wells with Petrogas. The estimated duration is 575 days, and the total firm contract value is approximately $43 mil- lion, excluding potential performance bonuses. The contracts include options to add additional work scopes with a total estimated duration of 228 days. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 7 DEPARTMENTS • DRILLING & COMPLETION NEWS Valaris wins new contracts, extensions for multiple rigs, retires VALARIS 67 Hess takes FID to develop Yellowtail in Guyana, plans to start production in 2025 Valaris recently announced new contracts and contract extensions with associated contract backlog of $181 million : • Two-year contract extensions with BP in the US Gulf of Mexico for managed rigs Mad Dog and Thunder Horse. The contract extensions were effective on 27 January. • One-well contract extension with TotalEnergies EP Brazil for drillship VALARIS DS-15. The option well is in direct con- tinuation of the current firm program and has an estimated duration of 100 days. • A three-year contract with Saudi Aramco for ARO Drilling’s standard-duty modern jackup VALARIS 140. This contract relates to the previously disclosed three-year bareboat char- ter agreement between Valaris and ARO Drilling . • The previously disclosed contract awarded to VALARIS DS-11 for an eight-well contract for a deepwater project in the US Gulf of Mexico has been novated from TotalEnergies to Equinor. There are no material changes to the contract . • VALARIS 67 has been sold and retired from the offshore drilling fleet. Hess has made a final investment decision to proceed with development of Yellowtail offshore Guyana after receiving government and regulatory approvals. Yellowtail, the fourth oil development and the largest on the Stabroek Block, is expected to produce approximately 250,000 gross bbl/day of oil starting in 2025. Yellowtail will utilize the ONE GUYANA FPSO, which will develop an estimated resource base of approximately 925 million barrels of oil. Six drill centers are planned, with up to 26 produc- tion wells and 25 injection wells. Hess’ net share of development costs, excluding pre-sanction costs and FPSO purchase cost, is forecast to be approximately $2.3 billion, of which approximately $210 million is expected in 2022, $430 million in 2023, $585 million in 2024, $390 million in 2025 and $295 million in 2026. Santos makes significant oil find with Pavo-1 exploration well offshore Australia Santos announced the Pavo-1 exploration well has con- firmed a significant oil discovery 46 km east of the Dorado field in the Bedout Sub-basin, offshore Western Australia. The well was drilled on the northern culmination of the greater Pavo structure and encountered a 60-m gross hydro- carbon column in the primary Caley member reservoir target. Wireline data has confirmed 46 m of net oil pay, with an oil- water contact intersected at 3,004-m measured depth (MD). Wireline logging operations to collect pressure, sample and rock data across the target Caley reservoir have been com- pleted. A 2C contingent resource for the northern culmination is assessed at 43 million barrels of oil gross . “The Pavo-1 success is expected to support a potential low- cost tie-back to the first phase of the proposed Dorado develop- ment, with Pavo north having an estimated breakeven cost of less than $10/bbl, and future gas production from the Bedout basin providing a source of supply into our existing domestic gas infrastructure in Western Australia,” said Kevin Gallagher, Santos Managing Director and CEO. Murphy starts production from Khaleesi, Mormont, Samurai in deepwater GOM Murphy Oil has achieved first oil from the Khaleesi, Mormont and Samurai field development project in the deep- water Gulf of Mexico . Production is flowing through the Murphy-operated King’s Quay floating production system. The Khaleesi/Mormont fields are located in Green Canyon blocks 389 and 478, respectively, and the Samurai field is located in Green Canyon Block 432. Completions operations are ongoing for the remaining five wells in the seven-well project. 8 Duva producer wells are tied back to the Gjøa semisubmersible platform, and the gas is then transported to the UK. Neptune will double gas production from Duva field for at least next 4-8 months To help meet gas demand in Europe, Neptune Energy and its partners will double gas production from the Duva field in the Norwegian sector of the North Sea by 6,500 bbl/day of oil equivalent (BOEPD) . Duva is a subsea installation with three oil producers and one gas producer, tied back to the Gjøa semisub- mersible platform. The gas is transported by pipeline to the UK’s St Fergus gas terminal. Duva’s overall production currently stands at 30,000 BOEPD, of which 6,500 BOEPD is natural gas. Under the newly agreed measures, daily gas production will double to 13,000 BOEPD for an initial period of four to eight months. The increase in produc- tion is expected to supply enough energy to heat an additional 350,000 homes per day in the UK, according to Neptune. M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R DRILLING & COMPLETION TECH DIGEST • DEPARTMENTS 14 innovations highlighted under OTC Spotlight on New Technology program The Offshore Technology Conference (OTC) has announced the winners of the 2022 Spotlight on New Technology Award. The award is presented to OTC exhibitors who are revolutionizing the future of offshore energy through technological advance- ment and innovation. A total of 14 technologies , including seven from small businesses, were recog- nized this year . Recipients were selected based on : nov- elty in the marketplace; level of innovation; demonstrated success; broad commercial appeal; and ability to make a significant impact across the offshore industry. 2022 Spotlight Winners • Bosch Rexroth, producer of SVA R2: The world´s first electric subsea valve actua- tor with safety by springs, as compact as hydraulic actuators; • Expro, producer of Galea – Autonomous Well Intervention System; • Oil States Industries, producer of Oil States Managed Pressure Drilling & Riser Gas Handling System; • Oil States and TotalEnergies, producers of 15K High Pressure, High Temperature (HPHT) Riser System For Subsea Drilling Applications in Shallow Water; • R3 Environmental Systems, producer of Vacuum Assisted Pure Oil Recovery Technology; • Schlumberger, producer of ReSOLVE iX extreme-performance instrumented wireline intervention service; and • Schlumberger, producer of Autonomous Directional Drilling. 2022 Spotlight Small Business Winners • ClampOn, producer of ClampOn Subsea Flow Temperature Monitor; • CoreAll, producer of CoDril; • HYTORC, producer of MXT+ Hydraulic Torque Wrench; • HYTORC, producer of HYTORC Connect Software App; • Rocsole , producer of ROCSOLE Intelligent Level Detection & Data Analytics for Sand Management; • Subsea Shuttle , producer of Subsea Shuttle ; and • Aquatec Group, producer of KINEKtron . Expro’s Galea Autonomous Well Intervention System (top), as well as Schlumberger’s ReSOLVE iX wireline intervention service (middle) and Autonomous Directional Drilling (bottom), all received the OTC Spotlight on New Technology Award. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 9 DEPARTMENTS • ENVIRONMENT, SOCIAL AND GOVERNANCE New framework aims to help assess reliability of crude oil’s GHG intensity KCA Deutag’s rig will use electrical motors instead of diesel generators while drilling the Z17 well for Neptune Energy in Germany. Electrical motors to cut drilling emissions in Germany Neptune Energy recently awarded KCA Deutag with a contract to drill the Z17 well in the Adorf Carboniferous gas field, northwest Germany . Operated with power from the grid, KCA Deutag’s rig will use electrical motors in place of diesel-driven generators, removing an estimated 1,000 tonnes of CO 2 emissions from the drilling operation. Neptune has been developing the Adorf field since 2019. The Adorf Z15 and Adorf Z16 wells were also drilled by KCA Deutag and are now in production. “The use of electrical motors under- lines Neptune’s commitment to continue to reduce emissions from our opera- tions,” said Andreas Scheck, Neptune Energy’s Managing Director in Germany. The operator says that by 2030, it aims to store more carbon than is emitted from its operations and from the use of its sold products. Work on the Z17 well is due to com- mence in June . Neptune Energy holds a 100% stake in the Adorf Carboniferous gas field. The current daily production is around 4,500 bbl/day of oil equivalent. Shell commits funds to create Energy Transition Institute A $10 million gift from Shell has enabled the University of Houston (UH) to establish the Energy Transition Institute, focused on the production and use of reliable, affordable and cleaner energy . Total funding for the institute will likely exceed $52 million. With Shell as the founding partner, the Energy Transition Institute is focused on three core areas: hydrogen, carbon management and circular plastics . The hydrogen focus will be on the industrial use, storage and transportation of liquid hydrogen, driven by a commercializa- 10 tion effort to accelerate its decarboniza- tion at scale. In addition to this work, UH is already working with a Shell-led consortium to enable large-scale liquid hydrogen storage for international trade applications. Carbon management will focus on policy, research and develop- ment to reduce emissions through the capture, utilization and storage of CO 2 and methane. After the institute is launched, it is expected that Shell scientists will work with faculty and students on each of the core areas . S&P Global has issued a study provid- ing guidance and methodology to help the industry improve comparability, con- sistency and confidence in assessing the life-cycle greenhouse gas (GHG) intensity of crude oil. The study addresses chal- lenges that currently limit utility of life- cycle GHG emissions estimates of crude oil. It also proposes a “Data Quality Metric,” a framework to improve the transparency around the reliability of estimates. It was developed in collaboration with the US Department of Energy’s National Energy Technology Laboratory. The study also aims to demonstrate the guidance and methodology by creating a benchmark representing the average intensity of crude oil consumed in North America. The results assess the crude oil pathways that comprise over 90% of the volume processed in the US in 2019 . Scan me to download the full report. bit.ly/3ro1OXk New BSEE Burner could be game changer for oil spills On 30 March, the US Bureau of Safety and Environmental Enforcement (BSEE) and the US Naval Research Laboratory (NRL) hosted a demonstration of the Low- Emission Spray Crude Oil Combustor tech- nology, also known as the “BSEE Burner.” The demonstration was held at NRL’s test- ing facility in Chesapeake Beach, M d . Developed in partnership with NRL over seven years, the BSEE Burner cleanly burns large volumes of emulsified oil from spills that occur in remote areas where storage facilities may not be available, or where transporting the recovered oil is cost prohibitive. EPA emission tests revealed that the burner performs well with a combustion efficiency of 99.9% . “This technology has the potential to be a game changer in the performance of oil spill recovery,” said BSEE Director Kevin Sligh. M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R ENVIRONMENT, SOCIAL AND GOVERNANCE • DEPARTMENTS SEC proposes requirements for climate-related risks, emissions disclosures The US Securities and Exchange Commission has proposed rule changes that would require registrants to include certain climate-related disclosures in their registration statements and period- ic reports, including information about climate-related risks that are reasonably likely to have a material impact on their business, results of operations, or finan- cial condition, and certain climate-related financial statement metrics in a note to their audited financial statements. The required information about climate-relat- ed risks also would include disclosure of a registrant’s greenhouse gas emissions . “ Today’s proposal would help issuers more efficiently and effectively disclose these risks and meet investor demand, as many issuers already seek to do. Companies and investors alike would benefit from the clear rules of the road proposed in this release ,” SEC Chair Gary Gensler said. Under the proposed rule changes, accel- erated filers and large accelerated filers would be required to include an attestation report from an independent attestation service provider covering Scopes 1 and 2 emissions disclosures, with a phase-in over time, to promote the reliability of GHG emissions disclosures for investors. The proposed rules would include a phase-in period for all registrants, with the compliance date dependent on the registrant’s filer status, and an additional phase-in period for Scope 3 emissions disclosure. See Page 6 for additional information on the proposed changes. BP, Chevron join new Singapore-based group for maritime decarbonization Demand for CO 2 storage is increasing, and Equinor believes it’s important to develop new storage sites quickly to allow the Norwegian Continental Shelf to become a leading province for CO 2 storage in Europe. Equinor awarded licenses for CO 2 storage on NCS Equinor has been awarded the oper- atorships for the development of two CO 2 storage projects – Smeaheia in the North Sea and Polaris in the Barents Sea. The two licenses are seen as build- ing blocks for developing the Norwegian Continental Shelf (NCS) into a leading province for CO 2 storage in Europe. CO 2 transport and storage infrastruc- ture is crucial for providing CO 2 solutions on a commercial basis to industrial cus- tomers, such as steel, cement and other heavy industries. This will also help pro- tect existing jobs while creating new jobs in the development of new value chains on the Norwegian shelf. Talos Energy executes lease for CCS site offshore Texas Talos Energy announced that Bayou Bend , its venture with Carbonvert, has executed definitive lease documentation with the Texas General Land Office to formalize a carbon capture and seques- tration (CCS) site offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. It is expected to be the first major offshore carbon sequestration site in the US. The lease maintains an estimated sequestra- tion capacity of 225 million to 275 million metric tons of CO 2 . Talos separately announced that it had established a CCS strategic alliance with Core Laboratories to provide technical evaluation and assurance services for CCS subsurface analysis, including the company’s upcoming 2022 stratigraphic evaluation wells. BP and Chevron each recently announced that they have joined the Global Center for Maritime Decarbonization (GCMD). Singapore-based GCMD was set up last year to help drive decarbonization of the maritime industry . It aims to help the maritime industry meet or exceed the International Maritime Organization’s GHG emission reduction goals for 2030 and 2050. BP’s partnership adds $7.4 million (S$10 million ) in funding for GCMD. Chevron said its involvement aims to help support GCMD’s efforts to develop potentially scalable lower-carbon tech- nologies – including those that enable the use of ammonia as a maritime fuel – and the commercial means to enable their adoption. Nabors Industries invests in geothermal tech company Nabors Industries has invested $8 million into GA Drilling, a geothermal technology company with headquarters in Bratislava, Slovakia . The investment expands Nabors’ commitment to deep- drilling technologies that can tap super- hot, ultra-deep rock reservoirs. GA Drilling ’s PLASMABIT drilling tool will be integrated into Nabors’ automated and lower-emission drilling operations, accelerating field commercialization and eliminating traditional economic barriers of ultra-deep projects to expand global access to geothermal energy . D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 11 DEPARTMENTS • OIL & GAS MARKETS Ukraine war will not derail Europe’s energy transition, DNV analysis shows Although oil and gas demand in the UK will likely still outstrip supply in the coming decades, Wood Mackenzie notes there is signifi cant uncertainty in the numbers, and the North Sea could still increase production to improve energy security. 5 levers UK can pull to increase oil and gas production High commodity prices and Russia’s invasion of Ukraine have called into ques- tion the UK’s reliance on energy imports. In response, the UK government is set to unveil a energy security strategy. In a new report , Wood Mackenzie examined the levers the North Sea can pull to increase production and argues indigenous oil and gas still has a major role to play. While UK demand for oil and gas will continue to outstrip supply, there are wide ranges of uncertainty, the report stated. In 2030, production will be between 0.6 mil- lion and 1.6 million bbl/day of oil equiva- lent (BOED) ; the range for demand is even wider. “By 2050, UK North Sea production will have largely ceased. But even in a net- zero scenario, demand will persist, with emissions being offset by carbon capture and storage and nature-based solutions,” said Neivan Boroujerdi, Research Director, North Sea Upstream for Wood Mackenzie. “Current levels of production could be maintained for the next decade, underpin- ning energy security and safeguarding jobs. But the UK is sorely lacking in gas and will be heavily reliant on imports in all scenarios.” The report sets out five levers to boost production: execution, new greenfield proj- ects, increasing recovery from existing assets, exploration and the development of contingent resource. If all economically viable resources were to be produced, this could deliver 5 billion BOE of new volumes and $60 billion of investment, according to the report. Greenfield projects like Cambo and Rosebank offer the most immedi- ate upside, but some require finance or a change in ownership. Wood Mackenzie also asserts that UK shale is not the answer. “In-place vol- umes may appear big, but public oppo- sition, population density, infrastructure, land access, flow rates and low recovery rates all limit its commercial impact,” Mr Boroujerdi said. Europe’s energy transition will be accelerated – with less fossil fuels in the energy mix and lower green- house gas emissions – because of its pivot away from Russian gas, accord- ing to new analysis from DNV’s Energy Transition Research. Their findings show that 34% of the energy mix in Europe will come from non-fossil fuels in 2024, 2% more than the pre-war forecast. Overall gas use will drop by 9% in 2024 compared with DNV’s pre-war model run. The biggest percentage increase is in solar, which is expected to be up 20% by 2026. The delayed retirement of some of the con- tinent’s nuclear power plants is also an important component of filling the gap. Although some coal is needed in the very short term to meet Europe’s ener- gy demand, by 2024 postponed retire- ments and higher nuclear utilization will be important to cover the shortfall of natural gas. Emissions from energy will be 2.3% lower in Europe from 2022- 2030, compared with a pathway with- out the Ukraine war. This is due to the increased prominence of low-carbon energy (renewables and nuclear), more energy efficiency and, in the short to medium term, lower economic growth. Russia’s pivot East will not fully compensate for reduced gas exports to Europe because of limited infrastruc- ture. In contrast, DNV estimates that Europe itself will produce 12% more gas in 2030, reflecting industry’s reac- tion to higher oil and gas prices in the short term and response to the pledge from EU to deliver more gas. The role of imported LNG is limited by regasifica- tion capacity, with extra infrastructure expected to take years to build . Global oil/gas contracts up by 9% from 2020 to 2021, while contract value rose by 51% Annual oil and gas contracts activity increased by 9% in 2021 in terms of the number of contracts and by 51% in terms of disclosed contract value, according to GlobalData . The number of contracts increased from 5,750 in 2020 to 6,263 in 2021 , and the disclosed contract value rose 12 from $115.42 billion in 2020 to $174.21 bil- lion in 2021. The analysis cites improved crude oil prices and COVID-19 subsiding as key factors that boosted activity. Notable contracts include those for an LNG project by Qatar Petroleum for the North Field East Project , as well as Saudi Aramco’s 16 contracts, with a combined worth of $10 billion, for the subsurface and EPC works for the development of the Jafurah shale gas field . Operation and maintenance represented 44% of the total contracts , followed by con- tracts with procurement scope with 20% . M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R OIL & GAS MARKETS • DEPARTMENTS Energy talent survey finds potential for skills exodus to renewables sector A whopping 82% of oil and gas profes- sionals would consider leaving for another energy sector within three years, accord- ing to findings from the sixth annual Global Energy Talent Index (GETI) . The report by Airswift and Energy Jobline also found that 54% would choose renewables. Moreover, the talent migration is already under way, with 28% of those who joined the renewables sector in the past 18 months transitioning from oil and gas. This is partly driven by rising concerns over climate change, with ESG factors now the second-biggest driver behind cross- sector career moves. A total 