GOING THE DISTANCE Extended laterals require new solutions for bit guidance, handling excessive torques – p14 MAR/APR 2023 Volume 79 • Number 2 Official magazine of the International Association of Drilling Contractors www.drillingcontractor.org www.iadc.org Digital tools streamline design, testing process during drill bit selection Digital twins, in-bit sensors shorten iteration cycle, help operators start drilling faster – p28 Drill pipes, BHAs evolve as wellbore geometries push existing boundaries Improvements include greater fatigue resistance for connections, better surface control of BHAs – p22 TAB LE OF CONTE NTS To drill more cost-effective extended laterals and help keep downhole tools in the hole for as long as possible, Patterson-UTI has focused on improving the accuracy of horizontal wellbore placement. Read more on Page 14. Cover illustration courtesy of Patterson-UTI. Official magazine of the International Association of Drilling Contractors MAR/APR 2023 Volume 79 • Number 2 drillingcontractor.org iadc.org I N N OVATI N G WH I LE D R I LLI N G 14 Going the distance: Drillers push innovations to drill extended laterals Extreme depths necessitate solutions to handle high torques and lateral vibrations, ensure accurate horizontal wellbore placement BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 18 Preventing lost circulation, instability offshore Malaysia BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 20 Combination of extended-reach drilling, maximum reservoir contact wells and artificial islands helps ADNOC access offshore reserves with land rig BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 22 Drill pipes, BHAs evolve as wellbore geometries push existing boundaries Industry steps up downhole performance by giving connections greater fatigue resistance and enhancing BHA steering capabilities BY STEPHEN FORRESTER, CONTRIBUTOR 27 Case study: Laser measurements, machine learning help operator improve its motor performance BY LONNIE SMITH, TURNCO 28 Digital tools streamline design, testing process during drill bit selection Digital twins, in-bit sensors among innovations shortening the iteration cycle to help operators get bits into the field faster BY STEPHEN WHITFIELD, ASSOCIATE EDITOR HYDRAULIC FRACTURING ADVANCES 33 Sensor-based system allows real-time detection, monitoring of emissions in frac operations BY STEPHEN WHITFIELD, ASSOCIATE EDITOR 34 Centralized start-stop system helps reduce fuel consumption, emissions from idling engines in hydraulic fracturing operations BY STEPHEN WHITFIELD, ASSOCIATE EDITOR D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 3 TAB LE OF CONTE NTS HYDRAULIC FRACTURING ADVANCES 36 Metal-seal dissolvable frac plugs use simplified design to improve reliability during plug and perf BY JINLU WANG, VERTECHS GROUP GLOBAL WORKFORCE DEVELOPMENT 37 ExxonMobil’s Guyana project provides blueprint for building local workforce, infrastructure in emerging E&P markets 39 Gender equality study explores barriers women in Persian Gulf still face in oilfield careers BY STEPHEN WHITFIELD, ASSOCIATE EDITOR IADC CONNECTION BY STEPHEN WHITFIELD, ASSOCIATE EDITOR DEPARTMENTS 41 News Cuttings 5 42 From the President: Next-gen engagement and enthusiasm continue to flourish BY JASON MCFARLAND, IADC PRESIDENT 44 Wirelines 45 Conference Calendar 46 Editorial Preview NOTE: Some articles feature QR Codes which can be scanned using your smartphone to access web- exclusive, enhanced editorial on DrillingContractor.org or in our Digital Reader. 6 7 8 10 12 47 49 50 Drilling Ahead: Talent report: Industry will need to compete on more than salary BY LINDA HSIEH, EDITOR & PUBLISHER D&C News D&C Tech Digest News Briefs: Environmental, Social and Governance Oil & Gas Markets Videos People, Companies & Products Advertisers Index Perspectives: Richard Grayson, Nabors – Being flexible is critical to a long career in an industry of constant change BY STEPHEN WHITFIELD, ASSOCIATE EDITOR MAR/APR 2023 Volume 79 • Number 2 Drilling Contractor (ISSN 0046-0702), the official magazine of the International Association of Drilling Contractors (IADC), is issued six times per year. DC is a wholly owned publication of IADC, which is also the publisher of the annual IADC Membership Directory. Drilling Contractor strives to ensure that the articles and information it publishes are accurate and reliable. However, DC cannot warranty the information provided in