85% of those in the sector say ESG concerns are now a factor in whether to join or leave a company. Those oil and gas majors that are slowest to adopt clean energy could, therefore, be most at risk of mass resignations, with 28% of survey respondents reporting that their organiza- tion has not changed direction to adapt to the energy transition. With investors increasingly spurning fossil fuels , profes- sionals now rank the transition to clean energy second only to COVID-19 as the big- gest challenge to oil and gas over the next three years. On the other hand, oil and gas workers awarded their companies an average 3.53 out of 5 stars for performance on envi- ronmental issues, and 18% of people who joined from another sector in the last 18 Key fi ndings from the new Global Energy Talent Index show that the oil and gas industry should not underestimate the competition for talent from other energy sectors like renewables, as well as from the technology industry. Source: Airswift, Energy Jobline months came from renewables. Further, 89% of all professionals would consider moving within the sector, indicating that companies with strong ESG credentials could attract workers from both within and outside the industry . Renewables salaries are also increas- ingly attractive . A total 40% of renewable professionals received a pay rise last year, compared with 31% in oil and gas. And only 11% of those in renewables saw sala- ries fall, compared with 21% in oil and gas. “ The (oil and gas) sector should continue to promote its role in global development efforts and as a bridge to clean energy ,” said Janette Marx, CEO at Airswift. Airswift and Energy Jobline inter- viewed sector experts and surveyed 10,000 energy professionals and hiring managers in 161 countries across five industry sub- sectors : oil and gas, renewables, power, nuclear and petrochemicals. Wood Mackenzie: Russian-Ukraine war may slow global economic growth in 2022-2023 Global economic growth could slow to 2.5% year-on-year in 2022 and 0.7% in 2023 due to the Russia-Ukraine war, according to Wood Mackenzie . The company has produced a downside scenario for the global economy, assuming large spill-over effects from the Russia- Ukraine conflict through transmission channels and markets, some interruption of energy and commodity flows, an energy price shock causing recessions in the EU and US, and pro-cyclical policy missteps exacerbating matters. “Energy and commodity prices could fall as the global economic downturn takes hold and the EU and US recessions bottom out after four to six quarters when con- sumption hits its nadir,” said Peter Martin, Research Director. “The lag in reaching the bottom of the economic cycle sees the global economy take a bigger hit, relative to the base case, in 2023 compared to 2022.” In the scenario, Russia partially defaults on sovereign debt worth $480 billion, with contagion effects for the European bank- ing system. However, this pales in com- parison to the Euro crisis in 2011-2012, and banks are now better capitalized to weather losses. Conversely, a sharp rise in energy and food prices hurts industry, destroys demand and erodes consumer purchasing power. Global business confidence deteriorates and investment contracts. Wages are fro- zen before unemployment eventually rises and consumption falls further. Concerned about inflation, major central banks persist with monetary policy tightening into the recession and fiscal support is inadequate. “We think a 15% decline in Russia’s GDP this year is possible,” Mr Martin said. “Over the medium term, however, Russia’s economy will be forced to rebalance and restructure.” He added : “ More importantly, the global economy could be looking at more perma- nent changes. If the COVID-19 pandemic highlighted a need to shorten supply chains, the war in Ukraine underscores the impor- tance to have reliable trading partners. These forces could lead to a lasting realign- ment of global trade. The global economy becomes more regionalized — shorter sup- ply chains with ‘reliable’ partners. ” D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 13 LOW-CARBON DRILLING SOLUTIONS Low-carbon technologies moving from concept to reality at the rig site Industry continues to develop new ways to reduce emissions, not only through engines but also drilling waste, hydraulic ring line BY STEPHEN WHITFIELD, ASSOCIATE EDITOR T he oil and gas industry is well aware of the need to adapt to a low-carbon future. With the push for net-zero grow- ing more urgent in recent years, the industry is moving beyond discussing the need for sustainable solutions and toward the delivery of effective technologies that reduce or eliminate harmful emissions from drilling operations. “We’ve seen a big step-change,” said Frank Tollefsen, CEO of COSL Drilling Europe. “Everybody in our industry recognizes that we need to operate as sustainably as possible, but there’s been an increased focus and an increase in pressure from the regulators, Highlights Engine management software systems are helping drilling contractors reduce both fuel consumption and emissions, both from onshore and offshore rigs. Super-capacitors can help distribute power to a rig’s engine system at faster rates than a battery energy storage system, further improving peak shaving capabilities. Portable treatment units are enabling drillers to eliminate emissions generated from supply vessels typically used to transport drill cuttings waste to shore. 14 from investors and from the public. It’s ever growing, and it only emphasizes the importance of us delivering sustainable solutions if we want to be part of the energy mix.” Many of the low-carbon technologies currently available focus on reducing Scope 1 emissions, or the emissions that come from sources directly owned by an organization. Engine management systems are the main focus of development in this area. A number of drilling contractors have recently launched systems designed to improve fuel efficiency by reducing the number of active engines on their rigs. Further, new technologies in the market are focused on minimizing the impact of peripheral emitters in a drilling operation, such as the hydraulic ring line or the transport and treatment of drill cuttings waste. Regardless of the system, the priority for drilling contractors and manufacturers is getting support from customers for wide- scale adoption, which can be difficult in an industry that’s typi- cally been slow to accept new technologies. The key to achieving that adoption is demonstrating their capabilities in the field and showing companies the value they can provide. “We’ve had to establish the reliability of these solutions opera- tionally so that you can get more buy-in,” said Gilles Luca, Senior Vice President and Chief Operating Officer at Valaris. “You want to adopt a conservative approach, and that includes carefully bring- ing in your rig crews and your operators on the journey, and dem- onstrating to them the sound operational and engineering basis of these solutions. The best thing to move this forward is to move slowly but surely, and build a successful operational track record with these technologies, so that people will have the confidence and willingness to use them.” M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R LOW-CARBON DRILLING SOLUTIONS COSL Drilling Europe initially installed its Energy Control System on two semisubmersibles in the North Sea, the COSL Promoter (pictured) and the COSL Innovator . The software monitors the rig’s diesel generators during a given operation and advises users on the actions likely to require the least amount of power consumption. CO 2 and NOx emissions have fallen by nearly 50% on the two rigs since installation, and the system has since been installed on the COSL Pioneer as well. Energy Control System In 2020, after six years of development, COSL Drilling Europe launched its Energy Control Project, designed to save energy on COSL rigs operating in the Norwegian North Sea. The project is primarily centered on reducing fuel usage of engines and gen- erators on COSL rigs and, subsequently, reducing greenhouse gas (GHG) emissions. The main deliverable from the Energy Control Project is the Energy Control System, an automated software program that monitors power consumption during a given operation. The sys- tem advises users on the courses of action likely to require the least amount of power consumption, estimating the kilowatts needed, the amount of fuel needed and the subsequent CO2 and NOx emissions. These estimates are displayed on a dashboard that users can access from anywhere. The system is connected to the rig’s control system so it can act upon its advisory without any input from the rig crew. However, it also has manual override capabilities for unforeseen circum- stances, like a weather event where users may need to shut down more generators than expected. Torfinn Kalstø, ICT & OT Manager at COSL Drilling Europe, said the monitoring and advisory capabilities in the Energy Control System provide essential insights and help maximize efficiency gains from the rig. “We’re looking to produce the most efficient kilowatt hours from the generator. This is the whole idea. It’s all about maintaining high performance and, at the same time, low- ering the power usage.” In 2020, COSL Drilling installed the Energy Control System on two semisubmersibles in the North Sea – the COSL Promoter, working for Equinor on the Troll field , and COSL Innovator, work- ing for Chrysaor . The rigs are each powered by six diesel genera- tors with maximum capacities of 4,800kW . These previously ran continuously during drilling operations, but pre-installation anal- ysis showed these generators were rarely used at full capacity. Running the Energy Control software, COSL Drilling found that it could shut down, on average, four of the six diesel engines dur- ing operations. The company has already seen a significant reduction in fuel consumption on these rigs. Prior to installation, the rigs averaged 27 tons/day of fuel consumed in Posmoor/ATA mode (where the rig is running a thruster-assisted mooring control system) and 29 tons/day in full DP3 mode. After installation, COSL Drilling now sees averages of 14/tons day in Posmoor/ATA mode and 20 tons/ day in DP3 mode. Depending on the operation, the company has D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 15 LOW-CARBON DRILLING SOLUTIONS COSL Drilling’s Energy Control System displays fuel consumption and emissions data on a dashboard. As it is connected to the rig’s control system, the software can automatically act upon its own advisory without any input from the rig crew, but users can also override the system in case of any unforeseen circumstances. The system is now deployed on all three of COSL Drilling’s contracted rigs in the North Sea. reported fuel consumption as low as 7.6 tons/day. CO2 and NOx emissions have also fallen by around 50% on the two rigs since installation. “We were almost shocked to see how much energy we were consuming in normal drilling operations,” Mr Tollefsen said. “Even when we first developed this, we thought we would need all of this energy, but in a normal drilling operation, the actual requirements can fall so low that they’re well within the capac- ity of one generator. On average, we can run two or three, but sometimes we’re down to one generator. That’s almost unheard of in the industry because you always assume you need some additional reserves.” COSL Drilling also installed the system on the COSL Pioneer, operating on the UK Continental Shelf, in December 2021. In the three months following installation, the semisubmersible saved 904 tons of fuel compared with the previous three months. This fuel reduction equated to approximately 2.85 tons of CO2 saved. The Energy Control System is currently running on all three of COSL Drilling’s contracted rigs in the North Sea. In March 2022, the COSL Pioneer began work under a new contract with Ithaca Energy that is expected to last until Q2 2024. The COSL Promoter is slated to work for Equinor through Q1 2024, while the COSL Innovator began a new contract with CNOOC Europe in April 2022. While the Energy Control System was developed for use on COSL Drilling’s North Sea rigs, Mr Tollefsen said the company is looking to expand its deployment in other regions, as well. Engine management Valaris is looking to enhanced power management systems as a low-carbon offering in its technology portfolio. In October 2021, the VALARIS DS-12 drillship became the first vessel in the world to receive the ABS Enhanced Electrical System Notation EHS-E. Valaris upgraded the rig’s electrical system to secure the notation, which recognizes improvements in power system redundancy 16 and reliability. The enhanced system enables the rig to safely operate with as few as two generators online, thereby reducing emissions. VALARIS DS-12 worked for a major operator in Angola during Q4 2021 and Q1 2022 and is expected to be working for the operator offshore Mauritania and Senegal through the remainder of 2022. During the Angola campaign, Valaris realized a 5% reduction in fuel consumption and approximately 600-MT reduction in CO2 emissions compared with the pre-upgrade configuration, which required a minimum of three generators online. Mr Luca noted that the mild environmental conditions found offshore Angola made it an ideal proving ground for this new technology. The company hopes to install the enhanced power manage- ment system on more of its floater fleet in the future, but further deployment will also depend on customer demand. “It’s an invest- ment to take the rig out of operation for a period of time and install this system, so we hope to find the right partners who are willing to invest in that enhancement for the rig, thereby making their own operations more carbon efficient.” The engine optimization system is one solution within the Valaris portfolio of options to reduce GHG emissions. For a fleetwide view and tracking of these emissions, the company leverages the Valaris Intelligence Platform (VIP), a monitoring program that aggregates and displays fuel consumption and GHG emissions for each monitored rig in its fleet. The program helps establish a baseline of fuel consumption and emissions by rig and engine type, which can then help the company quantify the impact of the various solutions it chooses to deploy across its fleet. While the VIP system monitors mission-critical rig equipment, it also provides dashboards for fuel consumption, CO2, NOx and SOx emissions over time. Understanding power requirements at the rig site and comparing against the amount of power available from the rig power plant enables the technical team to optimize the gap between the two, based on the operating conditions at any given time. The VIP system is currently available on more than half of active Valaris rigs and is on track for deployment to the remain- der of the active fleet by year-end. “VIP is really about streaming systems data into an aggregator and analytic solution to tell us how our rigs are being run. This enables us to better monitor our systems and our power plants. From there, we can visualize the loading of a particular engine in real time, optimize the loads on the engine, optimize the fuel and determine where we can reduce emissions,” Mr Luca said. In addition to the VIP system and enhanced power manage- ment system, Valaris has installed selective catalytic reduction (SCR) systems on four drillships – VALARIS DS-15, DS-16, DS-17 and DS-18 – and one jackup, VALARIS 123. SCR is an emissions control technology that filters out certain potentially harmful elements from the engine exhaust system. An additive is added to the exhaust fumes, initiating a chemical reaction that converts NOx into nitrogen, water and tiny amounts of CO2. While NOx emissions data from the four drillships are not yet available, Valaris has reported a 90% reduction in NOx from the VALARIS 123 jackup since the SCR installation. M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R LOW-CARBON DRILLING SOLUTIONS “The SCR system is doing the job for us. It’s a very effective system in terms of removing NOx byproducts – you cannot argue with a 90% reduction from the exhaust system,” Mr Luca said. AI-based systems In December 2021, Nabors launched Nabors Energy Transition Solutions (NETS), a portfolio of technologies designed to improve energy efficiency, reduce fuel consumption and lower emissions. At the heart of this portfolio is the SmartPOWER Advisory and Controls engine management software. The advisory system, which is deployable to Nabors and third-party rigs, applies artifi- cial intelligence (AI)-based algorithms to real-time drilling data, advising the driller on the optimal number of engines to run for a given task in a drilling operation. The SmartPOWER Control sys- tem, which is expected to launch in Q2 2022, automates the start and stop of the individual rig engines based on those advisories. James Hall, Product Line Director at Canrig Drilling Technology, a Nabors subsidiary, said the software is unique in its ability to incorporate numerous external factors in its advisory mecha- nism. SmartPOWER focuses on the true drilling data received through the electronic drilling recorder (EDR) and uses pro- prietary AI to recommend the optimal number of engines and generators to run, both for current and predicted drilling activity. In addition to real-time drilling data, a separate module within the system accounts for altitude, coolant temperature, oil condi- tion and filter condition within the engine to further optimize decision making. The system also accounts for an engine’s ser- vice life and maximum capacity. “Our system evaluates engine condition and other factors to determine which engines have the highest capacity,” Mr Hall said. “It’s just as important to know which engines to run as it is to know how many engines to run.” Field testing of the advisory system, carried out on a Nabors rig in Q1 2022, indicated a reduction in diesel consumption in line with internal models showing up to 20% in certain applications, with an equivalent reduction in CO2 emissions. This reduction is with respect to the baseline set from average fuel consumed during operations running all available engines, with no manual intervention of the generators. In Q2 2022, Nabors plans to release a super-capacitor energy storage system, Canrig PowerFLOW. Similar in function to other energy storage systems, PowerFLOW uses super-capacitors to provide immediate power for load spikes during tripping and other operations, maximizing energy capture during drawworks braking and reducing the need for diesel-generated power above baseload. The difference between super-capacitor and battery energy storage is the super-capacitor’s ability to near instantaneously store provided power and its speed at supplying power back to the system. The PowerFLOW’s charge/discharge rate (C rating) ranges from 25 to 50 C, meaning that it can provide 3,500 amps of power in just over a minute, and the system can support 1,000-amp dis- charge for 9.5 minutes. A battery energy storage system’s C rating typically ranges from 3 to 5 C, meaning that it can discharge a maximum of 1,500 amps for up to 12 minutes at max capacity. Last October, the VALARIS DS-12 drillship became the fi rst rig to receive the ABS Enhanced Electrical System Notation EHS-E. Valaris upgraded the rig’s electrical system to safely operate with as few as two generators online. A higher C rating means that a system can deliver more power to the system at faster speeds, which is valuable for tasks with high power demand. It also means that the system can recharge faster, with recharge times in the range of 1 to 6 seconds, depend- ing on drilling activities. Due to the fast recharge characteristics of PowerFLOW, the system is capable of fully charging from “free” regenerative power, rather than drawing charge from the genera- tors. This capability makes it easier for users to maintain peak shaving, avoiding the spikes in power demand that can drive up diesel usage and, subsequently, emissions. An additional feature available when combining SmartPOWER and PowerFLOW is the ability for the super-capacitor power to be pushed to the AC bus. AC bus frequency can be monitored, and PowerFLOW can inject AC voltage to the AC bus if frequency drops, when either large AC or DC loads are felt on the AC bus. This ensures that the generators maintain constant load and, therefore, no engine surges occur during any operation. “Imagine a system that you can fill up with power and discharge quickly. That’s where super-capacitors have value,” Mr Hall said. “By using these super-capacitors, you can monitor and control the discharge rates. For our drilling operations, energy storage isn’t really about powering the rig when your other sources of power are removed; it’s about giving you the ability to be more efficient with power generation. You’re using the super-capacitor to sup- plement that power generation, and you can run your engines at a constant load, even though you have these high demand peaks .” Eliminating drill cuttings waste transport NOV’s recent low-carbon technology offerings have targeted mitigating, or outright eliminating, wasteful activities in a drilling operation. One area of focus for the company is on the treatment of oil-based drilling waste. Last year, the company launched its iNOVaTHERM portable treatment unit to allow companies to treat and dispose of drilling waste on the rig, as opposed to the D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 17 LOW-CARBON DRILLING SOLUTIONS Left: Nabors’ SmartPOWER Advisory System incorporates data from several data points, including coolant temperature and fi lter status within the engine, to advise drillers on the optimal number of engines needed to run a given operation on the rig. Right: The Canrig PowerFLOW system, set to launch in Q2 2022, uses super-capacitors (pictured) to store and distribute power immediately to a rig’s engines to minimize the load spikes seen during tripping operations. conventional process of shipping the waste to shore for treatment and disposal, eliminating a notable source of emissions from a drilling operation. The system works by feeding drilling cuttings into a feed hopper. Those cuttings are then transferred to a heat exchanger module for treatment. Inside the heat exchanger module, the drill cuttings remain in constant contact with the heated internal surface area to ensure that consistent results on waste separation is achieved . A condensation module recovers the heavier phase of the oil, which is then returned to the mud system. The steam conden- sation within the condensation module is then transported to a water treatment module, which recovers the lighter phase of oil. The recovered water is then discharged from the rig. The iNOVaTHERM system eliminates the drive module found in a conventional frictionally heated waste-processing system, with the power going directly into the high-efficiency heat exchanger. Gordon Duthie, Senior Director of Sales – Eastern Hemisphere at NOV, said this feature reduces the footprint and helps conserve power and emissions on the rig, since the rig does not need to supply power to the gearbox, rotor and hammers found in typical friction-based systems. However, the biggest savings with emissions comes from eliminating the supply vessels typically used to transport cut- tings waste from the rig site to the shore, and the trucks needed to transport the cuttings waste from the vessel to the onshore treatment facility. “The treatment at the source really eliminates many of the logistical challenges that come from operating in a remote loca- tion, whether that’s on land or offshore. Any conventional waste handling requires you to use a supply vessel to go out to the rig and take back the containers of cuttings. From a carbon footprint reduction standpoint, this system eliminates the need for all that activity, and we’re eliminating the need for onshore processing and disposal in a land fill,” Mr Duthie said. 18 The numbers from NOV’s project scenario data illustrate the emissions savings that are possible from utilizing the system on the rig site. Comparing the emissions generated against con- ventional containment and waste-processing methods, iNOVa- THERM eliminates the supply vessels used offshore and the trucks used onshore to transport the waste to the treatment facil- ity, as well as the onshore treatment and disposal operations. In this project scenario, a significant amount in emissions (280,264 kg of CO2 per drilling campaign) was saved by treating the drilling wastes on site. Overall, the conventional method created 319,063 kg of CO2 emissions and 4,720 kg of NOx emissions. With the iNOVaTHERM system, those figures went down to 186,436 kg of CO2 and 3,107 kg of NOx. “These numbers demonstrate that processing drilling wastes offshore goes a long way towards meeting the emission reduction goals and targets our clients have committed to. Once we start eliminating the supply vessel and the other logistics with onshore processing, there are significant environmental and cost savings to be had ,” Mr Duthie said. The technology was launched commercially in January 2021 in the UK sector of the North Sea following 18 months of develop- ment and testing at NOV’s thermal treatment plant in Aberdeen . It has since been used by two major oil and gas operators on four drilling campaigns in the North Sea. A fourth campaign began in April 2022. Boosting hydraulic pump efficiency Another erratic power consumer on the rig is the hydraulic ring line. This system feeds several pieces of hydraulic equipment on the rig, including iron roughnecks, power casing tongs, vertical column pipe rackers and catwalk machines. The flow and pressure in the ring line system are usually set to a level that can accommo- date simultaneous operation of these pieces of equipment. Richard Verhoef, Product Line Manager for Handling Tools at NOV, compared the hydraulic pumps powering the ring line M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R LOW-CARBON DRILLING SOLUTIONS Left: NOV’s Eco Booster system, launched last year, contains an accumulator skid (pictured) that stores and distributes power to the hydraulic pumps powering a rig’s ring line system, reducing power usage during periods of peak demand. Right: NOV’s iNOVaTHERM, a portable unit for treating and disposing of drilling waste on the rig, has been used on four drilling campaigns in the North Sea since its commercial launch in January 2021. system to generator sets. To deal with the potential hydraulic demands at peak usage, more pumps are running than what is really needed for a large percentage of the time. Pumps running idle for 24 hours a day consume a large amount of electricity and fuel, continuously emitting CO2 and NOx. However, the pumps need to be able to handle sudden increases in flow requirements when the hydraulic pump is activated. Hydraulic equipment already in operation will also be affected by this pressure drop. To help operators use their hydraulic pumps more efficiently, thereby reducing power usage and emissions, NOV launched its Eco Booster system last year. Eco Booster is a hydraulic energy storage system that optimizes hydraulic ring line performance by storing hydraulic power when demand is low and releasing hydraulic power when demand is high. When additional flow is required, the technology transfers hydraulic energy from the accumulators, limiting the need for additional hydraulic pumps to start up. “This system basically eliminates that pressure drop. Instead of having the pumps increase their RPM to boost the pressure in the system, Eco Booster provides that short peak of hydraulic power. Instead of having all of your pumps running all of the time, you can reduce the number of motors and pumps that are running. That’s where the power usage savings come from. That’s where the emissions savings come from,” Mr Verhoef said. The technology is made up of an accumulator skid with four nitrogen pre-charged accumulators, a booster skid and an auto- mated control system. The accumulator is charged by a pressure booster when the ring line flow consumption is low. When charged, the accumulator matches the flow require- ments and demands of the equipment, even when those require- ments and demands exceed the ring line pump’s capacity. The accumulator also stores power during periods of light loading on the hydraulic equipment – a process known as load leveling – leading to more optimal use of the hydraulic pumps. The Eco Booster also dampens the variations caused by sudden power demands, providing instant flow and pressure to the ring line. NOV estimated the savings it could generate from the Eco Booster based on historical power usage data. A rig typically runs six hydraulic pumps 24 hours a day , with each pump consuming 55 kW of power each day. Each pump burns an average of 0.2875 liter/kW used, and NOV calculated 3.23 kg of CO2 and 4.2 g of NOx emitted for every liter of fuel burned on the rig. With the Eco Booster system installed, a rig can potentially run on four generators 65% of the time it is in operation. Over the course of an entire year, this would mean annual fuel savings of 180,072 liters. Emissions-wise, that annual fuel savings would lead to 581 tons of CO2 saved and 756 kg of NOx savings per year. Some countries already impose taxes on CO2 and NOx emis- sions, resulting in an even higher operational cost to the rigs oper- ating in those areas. Even if the system is used in an area without emissions taxes, Mr Verhoef noted that operators can make up the cost of installation in a few years. “If you’re saving tens of thousands a year in fuel costs, this system becomes a relatively small investment for the customer with a pretty good return on investment. The more pumps you can put offline, the better the savings, and the more stable the hydraulic system is, the better you are with emissions.” Since its commercial launch in 2021, the Eco Booster system has been installed on one rig for a major operator in the North Sea. Mr Verhoef said NOV has commitments to install four additional units for separate operators later this year. DC D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 19 H E A LT H , S A F E T Y, E N V I R O N M E N T & T R A I N I N G Offshore medics shoulder increasing burdens amid heightened health focus Industry may need to better support health professionals as pandemic-related testing/documentation and increased needs around rig crews’ mental wellbeing lead to staggering workloads BY STEPHEN FORRESTER, CONTRIBUTOR W hile HSE has long been a core focus area in the oil and gas industry, the offshore health professional – a group that includes doctors, nurses and paramedics, termed “medics” – often gets overlooked. Every rig must have at least one health professional onboard to legally operate, yet industry rec- ognition of the role these individuals play and how critical they are to the overall drilling operation has been limited. Regardless, Highlights Offshore medics have to handle all virus testing and prepare procedures for managing outbreaks on rigs, including how infected individuals are evacuated. Increased focus on rig crews’ mental health and wellbeing demands additional training and longer hours from offshore medics. There is enhanced awareness around the importance of the medic’s role on the rig, but more efforts are needed to better support them and to make sure they know they’re valued. 20 those working in this focus area have stayed the course, often with a noble dedication to doing what needs to be done when no one else will answer the call. The COVID-19 pandemic has helped the industry better understand the burden medics shoulder. Drilling contractors and offshore medics While the offshore drilling industry had previously prepared for and dealt with infectious diseases, the scale and impact of the COVID-19 pandemic still caught the industry off guard, said Dr Robina McCann, Company Medical Director for Seadrill. Drilling contractors had developed protocols around other diseases, like Ebola, but many of those plans never had to be activated. Further, plans were smaller in scope due to the limited area of impact. With COVID-19, perception of the role of the medic shifted, Dr McCann said. “Everyone suddenly understood how important the medic was,” she explained. “It’s not that they weren’t understood before, but rather that people realized that the medic was the person with the specialized skill set that could help them with their problems.” With the pandemic came an onslaught of new tasks for the offshore medic, including handling all virus testing and prepar- ing procedures for what to do if there is an outbreak. Medics have also managed the process for escalation in the event of infection, to whom they should escalate, and how evacuation of infected individuals from the rig is handled. Whether infection occurs is only part of the puzzle, as all tested individuals become part of the ever-growing pile of documenta- M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R H E A LT H , S A F E T Y, E N V I R O N M E N T & T R A I N I N G The COVID-19 pandemic brought with it an onslaught of additional responsibilities for medics on offshore rigs, resulting in workloads that have doubled, triped or even quadrupled. This has pressured some medics to leave the industry, and those who remain say they continue to face diffi cult challenges. tion on the rig related to the virus. On top of COVID-related duties, medics have also been tasked with providing psychological sup- port to the crew — such that some medics now require training in psychology. “Throughout the pandemic, some of our operations people had to maintain quarantining for up to 14 days in a hotel,” Dr McCann said. “We had guys psychologically breaking in that time, having panic attacks from the stress. So, the medics were being asked to step up and help detect and prevent that from happening, as well.” All of this means the medic’s workload has doubled or tripled over the past two years, with little recognition despite the increased risks to their own safety and health. Dr McCann explained that the confluence of these factors has led to burnout not only in the onshore global health workforce in general but also, more specifically, an exodus of talent from the offshore medical profession. “The industry has lost a lot of med- ics,” she said. “Globally, we’ve seen a trend over the last two years that has seen many medics and health professionals just quit. They said they were scared, and they didn’t want to do it anymore. Some didn’t even want to work onshore and left the healthcare sector entirely.” Dr McCann said she hopes that medics get more recognition for the job they do, considering the importance of the work and the personal risk they’re taking. “The industry needs to move away from checking a regulatory box to purposefully and intentionally looking at how critical this role is and making sure they know they’re valued,” she remarked. One approach Dr McCann took to establish better connections with offshore medics was to schedule regular support and knowl- edge sharing meetings . Because the medical professionals on rigs are typically hired via a third-party provider, such meetings didn’t used to take place. She also lobbied to implement high-level per- sonal protective equipment early in the pandemic, as she wanted to ensure that Seadrill did its part to keep medics safe as they worked on the front lines. The company believes that health and safety extends beyond the traditional focus on injury preventio n to include physical and mental wellbeing. Medics play a huge part in that strategy, Dr McCann explained, noting: “We work with the medics to provide a true holistic prevention and promotion model offshore.” However, as the drilling contractor does not have final say on the number of medics deployed to an offshore asset, she also noted that the onus should be on the operating companies to look D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 21 H E A LT H , S A F E T Y, E N V I R O N M E N T & T R A I N I N G “The medics are often the unsung heroes of our industry because they’re almost forgotten when nothing is going wrong. But now, they’ve shown the industry why we have them and why we respect and value their efforts and services.” - Barry Quinn, Noble Corp at how to better support the crew — even if that means having two medics onboard instead of one. Barry Quinn, HSE Director for Noble Corp, agreed there needs to be more focus on health, as well as more emphasis on the role of offshore health professionals. “We want to look more critically at the role they play and what they’ve done, especially during the pandemic,” he said. “The medics are often the unsung heroes of our industry because they’re almost forgotten when nothing is going wrong. But now, they’ve shown the industry why we have them and why we respect and value their efforts and services. These are highly educated, highly experienced professionals, and what they’ve done through the pandemic is vastly different from what they used to do.” Mr Quinn echoed Dr McCann in saying that a major change for offshore doctors and health professionals has been a new focus on mental health and wellbeing, which requires additional train- ing and longer hours. “Through the pandemic, rig crews have suffered greatly,” Mr Quinn said. “Whether they couldn’t get home due to extended rotations or company policy, or because they’re dealing with quarantine protocols and new regulations, everyone has been struggling and fatigued — and the medics have often been on call 24/7 to handle that.” Medics do not get the same break as crew members who work in 12-hour rotations. Unless there are two medics onboard, even a “break” offers another chance for a crew member to ask for some- thing outside the confines of the medic’s office. Fundamental changes in approach to health Injury and mental health are just two pieces of the puzzle. In addition to their standard duties, health professionals have also been tasked with performing extensive pandemic-related proce- dures. Additional layers of paperwork and testing have made the job much more difficult and time-consuming. Even though the volume of work performed by any individual medic is staggering, Mr Quinn said there can be disconnect between what the medic does and what the crew thinks they do. Furthermore, although the medic spends much of their time with the crew and naturally builds a rapport, they are almost always a third-party contractor and can feel left out of specific milestones or drilling contractor goings-on. “The medics, and all the health professionals who support us across the globe, are a core part of our industry,” Mr Quinn 22 explained. “We cannot operate without them, and we sometimes take for granted what they do, especially when things are looking good. But when things are bad, when we really need them, they step into the limelight.” Trust and respect are critical components enabling a medic to effectively engage with the crew. It is also important not to forget the ongoing support of the shoreside medical crews — who assist the offshore medic when necessary and who are sent to shore when there’s an injury or infection that requires immediate attention from doctors and nurses, Mr Quinn said. “The support of our medical team onshore — whether it’s to facilitate testing, develop procedures, provide guidance, or transfer equipment and supplies — is so crucial.” He added that the COVID-19 pandemic has fundamentally changed how the industry will approach medical concerns mov- ing forward. Even though the severity of the virus appears to be abating, its consequences will reverberate through the policies and procedures of operators and drilling contractors for years to come. Companies will now take a much more holistic and long- term approach to health, especially when it comes to transmis- sible viruses. They will also be more vigilant in monitoring and safeguarding crew mental health and psychological wellbeing. “We’re going to do what we do best and take all the collective and cumulative learnings from the pandemic and apply them to do things better,” Mr Quinn said. “We’ve learned a lot — how to be smarter, how to be more efficient, how to take better care of people — and the medics have really played their part in that.” The role of third-party service providers Most drilling contractors do not directly employ the health professionals staffing their offshore vessels. Instead, such indi- viduals are largely engaged contractually via third-party service providers like International SOS (ISOS). ISOS employs thousands of health professionals and deploys a small portion of them to high-risk remote environments, like offshore rigs. Wallace Bruce, Head of Offshore Clinical Operations for ISOS, said he sees the role of the medic evolving even as demand for these highly trained professionals increases, particularly in the oil and gas domain. “Once upon a time, the role just focused on the health of the crew — making sure everyone was doing well,” he said. “Over the past couple years, especially with the appearance of COVID-19, there has been a new focus within drilling contrac- tors’ health agendas on occupational and mental health.” Becoming an offshore medic isn’t easy, as candidates must receive training on core medical skills while also learning occu- pational health, which involves things like health monitoring, water quality management and noise management. “We’re see- ing new attention being given to the preventive side of things, like helping crew members avoid noise-induced hearing loss,” Mr Bruce explained. The COVID-19 pandemic has brought with it an outsize focus on mental health and wellbeing. Challenges for medics stem not just from the virus itself but also from the anxiety of having to work longer hours — often without any change in compensation. This is leading to a new awakening to the criticality of the medic’s role and the need to employ more trained medical personnel. “Most times, the medic is the hub where people go to speak and express M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R H E A LT H , S A F E T Y, E N V I R O N M E N T & T R A I N I N G their thoughts,” Mr Bruce said. “They go there for an open ear. That’s a big way their job has changed.” The pandemic, Mr Bruce continued, has been an ongoing learn- ing experience for ISOS, especially with government regulations, local mandates and company protocols being innately compli- cated and changing frequently. Along the way, the company has improved how it adapts to changing situations, as well as kept tabs on lessons learned that can be used in case another highly contagious virus emerges in the future. Although he hopes that day never comes, Mr Bruce remarked that the company is more prepared than ever. “We’ve had two years to get good at this,” he said. “One of the important things we’ve done is establish documentation