its editorial content, and publication in DC is not a guarantee that the material presented is accurate. DC wants to hear from its readers. Send your comments or inquiries to editor@iadc.org or Attn: Editor, Drilling Contractor Magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042 (please include your name, plus an email or phone number). We hope you will enjoy and benefit from DC’s editorial. However, should you wish to 4 complain, please contact the publisher. Our complaint policy is posted at www.drillingcontractor.org. Subscriptions are free to operational personnel employed by contract-drilling firms or by major, national or independent oil companies. Publisher reserves the right to refuse non-qualified subscriptions. Paid subscriptions are available at $260 per year, US; $320, outside the US. Single issues are $40. For advertising rates or information, call Drilling Contractor at +1-713-292-1945 or check our website at www.drillingcontractor.org. Postmaster: Please send address changes to Drilling Contractor magazine, 3657 Briarpark Drive, Suite 200, Houston, Texas 77042. © 2023 Drilling Contractor. All rights reserved. Printed in the USA. PUBLISHED BY IADC OFFICERS IADC 3657 Briarpark Drive Suite 200 Houston, Texas 77042 USA Chairman Andy Hendricks Phone: +1 713 292 1945 drilling.contractor@iadc.org www.drillingcontractor.org Secretary-Treasurer Scott McReaken EDITORIAL STAFF Vice President, Editor & Publisher Linda Hsieh Creative Director Brian C. Parks Associate Editor Stephen Whitfield Contributor Stephen Forrester Vice Chairman Leif Nelson Division VP North America Onshore Mike Garvin Division VP International Onshore Miguel Sanchez Division VP Offshore Brian Woodward Division VP Drilling Services Tim McGarity President Jason McFarland A full list of IADC staff is available here: www.iadc.org/about/staff M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R DRILLING AHEAD • DEPARTMENTS Talent report: Industry will need to compete on more than salary BY LINDA HSIEH, EDITOR & PUBLISHER Recruiters and hiring managers know: It’s an employees’ market right now. Multiple industries are experiencing widespread skills shortages, and everyone is compet- ing for a shrinking pool of experienced talent. Just recently I saw an article come across my news feed highlighting the aviation industry’s woes trying to fill bag- gage handling and customer service posi- tions. Recruiting and retention tactics that they’re now trying range from providing onsite childcare services to giving out free iPhones and even free cars. The oil and gas industry is facing big talent gaps, too. This has been evident across conversations I’ve had with vari- ous industry leaders while working on this magazine, as well as in presentations I’ve seen at industry events over the past six to nine months. Not only are compa- nies encountering difficulties attracting new workers, but they are also having a much harder time, compared with previ- ous cycles, trying to hire people back. A highly coveted workforce According to the 2023 Global Energy Talent Index (GETI), the oil and gas sec- tor is “leaking talent in all directions. Its multi-skilled, mobile workforce is increas- ingly high prized by other industries.” The report is based on surveys conduct- ed in late 2022 with more than 10,000 pro- fessionals in five energy sectors, includ- ing oil and gas. It found that 80% of oil and gas employees have been tapped for another job in the past year. Staggeringly, 10% of employees said they have been approached 16 or more times to apply for a position outside of their current company. So, what can our industry do to become more competitive? Yes, we can still compete on salary. In the surveys, the single factor that oil and gas workers cite as having the most positive impact on their job satisfaction is their remuneration. However, having employee job satisfaction so highly depen- dent on financial benefits – when there are such big skills shortages in multiple sectors – means that spikes in labor costs are certain to continue. This is unhealthy at a time when organizations are already dealing with serious inflation pressures in their supply chain. There have to be other differentiators. What can we do? For one, companies really have to get better at listening to their employees. We already know that the younger generation seeks to work with a sense of purpose. But the surveys still found many oil and gas