that we didn’t have previ- ously, like isolation plans specific to a rig. In the past, there might have been focus on dealing with catastrophic events, having things like triage systems. Now, plans include testing, isolation and how to get an individual off a rig. Those core documents never existed in such detail before.” If there has been an upside to the pandemic, Mr Bruce noted, it was that it changed the perception of health across industries. “Our clients are realizing the importance of health. While medics used to focus on patching someone up or dealing with an emer- gency, we’ve now seen several added layers because of COVID,” he said. “People can now see the true value of what an offshore medic brings to the table, especially in this remote environment.” Many medics remain fatigued, yet many have persisted because they feel called to the profession. “There is an element of selfless- ness in the work, which is a reminder that these are individuals who willingly place themselves in harm’s way for the greater good,” Mr Bruce explained. “These are people who just get things done. They understand what’s at stake, and they know what they signed up for.” View from the rig – an offshore doctor’s perspective Dr Fabian Vicente Castañeda Romero is an emergency doc- tor and physician onboard Seadrill’s West Titania jackup. On any given day, his job pulls him in two distinctly different, but ultimately connected, directions. One is the obvious — the medi- cal portion — which involves treatment of patients, whether for illness, minor injuries or, in the worst case, major sickness or injury requiring escalation and removal from the rig. The other part is the administrative side, which includes medical equip- ment inspections, documentation and record-keeping, inventory of supplies and medication, and so on. Some days pass with the medic only involved in office procedures, while on other days there may be a nonstop line of patients. While there is basic medical equipment on a rig, there is not anything for advanced procedures, nor is there medication for more serious issues. The doctor, then, is also responsible for WELL CONTROL IS WHAT WE DO Wild well continues its tradition of being the global leader in emergency response, well control, subsea operations, and training by offering a range of services to meet the industry’s ever-changing needs. Whether offshore or onshore, wild well responds quickly with experienced personnel and customized equipment to maintain the integrity of a wellbore through innovative engineering solutions. Contact us for all your well control needs. +1 281.784.4700 / WILDWELL.COM H E A LT H , S A F E T Y, E N V I R O N M E N T & T R A I N I N G “Often, what the doctors do is taken for granted, but I hope that people can really learn to appreciate us. Whether you’re onshore or offshore, take a moment to tell your doctor they’re doing a great job, and thank them for helping you.” - Dr Fabian Vicente Castañeda Romero, emergency doctor and physician onboard Seadrill’s West Titania jackup Dr Ruth Zamora Georgee takes care of rig crew members onboard Seadrill’s West Intrepid jackup. rapid situational assessment so that a patient can be quickly sent to shore for proper treatment and care if needed. Dr Castañeda refers to this as being a “first-contact practice,” where simple concerns can be addressed quickly but complicated issues requiring specialized equipment or a team of professionals are sent to shore. “We have defibrillators, oxygen tanks, pain medication and a hospital bed,” he said. “But we can’t do X-rays or lab tests, and we can’t do surgery. If we have a patient with a broken bone, we try to stabilize them and control the damage until we can get them back to shore.” The nature of this process makes offshore health profession- als very clinically apt, able to deal with issues efficiently and with high standards of care so that permanent damage is not sustained. The challenge, then, is workload and availability. With most rigs having only one medic onboard, managing multiple injuries or illnesses at once can become a test of endurance. Dr Castañeda said that on his vessel, many crew members also use him as a pseudo-psychologist, visiting simply to talk about prob- lems and explore thoughts on the state of the world. “For many of the crew members, they know that you’re a pro- fessional, and because you’ve been working and living with them on the rig, there’s a sort of bond,” he said. “This has been going on for years, but after COVID-19, it’s been happening a lot more. We’ve seen a higher incidence, for example, of anxiety attacks and stress-related health issues. It’s been difficult for two years, and some people are struggling to keep it together.” 24 Dr Castañeda confirmed that the COVID-19 pandemic has dramatically increased the workload of offshore medics, with frontline workers taking on the added burden of managing pandemic-related processes and procedures. “Seadrill has taken the pandemic very seriously,” Dr Castañeda said. “They were very aware of what would happen as things got worse, so they’ve done campaigns to encourage crew members to talk to the doctor and get the help they need. But it feels like it never stops, because COVID-19 has come in waves. As soon as you think things are going to slow down, there’s a new variant.” Dr Castañeda is responsible for testing and diagnosis, treat- ment, isolation protocols, proper documentation, and ensuring the infected are removed from the rig via a specialized helicopter service as quickly as possible. Health and safety standards on the rig are still very rigorous, with masking and constant sanitation seen as non-negotiable. While these efforts have been worthwhile, there is also a sense of burnout from the medics involved, with some reducing their hours and some leaving the profession entirely. “It was just too much,” Dr Castañeda explained. “We had all our regular duties, and now all the COVID-19-related duties, as well. It was a big change for all of us, because the workload tripled or quadrupled from what it used to be. It was overwhelming.” While having a second health professional onboard can ease the burden and eliminate the need for 24-hour shifts, not all oper- ators are willing to allot the capital necessary for that expense, and there are no standards that can force them to do so. Although there has been a slowdown in the frequency and intensity of cases offshore, Dr Castañeda urged caution in assum- ing the pandemic — and its related stresses — are over. He also asked for understanding and compassion from the general offshore community, as he and his fellow offshore doctors and health professionals are putting their lives on the line to help the crew stay safe. He has tried to manage not only the challenges and expectations of the crew members but also his own fear that he will not be able to return home to his family. “Often, what the doctors do is taken for granted, but I hope that people can really learn to appreciate us,” he said. “Whether you’re onshore or off- shore, take a moment to tell your doctor they’re doing a great job, and thank them for helping you.” DC M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R UNCONVENTIONAL DRILLING Chesapeake drills U-turn lateral to optimize tight lease space Horseshoe-shaped well was drilled in South Texas using conventional directional assembly BY JESSICA WHITESIDE, CONTRIBUTOR Drilling longer horizontal wells has become a common strategy for extend- ing exposure to promising reservoirs, benefiting well economics by increasing production potential. However, tight lease boundaries can limit the feasibility of this strategy in some areas. After all, how can you drill a 10,000-ft lateral in a lease that’s only 5,000-ft wide? Chesapeake Energy has adopted a way to circumvent such space constraints by drilling a “U-turn” horizontal well. The initial lateral makes a 180° turn to create a second lateral parallel to the first in the same formation. The resulting horseshoe shape effectively doubles the lateral length possible within the lease from a single vertical section. Chesapeake developed its first U-turn well in 2020 on a lease in the Eagle Ford Shale in South Texas. The expe- rience was presented at the 2022 IADC/ SPE International Drilling Conference in Galveston, Texas, on 10 March. Joe Kiefner, Chesapeake’s Category Manager – Completions & Sand, said the U-turn well met production expectations – within a few percentage points of the com- pany’s type curve for the area – and saved money, helping the company to make the most out of a small lease space in a matur- ing legacy field. Calling the project highly successful, Mr Kiefner said Chesapeake has added U-turns to its portfolio of wells and identi- fied 20 to 30 more potential U-turn loca- tions. The company has executed on a couple of those wells and is bullish about the ability of this approach to opti- mize tight leases where drilling the ideal straight long lateral is not possible. “We feel like this is not something that we should just keep internal. This is some- thing that is better for the industry, and I think is better for our ability to utilize the space that we have,” Mr Kiefner said. Chesapeake is not the only company to try the U-turn approach. Shell successfully drilled a horseshoe well in the Permian Basin in 2019 using a rotary steerable system. Chesapeake bills its 2020 U-turn well as the first such application in South Texas and the first using a fully conven- tional directional assembly, rather than a rotary steerable system. Selecting the trajectory Chesapeake tested the U-turn lateral strategy with its service providers as a potential tool to improve well economics and options within highly developed acre- age blocks in the Eagle Ford Shale. The test site was a 5,000-ft-wide lease that contained an existing producing well. The U-turn maneuver on the new well resulted in a completed lateral length of 9,200 ft (4,900 ft of treatable lateral in one arm of the U and 4,300 ft in the other). According to Chesapeake, this trajectory significantly improved well economics by “utilizing a horizontal turn as a hydrocar- bon pathway, rather than an additional vertical section from a new well to gain the equivalent treatable lateral length.” The measurement of treatable length does not include the U-turn portion of the well. To maximize the in-unit foot- age available for the lateral length, the company drilled the curve section into the adjacent unit and did not frac that sec- tion. Shell reportedly also elected to omit curve stimulation on its 2019 horseshoe well. Chesapeake’s case study report noted that to frac the curve would be “capitally inefficient due to the turn portion of the lateral being drilled in the direction of maximum horizontal stress, which would not optimally grow hydraulic fractures perpendicular to the wellbore.” Planning pays off In some cultures, the horseshoe is a symbol of good luck, but developing the horseshoe-shaped well on Chesapeake’s Eagle Ford lease took more than just luck; it took lengthy planning, modeling and simulations before drilling began. That was followed by real-time updating of fac- tors such as torque and drag (updated at 1,000-ft intervals). Cumulative degrees and Directional Drilling Index (DDI) values were among the key elements considered during planning and monitoring to understand the tortuos- ity associated with the U-shaped path. The team’s DDI assessment found many successfully drilled and completed wells with complex trajectories that had higher DDI values than what was expected for the U-turn, increasing confidence in their abil- ity to execute the unusual path. “If it doesn’t work on paper, it’s probably not going to work in real life. But all of our models from the drilling and comple- tions standpoint showed that it worked on paper. It was just on us to go execute,” Mr Kiefner said. The team used Chesapeake’s histori- cal base model for the area to guide its expectations for the well and applied the company’s standard best practices to miti- gate risks. Their due diligence included drafting contingency plans for various scenarios, including developing a back- up option to continue development if the U-turn failed. “At any point, if things went sideways, we could have stopped that plan and cased out a single 5,000-ft lateral and just drilled another vertical section,” Mr Kiefner said. “We had planned for that contingency and permitted it as such.” Adjusting in real time Fortunately, they didn’t need to acti- vate that fallback option as the U-turn project went almost entirely according to plan, despite some on-the-fly adjust- ments required to motor and mud weights. Surprisingly, the added tortuosity of the U-turn did not have a very large impact on operations, said Riley Schultz, Drilling Engineer for Chesapeake. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 25 UNCONVENTIONAL DRILLING Top: Speaking at the 2022 IADC/SPE International Drilling Conference in Galveston, Texas, in March, Chesapeake Energy’s Joe Kiefner (left) and Riley Schultz discussed the company’s experience drilling its fi rst horseshoe- shaped well in South Texas. Bottom: The successful U-turn well in the Eagle Ford resulted in 9,200 ft of treatable lateral in a lease space that was only 5,000 ft wide. Le as Co m ine ple 5,000 ft lease space tio 4,3 00 ns Ha ft t ing Pro ft t re at lin at du Executing completions rd re E x ist 4,9 00 9,200 ft treatable lateral e L ab le ce ab le r lat e lat er a l er “Casing went down just like we expect- ed, within 10% of the expectations, as far as final hookloads go. It was a relatively smooth operation from the drilling side and went according to our pre-planning expectations.” As the team monitored drilling prog- ress, they paid close attention to the tor- tuosity plots – wary of the potential for excessive doglegs – and made changes as needed to meet their motor yield expecta- tions in the turn. From an initial 7-in., 1.93° bent housing mud motor, they followed up with a 2.12° bent motor to help build the curve. After drilling 1,000 ft of the turn, 26 ity even while drilling in the azimuth of maximum horizontal stress. “After we had raised the mud weight there, for the rest of the well we saw no more signs of hole instability,” Mr Schultz said, calling this mud weight lesson a big takeaway from the project and something that Chesapeake has since applied to its work on other U-turn wells. al the rotation required to stay on plan was deemed too high, and they switched to a 1.83° motor for the rest of the well, meet- ing their pre-drill expectations for rate of penetration, required weight on bit, and pressures. The team also decided to adjust the mud weight after seeing indications of hole instability while making the turn, particu- larly when they got almost exactly parallel with the maximum horizontal stress. They raised the mud weight from 10 ppg to 11.3 ppg based on an area-specific, real-time mechanical earth model that showed the higher weight would maintain hole stabil- On the completions side, making sure that the wireline and coil tubing was able to convey around the turn was the team’s main concern. Mr Kiefner noted they had run more than 25 wireline simulations and used several software systems to make sure everything checked out for factors such as toolstring weight and length, run-in-hole and pull-out-of-hole speeds, and friction or stretch coefficients. The subsequent com- pletions activities went so smoothly that it even felt a little anticlimactic, he said. “From an execution standpoint, wire- line and coil tubing, there were no issues whatsoever. Anecdotally, the company (on location) said that had we not told them there was a downhole turn, they wouldn’t have known it was any different – it went that smoothly.” The team also monitored the adjacent legacy producer throughout the project to ensure there was no adverse impact. “We didn’t see anything that caused us any level of concern from a fracking stand- point, but it’s because we planned for that and we spaced off of it accordingly,” Mr Kiefner said. DC For more information, see IADC/SPE 208801, “Successful Planning And Implementation Of First South Texas U-Turn Lateral.” M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R UNCONVENTIONAL DRILLING Automated geosteering algorithm shows promising ability to match human geological interpretations H&P undertakes field testing in Haynesville to validate technology that supports more efficient analysis of target formation BY JESSICA WHITESIDE, CONTRIBUTOR The developers of an automated geosteer- ing algorithm aim to take the more mun- dane tasks related to the monitoring of geological data and generation of geologi- cal interpretations off the plate of the geo- steerer, so they can apply their expertise to more complex challenges. Geosteerers interpret real-time geologi- cal data from downhole logging-while- drilling tools, often a gamma ray module, to help drilling crews make directional changes for a better path to the pay zone. Geosteering analysis is particularly impor- tant in two key areas of wellbore place- ment: achieving the optimal landing point and guiding the lateral through the target formation. The geosteering process is labor inten- sive, requiring continuous monitoring and interpretation of data that can limit a remote supervisor to watching only two or three operations at a time. But what if that one expert could simultaneously monitor even more wells, with less stress and greater efficiency, through the appli- cation of technology? That thought was one impetus for the automated geosteering algorithm that Helmerich & Payne (H&P) developed and field-tested on two Sabine Oil & Gas wells in the Haynesville Shale. The geo-correlation algorithm is designed to expand the geosteering capac- ity and efficiency of remote operations centers by using automation to handle routine monitoring, as well as survey updating that requires no immediate deci- sions. This would free up geosteerers to 28 focus on the most challenging intervals in each well where meaningful decisions are required, such as steering changes or choosing between multiple interpretations when enough data is ready for review. “It’s not that we want to replace some- one or remove their job. It’s that we want to make sure that person can be more effec- tive, watch more wells and leverage their talents in a better way,” said Marc Willerth, H&P Technology Development Manager. He discussed the algorithm and its field testing at the 2022 IADC/SPE International Drilling Conference in Galveston, Texas, on 10 March. Minding the misfits To help the geosteering team identify the best pathway through the formation, the algorithm uses a stratigraphic heat map to visually represent interpretations of geological data, including stratigraphic depth and gamma ray signature measure- ments. The heat map’s coloring indicates the probability of encountering rock that matches type log expectations. Areas of low probability (high misfit) appear as yel- low, while those with higher probability (low misfit) are preferable and use darker tones. “The theory here is that if you build a path through these dark zones, this com- bines both what rock you are likely mea- suring from a geology perspective with what rock you are likely measuring from a geometry perspective,” Mr Willerth said. Validating the system H&P had previously tested the algo- rithm against historical drilling data, but the Haynesville project provided the first opportunity to apply the algorithm to the real-time workflow of a drilling operation as crews developed the lateral sections of the two subject wells. For this field trial, the team intentionally chose an area featuring benign geology with no major faults or dips so it would lend itself to straightforward interpreta- tions. “Basically, if we couldn’t steer this with our algorithm, we were going to struggle just about anywhere,” Mr Willerth said. “But we thought it was a good opportunity to give it a try, and it’s also potentially your highest value place for an early automa- tion solution. If you can take the simplest things and allow expertise to be focused on the more complicated areas, that in and of itself is already a win.” The field deployment offered a head-to- head comparison of the interpretations of traditional geosteering services and the automated system, which was periodi- cally monitored by a geo-professional. The team’s goal was not only to see if the algorithm could produce results similar to a human, but also to quantify how much effort would be required from a human to ensure that the algorithm’s interpretation was reasonable. The team checked the interpretations for three primary factors: estimated land- ing point, modeled geologic structure throughout the lateral, and the estimated footage of the wellbore in the target zone. In both test wells, the automated system estimated the same landing point tie-on and percentage in zone as traditional geo- steering. “We were excited to see that there was broad agreement in the key variables we were testing,” Mr Willerth said. While the algorithm’s estimated bed dips across the lateral also closely matched those from the human interpretation, there were some minor issues in which the algo- rithm added irregular artificial structures – a hump in the first well and some jagged cusps in the second – that required inter- vention through the addition of control points to create a more realistic formation shape for the area. M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R UNCONVENTIONAL DRILLING Defining control points To address the unusual hump depicted in the first well, for example, the team set control points of known stratigraphic depth and known measured depth to force the algorithm to find a path through that point. Flattening the cusps in the inter- pretation of the second well required four control points. The ability for a geologist to intervene like this to address anomalies in the automated interpretation is analogous to checking and fixing the work of an assistant, rather than having to do all the work yourself. “Instead of having to maintain an inter- pretation constantly, you can just verify what is going on and intervene one or two times to produce this same type of inter- pretation,” Mr Willerth said. The team considered the number of con- trol points to be a marker for the amount of manual effort needed to reach an accept- able automated interpretation. They esti- mated it would take a geo-professional five to 10 minutes to update a typical control point. Compared with the large number of monitoring updates required in tradi- tional geosteering, relating to potentially hundreds of surveys, the low number of interventions required in the test wells represents the removal of “a huge amount of human effort,” Mr Willerth said. “This suggests that we could poten- tially dramatically expand the capability of human geologists to monitor more and more wells without compromising service quality,” he said. Refining the technology The team plans to expand testing of the algorithm to basins with more complicat- ed geology to ensure that the results can be replicated over a wider range of geo- logical conditions. Since the completion of the initial field trials, the company has modified how the algorithm analyzes the heat map, in order to reduce the amount of manual intervention required for realistic results. After running the Haynesville test well data through the updated algorithm, the need for control point intervention dropped to none for the first well and just two control points for the second. H&P also expanded the algorithm’s capacity to accept different forms of human intervention, in addition to con- Click here to watch a video interview with H&P’s Marc Willerth from the 2022 IADC/SPE International Drilling Conference on a separate paper he presented, “Fifty Ways to Leave Your Wellbore: An Honest Look at the Causes and Costs of Unplanned Sidetracks.” trol points. The new functionality would enable a geologist to tell the algorithm to insert a fault of a certain size at a certain location, for example, to reflect their seis- mic knowledge of the area. The purpose of the algorithm is to enable the human to do the most important things – and not do the unimportant things, Mr Willerth said. “Selecting where a fault is, selecting the size of the fault – this is an important thing for a geologist to be analyzing and putting in there. Saying the formation has continued along the same dip for another 500 feet, saying there has not been a major change, is something that you might as well have a computer look at, and let the human plan for the next well.” H&P is also considering developing other features for the algorithm, such as the ability to actively alert the geosteering supervisor to changes in certain metrics. “That really expands how much a per- son can watch, because now you know when to look at it as opposed to just check- ing every so often,” Mr Willerth said. “It’s nice to only have to have a human inter- vene five times. It’s even nicer if you can tell them when they likely would need to intervene.” DC For more information, please see IADC/SPE 208697, “Field Validation of an Automated Geosteering Algorithm in the Haynesville Shale.” “It’s not that we want to replace someone or remove their job. It’s that we want to make sure that person can be more effective, watch more wells and leverage their talents in a better way.” - Marc Willerth, Helmerich & Payne D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 29 OFFSHORE TECHNOLOGIES & MARKETS Higher oil prices foster optimism for recovery in offshore drilling market Industry is hopeful that investments in offshore E&P will grow as geopolitical events put new spotlight on energy security BY STEPHEN WHITFIELD, ASSOCIATE EDITOR T he offshore drilling sector has had a challenging few years. When energy demand fell off rapidly at the onset of the COVID-19 pandemic in 2020, operators’ appetite for investing in offshore projects also dropped off dramatically. However, in recent months, as production levels have increased again to pre-COVID levels and with the oil price continuing to recover, there is renewed optimism in offshore E&P activity among drilling contractors. Highlights More stable oil prices expected for the forseeable future, combined with lower threshold for offshore projects to be profitable, will likely add opportunities for contractors to put rigs back to work. However, dayrates are still slow to increase, and significant reinvestment into rig fleets is unlikely in the near term. Growing profitability will remain a key priority for the service sector. Amid geopolitical instability, a focus on licensing and exploration could help countries achieve better energy security. 30 Another factor at play is that geopolitical events have sent oil prices shooting upward. Brent crude price reached a 2022 peak of $127.98 on 8 March, two weeks after the onset of the conflict in Ukraine. Although that price has since fallen to $111.16 as of 17 April, overall oil prices are still at a level that encourages sig- nificant investment. Moreover, the war in Ukraine highlighted for many countries the need for energy security, encouraging them to reduce their reliance on imports. This could lead to a more favorable environment for offshore development, some drilling contractors anticipate. “The industry saw post-pandemic recovery with a clear uptake in the market,” said Eirik Reinertsen, Chief Commercial Officer at Stena Drilling. “The offshore industry has already and, we believe, will continue to see an uptake in activity. That should see increased investment, both in renewables and in the oil and gas sector. I think that the future looks brighter for the energy sector as a whole.” While the Ukraine conflict created spikes in the oil price, it had been on a steady upward trajectory for the past two years – Brent crude rose from a post-downturn low of $24.81 on 19 April 2020 to $94.05 on 23 February 2022, the day before the Russian invasion. With the oil price increasing and operators looking to ramp up drilling activity, drilling contractors are seeing more opportuni- ties to get their rigs back in the market. “We’ve seen some increased market inquiries and tendering starting around the end of last year,” said Clay Coan, President of Northern Offshore, whose fleet of jackups are working in the Middle East. “Operators are showing an increased willingness M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R OFFSHORE TECHNOLOGIES & MARKETS The Stena DrillMAX drillship is one of two Stena Drilling rigs working in the Guyana/Suriname Basin , one of the most notable hotspots in the offshore sector . to add additional bidders to their approved list of rig contractors. That response, as much as anything, is indicative of the operators’ thoughts on the market. When you see them inviting new bidders to tender, then you know that the market’s improving – rig supply is decreasing, so they’re looking to expand the pool from which they’re choosing .” Deepwater exploration Operators have also established what Mr Reinertsen termed a “new baseline oil price” for triggering investment that is lower than what it had been prior to the downturn. A key enabling fac- tor for this has been the cost reductions that the service sector undertook in the wake of the 2020 downturn. The lower baseline price means that the threshold needed to make brownfield and greenfield deepwater projects profitable is also lower. For deepwater, better economics are then leading more opera- tors to move forward with FIDs on major projects. Mr Reinertsen said he expects the oil price to remain at a more stable level for the foreseeable future, which should encourage increased long-term investment in deepwater. “To get that market balance, we need to see a healthy oil price over a long period of time,” he said. “Ultimately, our concern is, how do we grow great profitability within the offshore drilling sector? As a company, we believe that creating long-term rela- tionships with major operators, working with them and adapting to uncertainty can help remove some of the obstacles you face.” One approach is to adjust contract terms. While the convention- al dayrate contracting model days are not over , he thinks incor- porating KPI-based incentives and market-based adjustment systems within contracting terms could help drilling contractors and operators hedge against pricing uncertainty. “With (Stena) being a privately held independent drilling contractor, we can obviously afford ourselves some flexibility in coming up with commercial solutions, and we have proposed several different models where we could integrate on services or take over some services that would traditionally fall under the remit of the operator. While I think the most likely solution going forward is the dayrate model, we’re going to continue offering integrated bolt-on services tailored to each client,” Mr Reinertsen said. To help advance these goals, Stena Drilling has also worked in the area of smart contracts. Last October, the company announced a partnership with blockchain technology startup company SmartChainServices . The companies are working on a smart contract solution that automates the payment cycle, as well as new contractual models based on KPIs such as drilling speed, carbon intensity and fuel usage, all of which can be automatically validated . D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 31 OFFSHORE TECHNOLOGIES & MARKETS The Stena Carron drillship is also working in the Guyana/Suriname Basin. Over the past year, Stena Drilling has secured new contracts and contract extensions for its rigs in Guyana/Suriname and on the UK Continental Shelf. These three KPIs will be critical in helping the industry lower emissions from its offshore drilling operations. This means the offshore sector needs to deploy low-carbon drilling solutions in the immediate future, particularly as operators focus on reach- ing their emission-reduction targets, Mr Reinertsen said. To that end, Stena Drilling announced in January 2022 that its fleet had achieved ISO 50001:2018 accreditation , which specifies require- ments for establishing, implementing, maintaining and improv- ing an energy management system . The intended outcome is to enable an organization to follow a systematic approach in achieving continual improvement of energy performance and the energy management system. “It’s important that we continue to improve our practices, and that means improving our drilling techniques to reduce the time spent on a well. The less time you spend on the well, the fewer emissions you have. I think most major drilling contractors have been moving in that direction,” Mr Reinertsen said. Stena Drilling has also been focusing its activities on Guyana, with the Stena DrillMAX and Stena Carron drillships working in the area. The Guyana/Surname region has been a major offshore hotspot in recent years, dominated by ExxonMobil through a slew of discoveries since May 2015, most recently with Fangtooth and Lau Lau, announced in January. Other operators are also starting to make progress there. Following positive results from the Kawa-1 exploration well, CGX Energy and Frontera Energy announced in February that they would focus on exploration at the Corentyne Block offshore Guyana in 2022. “I think anyone in the offshore drilling industry would agree that what we’ve seen coming out of Guyana and Suriname are very promising results that have already led to a lot of activity,” Mr Reinertsen said. “The area’s certainly a hotspot, and we all feel optimistic that this high level of activity will continue.” 32 Stena has also recently picked up various contracts for its two semisubmersibles on the UK Continental Shelf (UKCS). While operator investment in the region is still low, Mr Reinertsen said he believes interest could improve in the coming years. “We’re seeing more work manifest on the UKCS instead of being postponed year-on-year. That’s a cause for optimism, to actually see more activity. We’ve seen some of the bigger fields owned by the larger operators now going through the approval process internally, and there have been rumors that several operators are relooking at the figures to see what’s feasible. That’s another reason to be optimistic.” Developing mature assets In recent years, the UKCS has become somewhat of an after- thought in the North Sea drilling landscape, especially compared with the prolific Norwegian sector. The bulk of conversation on the UKCS has centered around decommissioning, plugging and abandoning mature assets. However, things are changing with the Ukraine crisis highlighting the need for energy security, both in Europe at large and particularly in the UK . The latter imported 37% of all oil and gas consumed in 2021, according to the latest Business Outlook released on 29 March by the Offshore Energies UK (OEUK), formerly Oil & Gas UK. Although the UK government has said it is still committed to developing renewable energy for a low-carbon future, the coun- try is encouraging more short-term oil and gas exploration and development to help reduce its reliance on foreign imports. “Given all that’s going on, the industry has a very important role to play,” said Deirdre Michie, CEO of OEUK. “What’s become clear is that energy security is a matter of national security. We can be part of the solution here.” The group’s Business Outlook noted that the number of approv- als for new oil and gas projects on the UKCS has been falling M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R OFFSHORE TECHNOLOGIES & MARKETS consistently through the past decade . One reason is the maturity of the basin has limited the investment opportunities under con- sideration. Additionally, operators and investors have been con- cerned about the level of political and public support for offshore exploration. Only 80 million BOE of new UKCS resources were approved for development in 2021, of which 35 million BOE were for gas fields. Developing these reserves will take approximately $975 million (£750 million) of new capital investment from opera- tors, according to OEUK. “We know the basin itself is in decline, and we need to actively manage this by investing in new projects, as well as existing ones. If we don’t, we’ll be even more reliant on other countries – up to around 80% of our gas and around 70% of our oil (by the 2030s). That’s a heavy exposure,” Ms Michie said. With 10 new fields set to start up in 2022 and early 2023, OEUK expects sufficient production to come on stream to maintain out- put in line with 2021 . Combined with the fields that started pro- duction in late 2021, this will result in approximately 450 million 1,80 1,800 0 1,600 0 1,60 ToToTotatatal l Approved Appr oved New Re Reserves serves (boe (boe)) New reserves on the UKCS are expected to reach its highest level this year since 2018. With the UK government pushing to lessen its reliance on imported oil and gas, short-term production in the region could increase. Source: NSTA, Offshore Energies UK 1,400 0 1,40 1,200 0 1,20 1,000 0 1,00 8000 80 6000 60 4000 40 2000 20 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022E 2022 E BOE in new reserves (split roughly 50/50 between oil and gas) and peak production rates of around 250,000 BOED. This would offset declining production from existing assets, according to OEUK. Further, the group is forecasting a 10% increase in exploration and development drilling on the UKCS this year compared with last year , as well as a 5% increase in UKCS oil and gas produc- tion over the next two years. The rise in production is attributed to operators accelerating smaller work scopes and launching brownfield infill drilling campaigns to extend the productive life of mature assets. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 33 OFFSHORE TECHNOLOGIES & MARKETS All four of Northern Offshore’s jackups, including the Energy Emerger (pictured), are working in the Middle East. Company President Clay Coan noted an increase in tendering activity in the region during the second half of last year. Production is still expected to decline in the long term, of course. Based on current levels of investment, the expected rate of decline is between 7% and 10% by the end of the decade. However, it’s important to note that the rate of decline could jump to 15% if no new investments are made in the next two years . A focus on new licensing and exploration can help balance this decline in the coming years, with OEUK emphasizing the need for a new licensing round to be announced this year. Its Business Outlook shows that operators are planning nearly $26.13 billion (£20 billion) in CAPEX on the UKCS from 2022 to 2026. New proj- ects under consideration for development could bring up to $4.57 billion (£3.5 billion ) annually in new investments if approved, unlocking around 300 million BOE per year in new reserves. Contractors not feeling full benefit yet Like with Stena Drilling, Mr Coan with Northern Offshore sees an upward trend for the offshore drilling sector . While it is unclear 34 what kind of long-term impact the Ukraine conflict will have on the oil price, Mr Coan said he feels the price has settled to a point that will encourage operator investment in new projects. “Speculating the future of oil prices will always be difficult, but I do think it’s reasonable to expect that prices will remain at a level that will continue to prompt investment by our customers. Whether that means oil prices settle to the $70-80 range or they remain north of $100, I don’t know, but I am confident they will be at a level that encourages operators to go out and drill more wells,” he said. However, drilling contractors have yet to feel the full benefit of that upward trend – dayrates are still not at a high enough level to enable significant reinvestment into upgrading rig fleets, and existing terms for contracts signed earlier in the oil price recovery timeline have not been adjusted to reflect higher prices. “When oil prices crash, some of the oil companies are quick to ask their service contractors to adjust their rates downward accordingly. When oil prices increase significantly, the oil com- panies generally have to go through a budget cycle before funds are approved to tender for new rigs,” Mr Coan said. “The tendering process itself can take many months before a contract is awarded. So, while the market is improving, it hasn’t yet had a material impact on the number of rigs contracted or market rates. We often say that we take the slow elevator up and we take the stairs down .” The downturn also forced drilling contractors to stack or retire a number of rigs . However, Mr Coan said it is unlikely the recov- ery will spur a newbuild cycle anytime soon. “The severity of the most recent downturn is probably going to limit investors’ appetite for newbuilds. There are just too many rigs out there that are still available that need to be put to work first. It is both faster and cheaper to get those rigs up and running than it would be to invest in a newbuild,” he said. Northern Offshore’s fleet of four jackups are currently work- ing under long-term contracts in the Middle East. The Energy Embracer, Energy Enticer and Energy Edge are working for Qatar Petroleum through Q4 2023, Q3 2024 and Q4 2024, respectively. All three contracts began in either late 2020 or early 2021. The fourth jackup – the Energy Emerger – is working for an unnamed operator offshore the UAE through Q4 2022. That contract started in mid-2021. Three of those four contracts were awarded prior to the oil price downturn, while the contract for the Energy Emerger was announced in October 2020. Since then, operators in the offshore space and particularly in deepwater have been hesitant to award long-term contracts . Mr Coan said he’s hopeful that, as oil companies’ confidence in a sustained high oil price environment grows, more long-term contract opportunities will become available. But for now, when making strategic contracting decisions, drilling contractors must decide whether to bid low enough to secure short-term work or hold out for longer-term contracts with improved dayrates. “Each contractor has their own strategic objectives. For us, we had to have the long-term contracts. We couldn’t justify taking delivery of a newbuild rig and investing the money required to deliver the rig to our customers for short-term work. Therefore, we had to be selective for the right opportunity to take delivery of our rigs and put them into the market.” DC M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R OFFSHORE TECHNOLOGIES & MARKETS Case study: Chevron deploys below-tension-ring MPD to drill highly depleted reservoir in GOM potential benefits include quicker leak- off detection and reaction to losses, safer determination of drilling parameter and mud weight adjustments, greater control of pressure to prevent borehole instability, and more efficient cementing of produc- tion liner. Strategy helped to reduce risk for fluid loss and decreased mud weight requirements Choosing the right equipment BY JESSICA WHITESIDE, CONTRIBUTOR Complex deepwater drilling environments can become even more challenging as res- ervoirs mature. Pressure concerns tied to high levels of depletion increase the poten- tial for fractures, downhole fluid loss and well control hazards. To reduce these risks and associated remediation costs, Chevron has found success deploying drillships outfitted with customized surface-back- pressure managed pressure drilling (MPD) systems in mature reservoirs in the deep- water Gulf of Mexico. At the 2022 IADC/SPE International Drilling Conference in Galveston, Texas, on 9 March, Ken Vaczi, Deepwater Drilling Engineer for Chevron, described the com- pany’s experience with its first two deep- water BTR MPD systems in the Gulf of Mexico during a four-well campaign. The company has since expanded its use of the technology to other operations in the region. BTR (below tension ring) refers to a sur- face-backpressure MPD system in which the rotating control device (RCD), used to control pressure during drilling, is placed near the surface in the riser but below the telescopic joint. By maintaining near-constant bottom- hole (or other target location) pressure, this MPD approach helps the operator to navigate narrow drilling margins. Other Ken Vaczi, Deepwater Drilling Engineer for Chevron, described the company’s experience with two deepwater BTR MPD systems in the Gulf of Mexico. He was speaking at the 2022 IADC/SPE International Drilling Conference in March. Chevron decided to apply BTR MPD to the four-well campaign after experienc- ing major downhole fluid losses during an earlier conventional drilling operation in highly depleted Gulf of Mexico reservoirs. Modeling predicted that the new cam- paign could face similar conditions, which could trigger downhole losses and make it difficult to reach planned total depth and achieve other well objectives. Through MPD, the team hoped to miti- gate the potential for thermally induced fractures and differential depletion, with some sands in virgin condition and others with high depletion levels up to 8,000 psi – the highest level of depletion that Chevron has drilled in the Gulf of Mexico to date, Mr Vaczi said. Smaller flow meters tend to be standard on MPD packages, which concerned the project team in light of the erosional veloc- ity of the mud expected to flow through the meter, especially in combination with some of the lost-circulation material they anticipated using for the project. “To fix the problem, we elected to do a two-size implementation,” Mr Vaczi said. “The larger flow meter could be used for the larger hole sections and the smaller flow meter could be used in the smaller hole sections where the flow rates were less.” They also included a dual junk catcher to prevent large debris from plugging the automatic chokes and disrupting the abil- ity of the MPD system to automatically manage surface backpressure. When one catcher was plugged, they could switch to the redundant catcher on the fly with minimal impact to operations. While Chevron had used other forms of surface-backpressure MPD around the world, the four-well campaign marked its first use of the BTR MPD variant on deep- water floating rigs in the Gulf of Mexico. The company worked with MPD equip- D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 35 2022 IADC HSET & Sustainability CONFERENCE & EXHIBITION 20-21 SEPTEMBER 2022 HYATT REGENCY HOUSTON WEST HOUSTON, TEXAS SILVER SPONSOR www.iadc.org/event/ 2022-iadc-sustainability-conference-exhibition For more information, contact IADC by phone at +1.713.292.1945 or via email at iadcconferences@iadc.org ment providers and two drilling contrac- tors to place permanent BTR MPD systems on two drillships. Using BTR MPD in the Gulf of Mexico required the submission of a new tech- nology plan to the US Bureau of Safety and Environmental Enforcement. Adding MPD equipment to the rigs fundamentally changed the way some operations, such as tripping, were performed. This neces- sitated the creation of more than 40 new mandatory rig-specific procedures for each of the rigs and the development of classroom, simulator and onsite refresher training. Before putting a single piece of MPD equipment on the rigs, the team conducted a five-step review that included a hydrau- lics check, onshore flow test, RCD durabil- ity test, HAZID/HAZOP workshop, and a complete logic system review of the MPD control system. Achieving objectives Their careful planning paid off. Mr Vaczi called the application of deepwater MPD highly successful, with all wells drilled to total depth with no losses through the high depletion intervals or the tight margins of the intermediate section. “We had no major safety incidents throughout the implementation and exe- cution of MPD, and all systems performed as intended.” Compared with offset wells drilled con- ventionally, MPD successfully reduced equivalent circulating density (ECD) by 0.5 ppg. Dynamic pore pressure tests per- formed on all wells enabled the team to further reduce mud weight while remain- ing within the safe parameters identified by borehole stability studies conducted prior to the startup of operations. They also successfully ran and cement- ed all production liners in the campaign using MPD and reduced cementing ECDs by almost 1 ppg compared with conven- tional operations. “This is critical to the success of the cementing job in achieving zonal isolation in these intervals,” Mr Vaczi said. DC For more information, please see IADC/SPE 208771, “Implementation of MPD Systems in the Deepwater Gulf of Mexico to Drill Highly Depleted Reservoir Sections.” 36 M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R DRILLING & COMPLETION VIDEOS • DEPARTMENTS Workforce development goes hand in hand with industry’s digital transformation The digital transformation is critical to building and main- taining the workforce of the future, so companies must enhance their understanding of digital systems if they want to attract and retain young talent, said Brett Schellenberg, Director of Controls and Automation at Nabors. In this video from the IADC Drilling Engineers Committee (DEC) Q1 2022 Technology Forum, held in Houston on 30 March, Mr Schellenberg discusses how the role of the driller is changing amid the digital transformation, as well as the challenges that drilling contractors face in an increasingly digital ecosystem. Watch the video for more information. Attracting young talent will require oil and gas companies to think outside the box The oil and gas industry is looking to new avenues to find the workers needed in order to adapt to a changing technical landscape, with companies rethinking the skillsets they need to thrive in the future. Speaking from the IADC DEC Technology Forum in Houston in March, Willie Thompson, Senior Manager, Early Career Engineering at Hess, discusses the external and internal forces that have changed how the industry looks for new talent. Mr Thompson also discusses the “attributes for today” that companies find necessary in young workers, as well as the ways in which Hess is investing in talent development. Low-carbon future will require industry buy-in, technology enablers Examining the causes and costs of unplanned sidetracks can help companies better mitigate future risk ‘Unconventional’ systems could help to scale geothermal drilling H&P introduces solution to optimize power usage, reduce fuel consumption at the rig Patterson-UTI develops real-time alert system to improve decision making at the rig site Technological disrupters could lead to a rethinking of the well construction business model D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 37 OPTIMIZING WELL INTERVENTION Software applies real-time data, automation to redefine wireline sleeve shifting operations Using available instrumentation, workflows can be streamlined to reduce reliance on individual experience, improve overall reliability BY STEPHEN WHITFIELD, ASSOCIATE EDITOR The success of conventional wireline intervention shifting typically depends heavily on the field engineer’s experience and knowledge. Any error in that individu- al’s judgment could lead to nonproductive time (NPT), or even total failure. To help redefine the selective shift- ing workflow, Schlumberger has devel- oped new surface acquisition software. It leverages available instruments and uses an automated real-time data collection system to streamline and simplify pro- cedures, eliminating or reducing human error and reducing the burden placed on the field engineer for post-job deliverables. “When you’re operating the shifter, you have to rely a lot on the engineer’s judg- ment. It’s pretty time consuming because we have to do a lot of operations for this, and if you somehow get things wrong or take a wrong step, you have to go back. That can take a lot of time,” said Jisheng Li, Software Engineer at Schlumberger, during a presentation at the 2022 SPE/ ICoTA Well Intervention Conference in The Woodlands, Texas, on 22 March. In a conventional shifting operation, he said, it is possible to miss the collar joint, waste considerable time finding the loca- tion, or even perform the shifting opera- tion at the wrong location. The software correlates the completion mapping depth based on the operator-provided comple- tion table, creating a channel similar to a casing collar locator (CCL) recording, thus enabling side-by-side correlation directly on the depth log. The software also renders details of the well completion mapping and shifting tool string on the same graph 38 for visualization of the relative locations of the toolstring, the shifting target and the collar joints in real time. The software allows users to initiate an automated seeking function to locate and latch the shifter key onto the target pro- file within a few millimeters in the well, including extended-reach drilling and wells intervened on a floating installation. Critical data from each user operation is logged and displayed on a two-dimension- al plot and customized table, and users can generate operations reports that include all relevant data. The software addresses five key chal- lenges in sleeve shifting operations: pre- cise depth control for toolstring convey- ance, target profile seeking and latching, winch seeking, operations reporting, and troubleshooting and reliability improve- ments. To address depth control, Schlumberger developed a two-step correlation process based on completion mapping that it embedded into the software as part of the shifting operation workflow. In the first step, the software imports a completion mapping profile into the software system and creates data channels and logs that can help real-time correlation on an acqui- sition log. Then, it implements the depth control user interface that integrates both completion mapping and toolstring details with real-time movement for visual cor- relation and depth control. Mr Li said this process allows users to monitor, in real time, both the toolstring position and speed in the well. It also sim- plifies the operation of conveying the tool to the desired target depth, eliminating the risk of missing completion joints. For the target profile seeking and latch- ing challenge, Schlumberger embedded tool control automation into the software. This enables automatic seeking, latching and shifting of the target. The user inputs operational parameters, and the software then controls the downhole tool operation. In the winch seeking operation, the software has what Schlumberger calls a “profilometer mode,” where it estimates the shifter’s open diameter. In this mode, the shifter force will change accordingly with the inner diameter (ID) of the sections. The well ID can be estimated from the shifter pressure, and when the toolstring is pulled by the winch to seek the target, the open diameter is computed from the force measurement. By comparing the shifter open diameter to the known profile IDs of different sections, users can tell where the shifter is located inside the profile and if it is in the correct latch location. To improve troubleshooting and reliabil- ity issues, Schlumberger focused on the most common cause of downhole shifting toolstring malfunctions – clogged sole- noids, which often result in the inability to control hydraulic pressure in the system and the tool modules not operating proper- ly. The software automates the process of unclogging the solenoids by turning them on and off while the motor is running, building up enough pressure in the tool to flush debris away from the solenoids and resume normal tool functionality. To address client reporting challeng- es, an automated real-time reporting tool was incorporated into the software. A data interpretation module correlates the tool’s operational status with relevant data channels from the downhole tools, interpreting and recording key operational events with real-time measurements. The software tabulates the events and related information in chronological order during the job. This logging table is available to users in real time and after the job. “We wanted this software to provide real-time integration of all the events that go on during a shifting operation, where it can automatically put all of these events in a log, so the engineer can take a look at it and see if something’s going wrong. If there is something wrong, you can look M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R STUDENT CHAPTERS Student chapters provide an avenue for students to connect to global IADC activities, drilling industry professionals, and the industry as a whole. Chapter activities typically include opportunities to meet and exchange ideas, socialize, and learn about the drilling industry. IADC supports student chapters by coordinating rig visits, factory tours, industry professional speakers, conference attendance and opportunities to connect with potential future employers. Inquire about an IADC student chapter at your school by contacting: STUDENTCHAPTERS@IADC.ORG INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS OPTIMIZING WELL INTERVENTION Schlumberger has developed a software program for streamlining wireline intervention shifting operations. Among other things, it automates the process of fl ushing clogged solenoids, a common cause of toolstring malfunctions. through this log and immediately work on troubleshooting,” Mr Li said. Case study At the conference, Mr Li presented the results from a system integration test (SIT) Schlumberger performed on the software. The test setup consisted of a 333 ft-long completion, including the following sec- tions: 7-in. tubing, 4.5-in. tubing, 3.5-in. tubing, 5-ft sliding sleeve and then an additional 6 ft of 3.5-in. tubing. The wireline toolstring used in the test consisted of a four-section tractor, fol- lowed by the shifting tool module. The completion mapping information was loaded into the software. The depth control panel was used to dis- play the shifting toolstring inside the com- pletion. The position of the toolstring was defined per the winch depth measurement and an offset correction. The depth of the end of the 6-ft section of 3.5-in. tubing was set at an artificial depth of 10,302 ft. The objectives of the SIT were to use the depth control panel to deliver the tool 7 ft above the sliding sleeve lower profile, and then start the automated seeking/shifting sequence to latch and shift the sliding sleeve down to open. The SIT was started with the toolstring inserted at the uphole end of the tubing. The tractor was used to tractor down. As the CCL module passed through the 7-in. tubing to the 4.5-in. tub- ing, the CCL signal was recorded. The trac- tor controls were set so the tractor stalled as the bottom-most drive hit the restric- 40 tion. The first drive was closed while the other three drives were kept open. This allowed the toolstring to move forward until the second drive hit the restriction. The tractor navigation sequence was continued by opening the first drive, clos- ing the second drive and tractoring down again. This allowed the tool to move down until the third drive hit the restriction. The second drive was opened and the third drive was closed, allowing the tool to move down until the fourth drive hit the restriction. At this point, the shifting tool was opened in seek mode, incorporating a suspension system that allowed it to compress to pass through restrictions or expand into openings. The third tractor drive opened, and the fourth drive was closed. The tractor was started, and the tool moved down until the tractor stalled. The higher tractoring force was selected, causing the shifting tool to be compressed and pass through the 4.5-in. to the 3.5-in. restriction. In seek mode, a profilometer option can be used to isolate the hydraulic chamber in the shifting tool. Fluctuation of the pressure then gives an indication of the change in diameter. The shifting tool diameter change mea- surement can then be used to measure change in diameter up to 1 in. In this case, the shifting was compressed from 3.9-in. diameter to 2.99-in. diameter, another indi- cator that Mr Li said helped to locate the toolstring in the completion. The shifting tool was opened near the end of and inside the 4.5-in. tubular, after which it was com- pressed to pass through the restriction and enter the 3.5-in. tubular. After the shifting tool passed the restric- tion, the next indication came from the CCL module passing through the 4.5-in. to 3.5-in. tubing restriction. The tractor then stalled when the bottom-most drive hit the 4.5-in. to 3.5-in. restriction. The tractor navigation was executed, and the fourth and last drive hit the restriction. This was the last indication before the shifting tool entered the sliding sleeve. The depth control panel, the CCL signal, tractor motor stall indicator and shifting tool ID measurement were used to deliver the shifting tool 5 ft above the sliding sleeve. The shifting tool pressure was then increased to use it as an anchor and pre- vent the toolstring from sliding inside the tubing. The tractor drivers were closed. Afterwards, the operation was complet- ed using the automated seeking/shifting sequence, which consisted of activating the tool using pre-selected parameters so that it moved in an inchworm-like motion toward the profile and latches, shifting the sleeve. In this case, the downhole direction was selected. The shifting tool latched and shifted the sleeve without stopping. Ultimately, Schlumberger hopes to enable “one-click” operation with the soft- ware, Mr Li said, although he noted this would require the software to be fully auto- mated over the wireline. To accomplish this full automation, automated winch operation must be incorporated into the workflow, and a decision-making method that better incorporates artificial intel- ligence will likely be needed to identify different phases of the operation. Further improvement on linear actua- tor displacement measurement would also allow micro-level correlation with submillimeter-grade accuracy. Mr Li said this could potentially be achieved by fus- ing multiple measurements, including the accelerometer measurement, the tractor speed, the pumping motor speed of the shifting tool, and the winch depth mea- surement. DC For more information, please see SPE 208992, “Advanced Software Features to Enable Smart Downhole Valve and Sleeve Shifting Operation.” M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R World Drilling IADC 2022 CONFERENCE & EXHIBITION 21-22 JUNE 2022 PULLMAN TOUR EIFFEL HOTEL PARIS FRANCE DIAMOND SPONSOR PLATINUM SPONSORS TOTAL TOT_21_00008_TotalEnergies_Logo_CMYK JFB 30-34 Rue du Chemin Vert 75011 Paris +33 (0)1 85 56 97 00 www.carrenoir.com TONS RECOMMANDÉS CYAN MAGENTA Ce fichier est un document d’exécution créé sur Illustrator version CS6. Date : 26/05/2021 TECHNIQUE YELLOW SILVER SPONSORS EVENT SPONSORS www.iadc.org/event/ iadc-world-drilling-2022-conference-exhibition For more information contact IADC The Netherlands by phone at +31.24.675.2252 or via email at europe@iadc.org OPTIMIZING WELL INTERVENTION Real-time force monitoring improves CT drillout efficiency Interactive tubing force analysis models, real-time data overlays reduce stuck pipe, NPT BY JESSICA STUMP, TRAVIS THOMAS AND COLT ABLES, NOV Considerable progress has been made in advancing methods and procedures for well intervention operations with coiled tubing (CT). However, stuck-tubing events are still common in post-fracturing drill- outs. Most analysis happens after these incidents have occurred, despite technol- ogy allowing for real-time viewing and engineering analysis of these operations. Between 2005 and 2010, horizontal drillouts became common in the Barnett and Haynesville shale plays. The indus- try rapidly standardized the operational procedures for horizontal plug-and-perf operations. The main standard operating procedures (SOPs) transferred over were weight checks to determine that CT was safe and free. However, CT technology used to analyze the operations in real time did not follow suit at the same pace. CT modeling software and data acquisi- tion systems (DAS) were used specifically to track string fatigue and record data for post-job analysis. Most field operations directly transferred vertical well SOPs to horizontal well applications. As horizon- tal well interventions became common, each operation was pre-modeled with a tubing force analysis (TFA). However, the TFA was used to determine if the CT could reach total depth (TD) but was not shared with field operations. Engineering tools like force monitors have been available since 2014. However, their use in North American operations have been limited because multiple short- cycle downturns removed engineering resources from the field. The online migra- tion capabilities of these engineering tools have improved as the well site trans- formed from largely remote to a data- connected environment. The connection of the subject matter expertise, which has moved out of the field and into the office, has allowed the most informed resources to access critical operational data and provide real-time engineering feedback without ever having to be at the well site. NOV’s CTES Cerberus intervention mod- eling software for planning and perform- ing CT operations now features cloud con- nectivity to provide field operators, man- agement and engineers with real-time access to the same data. This enables quick and inclusive operational decisions to be made before potential issues occur. Interactive TFA models in the software, combined with real-time data overlays, improve the efficiency of post-fracturing intervention of horizontal wells with CT and prevent problems currently analyzed only after operations have been negative- ly affected. Operational efficiencies can be achieved with the following proactive real-time engineering approaches: • Use Cerberus to: • Create a digital twin of the CT string for calculating fatigue; • Create a digital twin of a wellbore so expected variables, such as dynamic friction, pressures and temperature, can be considered when applying cal- culations in the TFA; and • Create an Orpheus Force project (TFA) to generate the expected weight ver- sus depth; • Run the Orpheus project to determine the coefficient of friction (CoF) reduction needed to reach plug back TD; • Using historic basin data, determine the acceptable deviations from the modeled run in hole (RIH) and pull out of hole (POOH) weights to ensure there is an agreed-upon stopping point; • Upload the Orpheus TFA into the CTES Figure 1 (left): The TFA shows that during RIH (blue), the model and weight indicators are good, but the friction increases before the 0.30 lockup depth, indicating an underperforming ERT. Figure 2 (above): The post-job TFA shows that after POOH (green) began, the CT pulled heavy and became stuck. After five days of circulating, the CT was freed and returned to the surface. 42 M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R OPTIMIZING WELL INTERVENTION Live Real-Time Force Monitor so the live data can be overlaid on the model and deviations can be seen before opera- tional issues arise; and • During the live job, adjust the model to account for current well conditions. RIH deviations If the RIH values are less than the planned values by the predetermined off- sets, there is either debris in the wellbore, an underperforming extended-reach tool (ERT), weight indicator calibration issues, or the model needs to be updated for actual well variables, such as pressure and ERT friction reduction value. Before moving farther in hole, determine the cause of the deviation. If the modeled data’s inputs have not deviated from the actual well conditions and the actual data previously matched the modeled data, the model did not cause the deviation. If the measured depth is less than the 0.30 CoF lockup depth, an ERT perfor- mance issue did not cause the deviation. Bottomhole assembly (BHA) performance issues are indicated when there is an apparent friction increase prior to the 0.30 CoF lockup depth and the CT can still prog- ress in the hole with clean weight checks, indicating no debris in the well. If debris is causing the deviation, a torque differential may be noticeable on the BHA, divergent pressures indi- cate bridging behind the BHA, or the CT continues to move in hole but only with increased set-down force and overpulls on weight checks. For instance, during a job, a service com- pany believed the CT was reaching friction lockup or a hard tag. The CT was pulled out of the hole to the surface, and the BHA was function tested. The CT tripped back in at normal speed and experienced the same issue at the same depth. The CT was pulled out of the hole again, and the BHA was changed. On the third run, the CT progressed to the bottom and completed the job with the replaced BHA. If the com- pany used the TFA as shown in Figure 1, the underperforming BHA, specifically the ERT, causing the deviation would have been apparent. If the tools were changed on the first run, multiple trips could have been eliminated, reducing nonproductive time (NPT) and costs. Figure 3: The CTES Live Real-Time Force Monitor enables the live data to be overlaid on the TFA so deviations can be seen before operational issues arise. POOH deviations If POOH values are greater than the planned values by more than the predeter- mined offsets, there is debris in the well- bore or weight indicator calibration issues. To determine the deviation cause, ver- ify the weight indicator readings versus the hydraulic calculations. If the weight indicator varies from the hydraulic cal- culations, calibrate the weight indica- tor and reevaluate the operation. If the weight indicator does not deviate from the hydraulic calculation, debris is in the well- bore. Pulling heavy can result in debris bridging and stuck pipe. Stop and circulate the well clean. If possible, RIH to assist in static friction reduction of the debris to increase removal. For example, a 7,000-ft horizontal well with 5.5-in. 20-lb/ft casing and a 2.635- in. CT string was modeled before arriv- ing on location. Data suggested that the approximately 17,000-ft TD could easily be reached with an ERT and a 0.30 CoF while pumping 5 bpm through the CT and taking 6 bpm returns. As shown in Figure 2, this well began with the weight data being offset from the TFA RIH line. The operator should have checked the TFA to ensure the input parameters matched the actual job condi- tions. A weight indicator issue could have also caused this offset. However, the weight was consistent compared with the TFA RIH line until they entered the horizon- tal. As the CT continued in the wellbore, the weight data deviated from the expect- ed weight from the TFA, even though it was making excellent progress to TD. The weight crosses over the expected TFA line and remains on the “light” side of the line, which indicates more weight is required to RIH than expected. The most likely cause of this is excess sand in the wellbore. The CT made it to TD in 12 hours without issues. After circulating for 20 minutes on bot- tom, the service company began to POOH at 35 ft/min. The circulation was too short, and the POOH speed was too fast. When looking at the force monitor, sand was most likely present. After 1,800 ft, the CT began to pull heavy and became stuck. After five days of circulating and pulling up to 140,000 lb, the CT was freed and removed from the wellbore. The wellbore was cleaned during the five days, so little or no sand remained in the horizontal section. After the CT was freed, the POOH weight matched the expected POOH TFA line, although the offset from the beginning of the job remained. In a clean wellbore, the POOH weight data runs parallel to the expected POOH TFA plot. The future of automation Analyzing the data in real time to make operational decisions is a foundation for the future of CT, but not the goal. As real- time force monitoring becomes common, NOV is applying the same real-time force data to develop automated CT operations in the future. The TFA will be the roadmap to keep the operation on path and ensure it does not deviate from the plan. Automated CT will be able to streamline well inter- ventions, capture lessons learned, apply improved processes, reduce the potential for human error in operations, and enhance efficiency and safety for all personnel. Conclusion While CT operations in horizontal shale plays have become standardized, the increased use of interactive TFA models and real-time data overlays will reduce stuck-tubing events, NPT and costs. Today, the tools to analyze and act on TFA devia- tions are available in most CT units. Real- time force monitoring improves drillout efficiency. DC This article is adapted from SPE 208999, “Optimizing Drillouts Using Live TFA,” presented at the SPE/ICoTA Well Intervention Conference, 22-23, March 2022. CTES, Cerberus, Orpheus and CTES Live are NOV trademarks. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 43 IADC CONNECTION • EDITORIAL To propel itself forward, drilling industry must look to technical innovations FROM THE CHAIRMAN Technological advances are often designed to further safeguard our employees or to deliver heightened equipment and systems reliability and operational efficiency, or to simultaneously advance both of these essential attributes as our industry explores, drills and produces the energy upon which the world relies. This is why many oilfield service companies commit their efforts, and financial resources, to drive continuous enhancements to existing technologies and to develop new, innovative technologies to support customers’ efforts to meet the world’s expanding energy demands. The importance our industry places on technological advancements is on dis- play each May in Houston at the Offshore Technology Conference (OTC), the premier event for exhibiting the latest scientific and technical knowledge in the offshore energy sector. Thousands of profession- als from around the world collaborate at the four-day conference to discuss techni- cal challenges and solutions. It is a truly inspiring event, and I encourage everyone in our industry to participate, using it as a prompt for incremental improvement of existing technologies and as a springboard for the exploration of new ideas that will invariably continue to propel our industry. Everyone in the energy industry knows that we will continue to face challenges – some of which are not yet known. However, we possess the distinct advantage of hav- ing the best and the brightest minds to tackle these challenges and push us for- ward to further improve safety, reliability and efficiency while reducing fuel con- sumption and emissions. This continued technological advancement is especially important as the offshore drilling market enters a period of robust recovery amid 44 strong demand and limited availability of the newest, highest-specification rigs. At Transocean, we are nearing deliv- ery of our two new eighth-generation drillships – the Deepwater Atlas and the Deepwater Titan. These will be the only two eighth-generation drillships in the industry, set apart by their ability to drill and complete 20,000-psi prospects with an industry-leading net 3 million-lb hoisting capacity. These attributes clearly reinforce Transocean’s position as the technologi- cal leader in offshore drilling – a position built upon a long history of technological innovation in constant pursuit of safety, reliability and efficiency. Our company’s history includes the first dynamically positioned drillship, the first rig to drill year-round in the North Sea, the first semisubmersible rig for year-round sub-Arctic operations, the first 10,000-ft water depth rated ultra-deepwater drill- ship, as well as numerous water depth world records over the past several decades. Innovation is a core value at Transocean. We continuously advance our leadership position by developing and investing in technologies that optimize our operation- al performance. An excellent example of a technology enhancement to improve operational performance is our automated drilling control system, which is currently installed on six of our harsh-environment floaters. This system materially improves our ability to safely and efficiently deliver better wells to our customers. Additionally, we employ a data-driven approach across the company and have deployed our smart equipment analytics tool, which delivers real-time data feeds from equipment to monitor their health, inferred emissions and energy consump- tion, while identifying performance trends that allow us to systematically optimize equipment maintenance and achieve higher and more constant levels of reli- ability and operational efficiency. Transocean has also developed and deployed its patented HaloGuard system, which sounds a series of alarms and, if required, halts equipment to prevent injury to personnel who move into danger zones. We also recently deployed the first unit of Enhanced Drilling’s EC-Monitor system to an offshore installation, which enables a highly accurate understanding Click here to view more photos. Jeremy Thigpen, IADC Chairman of well fluid dynamics, improves the effi- ciency and accuracy of flow-checking, and detects flow anomalies. Additionally, in 2021, on one of our ultra-deepwater drill- ships, we deployed and tested the world’s first kinetic blowout stopper on a well, potentially representing a sea change in operational integrity and enterprise risk reduction through unrivaled shearing capability. Later this year, we expect to be the first to deploy offshore a robotic riser bolting tool on two of our ultra-deepwater drillships, improving our ability to deliver safe, efficient operations to our customers. At Transocean, we believe that our efforts to continuously improve, and effec- tively use, innovative technologies are critical to maintaining our competitive position within the contract drilling ser- vices industry. By drilling more efficient wells, building greater resilience into our critical operating systems, ensuring the safety of our crews, and reducing fuel con- sumption and emissions, we are making improvements that benefit our company, our industry and the environment. And as we work toward producing more energy with lower emissions, our entire industry recognizes that new and existing technology plays a role. It is clear that our industry must keep innovating, we must keep advocating, and we must keep edu- cating to attract new talent and the neces- sary capital for the future of our industry. Most importantly, we must keep drilling to meet the global demands of a world whose economies and people rely upon the oil and gas we help produce each day. DC HaloGuard is a service mark of Transocean. M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R NEWS CUTTINGS • IADC CONNECTION Volunteers needed for IADC ISP review subcommittee The IADC HSE Committee recently formed a subcommittee for drilling con- tractors, onshore and offshore, to under- take a comprehensive review of the IADC Incident Statistics Program (ISP), focus- ing on updating definitions, reporting criteria and performance metrics. The ISP has tracked safety and acci- dent information for the drilling indus- try since 1962. It provides a record of data reflecting accident experience that can be compared with other industries, helping drillers identify the causes and trends of drilling industry injuries and providing a means of recognizing rig crews for outstanding safety perfor- mance. It also provides a benchmark for global HSE performance across the drilling industry. Patrick Kearley, Global VP HSE and Training for Ensign Energy Service, will serve as Onshore Chairman for the ISP Subcommittee, and Paul Finnie, Director Global HSE for Diamond Offshore, will represent the offshore members. The subcommittee is proactively looking for representatives from onshore and off- shore drilling contractors to participate, with the goal of creating a finished prod- uct that is fully representative of indus- try opinion. Its first meeting will be held on 9 May. For more information, please contact Rhett Winter at rhett.winter@iadc.org. IADC members host students at Drilling Conference IADC member companies hosted several student chapters at the 2022 IADC/ SPE International Drilling Conference in Galveston, Texas, in early March. As part of the activities that week, 39 students from nine schools also toured the Valaris 8506 semisubmersible, which was positioned dockside in Galveston. DEC Tech Forum to focus on drilling hazards, well design On 15 June, the IADC Drilling Engineers Committee will host its Q2 Technology Forum, “Drilling Hazards and the Impact on Well Design and Delivery.” This forum will explore the ongoing evolution in well design due to changes in philosophy, technology and risk. Well designs are constantly evolving, and wellsite operational practices continue to improve to mitigate exposure and risk. The forum will examine how the indus- try can quantify risk so that appropriate well designs can be planned and select- ed. Drilling engineering problems that could be explored in this forum include: subsurface hazards, offset wells, drilling technology, bit design and fluids. Scan me to register for the IADC DEC Q2 Technology Forum. bit.ly/3Dij3xT IADC ART Energy Efficiency group launches projects The IADC Advanced Rig Technology (ART) Committee recently kicked off three new projects and is calling for individu- als in the drilling industry to join the efforts. The projects, which fall under the ART Energy Efficiency Subcommittee, are emission forecasting and reporting, emis- sion reduction recommended practice for drilling operations, and an alternative fuels overview report. Scan me to indicate your interest in participating in one or more of these projects. bit.ly/2YHM9GC IADC, SPE student chapters collaborate to host virtual geothermal drilling event IADC and SPE student chapters at the University of North Dakota co-hosted a virtual Geothermal Drilling Conference in late March. While enhanced geothermal systems offer tremendous potential, high drilling costs remain a critical challenge. The conference explored the causes of these high costs, such as low rates of pen- etration and wellbore instability issues. The event also presented a drilling opti- mization system designed for geothermal application. This was the second event co-hosted by the two student chapters. The first event, focusing on carbon capture utilization and storage, took place in January. Saudi Arabia’s KFUPM adds IADC student chapter IADC has announced the 13th edition to its student chapter program: King Fahd University of Petroleum and Minerals (KFUPM) in Saudi Arabia. The KFUPM Department of Petroleum Engineering was established in 1973 and started functioning on 14 September 1974 with an undergraduate program. The first BS degree in petroleum engineering was awarded in 1977. The department started its MS program in 1982 and its PhD pro- gram in 1985. IADC’s Student Chapter program was started in 2017. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 45 IADC CONNECTION • WIRELINES BSEE launches web-based dashboard for safety data A new web-based dashboard is now available to industry and the public as part of the US Bureau of Safety and Environmental Enforcement (BSEE) and Bureau of Transportation Statistics (BTS) SafeOCS Reporting System. The dashboard represents data col- lected from 2018 to 2020 and over 11,900 consolidated, voluntarily reported events, including incident reports, event narratives, and contractor and operator information. It allows operators to com- pare their confidential submissions with aggregated data from all participants to better identify safety risks and address them before an incident occurs. Working with the BTS and other industry collaborators, BSEE began the SafeOCS program in August 2013 for con- fidential reporting of safety data on the OCS. The dashboard increases transpar- ency and improves companies’ ability to follow trends, improve inspection plan- ning, and see meaningful relationships in process safety and personal safety. Scan me to access the BSEE/BTS SafeOCS dashboard. bit.ly/3xsiuk6 US SEC looks to bolster cybersecurity risk management The US Securities and Exchange Commission (SEC) is proposing rules to enhance and standardize disclosures regarding cybersecurity risk manage- ment, strategy, governance and cyberse- curity incident reporting by public com- panies. Specifically, the commission is look- ing at amendments that require cur- rent reporting about material cyberse- curity incidents. The proposal would also require periodic disclosures about a company’s policies and procedures to identify and manage cybersecurity risks, management’s role in implement- ing cybersecurity policies and proce- dures, its board of directors’ cybersecu- rity expertise (if any) and its oversight of cybersecurity risk. It would also require companies to provide updates about pre- viously reported cybersecurity incidents in their periodic reports. In its release of the proposal in the US Federal Register on 23 March, the SEC said the rules would better inform investors about a registrant’s risk man- agement, strategy and governance, and provide timely notification of material cybersecurity incidents. Scan me to read the SEC’s proposal for disclosures on cybersecurity risk. bit.ly/3jKKffT IADC supports House Natural Resources energy bills On 30 March, the US House Natural Resources Committee introduced six bills that would bolster the US energy sector and give regulatory certainty to drilling contractors. Among many things, these bills would address well-known oil and gas permitting delays facing the US Department of Interior, as well as end the Biden Administration’s ban on federal onshore and offshore oil and gas leasing. IADC President Jason McFarland issued the following statement: “At a time in which the United States and nations around the world are facing rampantly growing energy scarcity and fuel prices, 46 these bills are textbook examples of the type of legislation needed to support rig owners and ramp up drilling. “On behalf of IADC’s member compa- nies and the hundreds of thousands of workers they employ, I’d like to thank Ranking Member (Bruce) Westerman and Representatives (Garret) Graves, (Jerry) Carl, (Blake) Moore, (Beth) Van Duyne, (Yvette) Herrell and (Matt) Rosendale for their continued support of good-sense energy policy, and for recognizing the urgent need to boost exploration, drilling and production in the North American market.” OSHA proposes changes to regulations for recording occupational hazards The US Department of Labor’s Occupational Safety and Health Administration (OSHA) has proposed amendments to its occupational injury and illness record-keeping regulation, 29 CFR 1904.41. The current regulation requires certain employers to electronically submit injury and illness information – which they are required to keep – to OSHA. The agency uses these reports to identify and respond to emerging hazards. It also makes aspects of the information publicly available. Under the proposed rule, not only would companies have to report their annual summary of work-related injuries and illnesses, certain establishments in cer- tain high-hazard industries would also be required to electronically submit addi- tional information from their Log of Work- Related Injuries and Illnesses, as well as their Injury and Illness Incident Report. OSHA said in a statement that the pro- posed rule would improve its ability “to use its enforcement and compliance assis- tance resources to identify workplaces where workers are at high risk.” It also believes the amendments would empower workers by increasing transparency in the workforce. The rule would: • Require establishments with 100 or more employees in certain high-haz- ard industries to electronically submit information from their OSHA Forms 300, 301 and 300A to OSHA once a year; • Update the classification system used to determine the list of industries covered by the electronic submission requirement; • Remove the current requirement for establishments with 250 or more employ- ees not in a designated industry to elec- tronically submit information from their Form 300A to OSHA annually; and • Require establishments to include their company name when making electron- ic submissions to OSHA. M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R Scan me to learn more about OSHA’s proposed amendments. bit.ly/3rhGhiC UPCOMING IADC EVENTS • IADC CONNECTION IADC 9-10 JUNE 2022 RITZ CARLTON NEW ORLEANS, LOUISIANA International Tax SEMINAR SEMINAR World Drilling IADC 2022 CONFERENCE & EXHIBITION 21-22 JUNE 2022 PULLMAN TOUR EIFFEL HOTEL PARIS FRANCE IADC Advanced Rig Technology CONFERENCE & EXHIBITION 30-31 AUGUST 2022 HYATT REGENCY AUSTIN HOTEL AUSTIN, TEXAS 2022 IADC Europe IADC HSE AND SUSTAINABILITY CO N FER EN CE & E XH I B ITI O N HSET HSET & & Sustainability Sustainability CONFERENCE & EXHIBITION 20-21 SEPTEMBER 2022 HYATT REGENCY HOUSTON WEST • HOUSTON, TEXAS 14-15 SEPTEMBER 2022 APOLLO HOTEL AMSTERDAM, THE NETHERLANDS To register for these and other conferences please visit us online at www.iadc.org/conferences/upcoming. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 47 IADC CONNECTION • DRILLING CONTRACTOR DON’T MISS OUT ON OUR NEXT ISSUES! EDITORIAL PREVIEW OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS July/August WWW.DRILLINGCONTRACTOR.ORG WWW.IADC.ORG Bonus distribution: AD CLOSING: 16 JUNE MATERIALS DUE: 23 JUNE • The Digital Transformation issue: • Applying Data Science in Drilling • Re-skilling Workers for Digital Workflows • Innovations from Tech Startups • IADC/SPE Asia Pacific Drilling Technology Conference & Exhibition, 9-10 August 2022, Bangkok, Thailand • IADC Advanced Rig Technology Conference & Exhibition, 30-31 August, Austin, Texas • Offshore Asset Integrity September/October Bonus distribution: • IADC Drilling HSE & Sustainability Europe Conference & Exhibition, 14-15 September, Amsterdam, The Netherlands AD CLOSING: 11 AUGUST MATERIALS DUE: 18 AUGUST • The Drilling Rig issue: • Maximizing Fuel Efficiency on Drilling Rigs • Achieving Autonomous Drilling • Advances in Tubular Handling • Improving Safety on the Rig • Workforce Development & Training News • SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference & Exhibition, 27-28 September, Kuala Lumpur, Malaysia • SPE Annual Technical Conference & Exhibition, 3-5 October, Houston, Texas • IADC Contracts & Risk Management Conference, 4-5 October, Houston, Texas Visit DrillingContractor.org for the latest drilling industry news and videos Saipem awarded new contracts offshore Middle East, West Africa Saipem has been awarded new con- tracts for drilling offshore the Middle East and West Africa for a total amount of more than $400 million. Two contracts have been awarded in the Middle East for two high specification jackups, consisting of drilling and work- over operations for a duration of five... 48 • IADC HSET & Sustainability Conference, 20-21 September, Houston Maersk Drilling secures one-year multi-country commitment for drillship with Shell Maersk Drilling has been awarded con- tracts with Shell for the Maersk Voyager drillship for drilling services offshore mul- tiple countries. The contracts are expected to commence in April 2022 and last for one year. The total contract value is approxi- mately $107.5 million... Noble rig mobilized to drill Santos well offshore Australia The Noble Tom Prosser jackup has been mobilized to Santos Energy-operated Apus-1 well in the Bedout Sub-Basin off- shore Australia. The rig recently complet- ed successful drilling in proximity to the Apus-1 well, which resulted in a material oil discovery... M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R PEOPLE, COMPANIES & PRODUCTS • DE PAR TM E NTS Simon Johnson appointed President, CEO of Seadrill Seadrill has named Simon Johnson as its new President and CEO, effective immediately. Mr Johnson replaces Stuart Jackson in both positions. Mr Johnson has worked for a number of offshore drilling contractors over the past 25 years, including Diamond Offshore, Seadrill, Noble Corp and Borr Drilling. He previously served as Senior Vice President – Marketing and Contracts at Noble and as CEO of Borr Drilling. Mr Johnson holds a Bachelor of Commerce (Economics & Finance) from Curtin University and has completed the Advanced Management Program at Harvard Business School. Noble, Maersk Drilling announce executive management team Noble Corp and Maersk Drilling recently announced the executive management team that will be effective after the clos- ing of the business combination originally announced in November 2021. The com- bined company will be led by Robert W. Eifler as President and CEO. Others on the executive management team will include: • Richard B. Barker – Senior Vice President and Chief Financial Officer; • William E. Turcotte – Senior Vice President, General Counsel and Corporate Secretary; • Joey M. Kawaja – Senior Vice President – Operations; • Caroline Alting – Senior Vice President – Operational Excellence; • Blake A. Denton – Senior Vice President – Marketing and Contracts; • Marika Reis – Chief Innovation Officer; • Mikkel Ipsen – Vice President of Human Resources; • Kirk T. Atkinson – Head of HSE; • Claus Bachmann – Vice President of Operations – North Sea; • Matthew J. Brodie – Vice President of Operations – Middle East, Africa and Asia Pacific; and • Garth Pulkkinen – Vice President of Operations – Americas. Tungesvik, Stenerud named to new executive roles at Equinor Equinor announced Geir Tungesvik will take over as Executive VP for the Projects, Drilling and Procurement business area starting 1 May. Aksel Stenerud was named Executive VP for the People and Organization function, effective 1 March. Mr Tungesvik was previously Senior VP responsible for project development, and Mr Stenerud was VP responsible for global employee relations. Geir Tungesvik Expro acquires fiber optic sensing company SolaSense Henn, Stringer join team at Intelligent Wellhead Systems Expro has acquired 100% of distributed fiber optic sensing company SolaSense. SolaSense’s well surveillance technology features portable processing software and enhanced visualization interface for deliv- ering near real-time analysis of distributed acoustic sensing/distributed temperature sensing data at the well site. This allows well characteristics to be readily recog- nized and evaluated, avoiding shut-ins for extended periods and minimizing lost production. New Industries, Delmar team up for suction piles New Industries and Delmar Systems have signed an agreement to work in partnership to provide enhanced design and fabrication services for turnkey suction piles. The engineering will take place in Delmar’s Houston office, and the fabrication will be com- pleted in New’s fabrication yard in Morgan City, La. Aramco awards gas drilling project to Schlumberger Schlumberger has won a major con- tract from Saudi Aramco for integrated drilling and well construction services in a gas drilling project. The scope encompasses drilling rigs and tech- nologies and services, including drill bits, MWD and LWD, drilling fluids, cementing and completing wells. TSC acquires high-torque thread connection tech Texas Steel Conversion (TSC) has purchased the intellectual property, patents, associated trademarks, licens- es and other thread connection tech- nology known as the PTECH+ thread connection. TSC will manufacture, market and sell the thread connection through various divisions. 3D printing centers for oil/gas industry certified Aksel Stenerud Intelligent Wellhead Systems has brought on Bill Henn as Strategic Technical Advisor and Rip Stringer as Director of Industry Affairs. Both have 30-plus years of experience with managing oilfield tech- nologies and will report to CEO William Standifird. Mr Henn will work to stream- line the adoption of digital completion technologies, and Mr Stringer is respon- sible for creating effective connections among operators, service companies and technical societies. Voestalpine Additive Manufacturing Centers in Canada and US recently became the first such centers in North America to be certified by DNV for the oil & gas industry with the DNV- ST-B203 industry standard. Tenaris taps Microsoft for digital transformation Tenaris and Microsoft have inked a five-year Digital Transformation Alliance. Tenaris aims to fast-track its migration to the cloud by leveraging Microsoft’s Azure solutions to improve accessibility and reliability of informa- tion; develop digital tools using real- time data; and optimize performance across its industrial footprint and sup- ply chain through improved manage- ment and control processes. D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 49 DE PAR TM E NTS • PEOPLE, COMPANIES & PRODUCTS Products Halliburton launches new real-time service for multilayer visualization while drilling Halliburton has introduced StrataStar, a deep azimuthal resistivity service that provides multilayer visualization to maxi- mize well contact with the reservoir and improve real-time reserves evaluation. The service is the latest addition to Halliburton’s iStar intelligent drilling and logging platform, which combines deep subsurface insights with artificial intelligence for improved drilling perfor- mance and consistent well delivery. For more decisive well placement, the ser- vice acquires real-time measurement and visualization of surrounding geology and fluids up to 30 ft around the wellbore. It applies a sophisticated algorithm to accurately map the position, thickness and resistivity of interbedded rock and fluid layers to stay within targeted bound- aries. Dropsafe expands range of its helideck safety net system Dropsafe has expanded its Helideck Perimeter Safety Net range, with one ver- sion offering a 10-year service life and two- year warranty, and another version offer- ing a 25-year service life with a 10-year warranty. The 316 stainless-steel system attaches to the perimeter frames of heli- decks to protect personnel from falling. The system is designed to withstand an impact greater than 2.3 kJ (100 kg at 2.35 m). The system is modular, allowing easy replacement of components if necessary. Data Gumbo recently launched GumboStore, an industry-grade smart contract marketplace. It enables com- panies to create, deploy, publish or license intuitive smart contract tem- plates to eliminate transactional and informational friction in commercial relationships. Access to GumboStore requires a subscription to Data Gumbo’s smart contract network, GumboNet. Compact well integrity technologies reduce space requirements Unity has launched a new range of compact technologies to solve industry challenges like working space, com- ponent weight and personnel on board restrictions. The new technology range includes a compact dual-bore xmas tree isolation system, a compact valve remov- al tool and a compact shear-seal valve. The technologies will be used to support Unity’s surface well integrity, shallow intervention and well decommissioning services. Data Gumbo launches smart contract marketplace Hammerless valve cover lock for drilling modules GD Energy Products has launched SafeLock, a hammerless quarter-turn valve cover lock for drilling modules that delivers safe, fast removals with- out requiring any tools. The tool reduc- es the multiple revolutions needed to remove the valve cover lock to a quar- ter-turn. Corrosion-resistant threading and grease zerks keep threads lubri- cated between service intervals. Unity’s new compact shear-seal valve IFS Cloud updated with simpler but more intelligent analytics IFS has released an update to IFS Cloud, enabling fast-tracked adoption of digital capabilities. The update delivers improved predictive capabilities and sim- pler, more intelligent analytics for faster time to insight. Enhancements include: • Ready-to-go analytics: pre-built content with advanced analytics reports; • New analysis models for enterprise 50 asset management, customer relation- ship management, human capital man- agement, and manufacturing, and self- service analytics; • Extended asset performance prediction: Combined sensor data and historical maintenance records can be used to train machine learning models to support the decision-making process of operators. M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R AD INDEX Abaco Drilling Technologies..................54 Burgess Manufacturing............................53 IADC Advanced Rig Technology Conference & Exhibition...........................5 IADC HSET & Sustainability IADC World Drilling 2022 Conference & Exhibition......................... 41 M-I-SWACO..........................................................2 Nabors Drilling Solutions.............. DIGITAL Noble Corporation......................................... 51 Conference & Exhibition .......................36 Oil States............................................................. 27 IADC Professional Membership..............6 TSC Drill Pipe.....................................................33 IADC Student Chapters.............................39 Wild Well Control...........................................23 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! 7,205 + Followers 30,540 + Followers 5,260+ Followers 2.61K Subscribers 2,248,060 + Views D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2 51 DEPARTMENTS • PERSPECTIVES Jamie Elrod, Baker Hughes: Industry must continue working to improve gender diversity within its ranks BY STEPHEN WHITFIELD, ASSOCIATE EDITOR The journey to a career in the oil and gas industry can take on many different forms. Some people are practically born into the oilfield, or they know from an early age that this industry is where they want to devote their working lives. Some people come into the industry through fortuitous circumstances. Jamie Elrod, Emissions Management Commercial Leader at Baker Hughes, falls into the latter category. These days, Mrs Elrod serves as a voice for the industry, pushing for greater gender diversity through her “Flipping the Barrel” podcast and promoting the industry’s role in the energy transition through her work. But growing up in Magnolia, Texas, she did not have dreams of a career in oil and gas. She was passionate about horseback riding, competing in showjumping events. She ran track and played volleyball. As a personable teen who loved working retail jobs, she figured that a sales career would be perfect for her. “I took a job at The Woodlands Mall when I was about 16 years old, and you had to upsell your customers, and all the salespeople competed against each other. There was a list where you could see who had the best sales numbers, and I really thrived off of that. It was something I was just naturally good at,” she said. Mrs Elrod attended Sam Houston State University on a volleyball scholarship, ultimately studying marketing and eco- nomics at the school. Shortly after her graduation in 2012, she was contacted 52 by a headhunter who focused on placing college athletes into entry-level positions. That led to a two-year stint at Vopak, a company that offers storage services for products including biofuels, LNG and chemicals. She worked a number of trainee jobs before being promoted to Commercial Business Analyst in December 2013. Ten months later, in September 2014, Mrs Elrod joined Smith Bits, a Schlumberger company, as a Field Sales Representative. This marked her first foray into the world of oil and gas drilling – as part of the job, she had to assist in the development of new marketing material and analysis for the company’s drill bit products. After a year, Smith Bits promoted Mrs Elrod to Technical Sales Representative, where she worked primarily on selling small roller cone bits for plug-outs. Next came a corporate sales position at Thru Tubing Solutions and then a position as Senior Account Manager for C&J Services (later NexTier Oilfield Solutions), where she focused on commercial development in frac and wireline operations. Promoting the industry to new audiences It was during Mrs Elrod’s time at NexTier that a pair of major life events changed things for her. First, she connected with Massiel Diez, MCA Reservoir Performance Sales Lead at Schlumberger, on Instagram. The pair bonded over their shared love of the oil and gas industry and their desire to help make the industry more diverse. In September 2019, they launched “Flipping the Barrel,” providing women’s perspectives on oil and gas. The podcast features interviews with senior executives and other key industry figures on a variety of topics, such as the energy transition, technology adoption and the challenges in maintaining a work/life balance. “We wanted to share with the outside world that this is a great industry to be in,” Mrs Elrod said. “We’re tired of just talking about it in our circle. So, let’s start a pod- cast and talk about how can we empower the next generation? How can we inspire women to join this industry?” The second thing that happened to Mrs Elrod during this time was the birth of her daughter in January 2021. Her pregnancy led her to rethink the path she wanted to During a session on diversity and in- clusion at the 2022 IADC/SPE Interna- tional Drilling Conference, Jamie Elrod stressed the need for the industry to build environments that can help wom- en to sustain long careers. take within the industry, she said. “I real- ized how much I care about our industry and the environment. I was working in frac, and it has this perception as a hor- rible thing for the environment, and that’s pretty far from the truth. I think it’s one of the cleanest ways to get energy.” This newfound perspective led Mrs Elrod to switch gears. In September 2021, she moved into her current role at Baker Hughes, where she promotes emissions monitoring, detection and quantification systems, as well as digital solutions for mitigating and preventing fugitive emis- sions. While her job focuses on ESG, Mrs Elrod remains passionate about promot- ing gender diversity within the industry. On 9 March, Mrs Elrod gave a speech at the Diversity and Inclusion Session held during the 2022 IADC/SPE International Drilling Conference. She said the main purpose of her speech was to show how companies can encourage women to build long-term careers in oil and gas. “This industry has done a very good job of seeking out more women for engi- neering roles and bigger leadership roles, but we still have a lot of work to do on developing an environment that supports women through the different challenges and changes in their lives,” she said. DC M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R OPTIFIT TM POWER SECTION STATORS Optimum Performance Through Innovation TM OPTIFIT is the latest engineering innovation from Abaco. This new stator design delivers an optimized fi t for all drilling applications. Single direction stators feature harder rubber with deviated profi les to address high power and high torque drilling stresses on the power section lower end. The variable fi t of the rotor and stator stabilizes the lower end to reduce frictional wear and overheating by balancing fl uid pressure distribution. This results in maximized performance and greater power section reliability, especially at high power, with a signifi cant reduction in fi eld failure rates. See OPTIFIT and all of our innovative power section technologies at Abacodrilling.com Patent Pending LEADING POWER SECTION TECHNOLOGY Abacodrilling.com © 2022 Abaco Drilling Technologies. All rights reserved.