employees who say their views and values are ignored and do not influence com- pany policies. “Companies must shift from retrospective snapshots of workers, such as job satisfaction surveys, to continual employee engagement,” said Janette Marx, CEO of Airswift, the company behind the talent survey. Secondly, don’t scrimp and save on employee training and upskilling. Not only is it a cost-effective way for an organiza- tion to boost its capabilities, the report said, but it’s also associated with higher talent retention. Keeping pace with wider ESG trends may be another step companies can take. When oil and gas employees were asked if they believe their job has changed as a result of the energy transition, the largest percentage of respondents (38%) not only said yes but also said they enjoy their job more because of the change. It’s also worth noting that, when asked which other energy sector they’re most considering moving to, nearly half (49%) picked renewables. In conclusion, the report makes it clear that oil and gas employees are a highly attractive bunch to many other technical, high-paying industries. We can try to con- tinue competing on pay, but that may no longer be enough. DC Safer employees equals safer operations Delivers a standardized safety orientation for new employees in any region or operating environment. Incorporates vast industry knowledge and expertise of HSE professionals. Offers flexibility to develop courses to address unique company needs. Is open to all drilling and service contractors, commercial providers, educational institutions and agencies. www.iadc.org/iadc-rig-pass rigpass@iadc.org E-mail Linda Hsieh at linda.hsieh@iadc.org. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 5 DEPARTMENTS • DRILLING & COMPLETION NEWS New discovery near Troll field in North Sea marks Equinor's 7th in the area since 2019 Equinor made an oil and gas discovery, Røver Sør, close to the Troll field in the North Sea. Preliminary estimates show the discovery's size is between 17 million and 47 million barrels of recoverable oil equiv- alent, of which the majority is oil. The two exploration wells of the discovery were drilled by the Transocean Spitsbergen. This is the seventh discovery in this area since the autumn of 2019. The six earlier discoveries are Echino Sør, Swisher , Røver Nord , Blasto , Toppand and Kveikje . Equinor said it expects results from the next exploration well in this area, Heisenberg , to be ready in March. More exploration wells are also being planned . "As this discovery is close to the Troll field and other discoveries we have made in the area, we can already now state that it will be commercial,” said Geir Sørtveit, SVP for Exploration and Production West Operations. Equinor's partners in the license are DNO, Wellesley Petroleum and Petoro. Shelf Drilling jackups working offshore Egypt win 1-year contract extensions Neptune Energy's new well at Germany's Adorf gas fi eld is being drilled by KCA Deutag and expected to reach its fi nal depth of approximately 4,700 m in June. Neptune spuds 4th well in Adorf gas field, expects to reach final depth in June Neptune Energy has begun drilling at its operated Adorf Z18 gas production well in the municipality of Georgsdorf, northwestern Germany. The well is being drilled by KCA Deutag, with final depth of around 4,700 m expected to be reached in June . “The Adorf field is already an important contributor to domestic energy supplies in Germany, providing enough gas to heat more than 100,000 households,” said Andreas Scheck, Neptune Energy’s Managing Director in Germany. The Adorf Carboniferous gas field was discovered in 2020, and the first well – Adorf Z15 – was brought into production in October the same year. A second well – Adorf Z16 – increased Neptune’s production from the licence to around 4,000 BOEPD at the begin- ning of 2022. The third well – Adorf Z17 – reached its final depth at the end of 2022 and will be tested for production in Q1 2023. The construction of a modern treatment plant for the natural gas from Adorf Z17 and Z18 is ongoing. Drillship nets 910-day contract in Brazil Transocean announced the Dhirubhai Deepwater KG2, an ultra-deepwater drillship, has been awarded a 910-day contract by a national oil company for work offshore Brazil. The estimated backlog of $392 million excludes a mobilization fee of 90 times the contract dayrate. The new contract is expected to commence in Q3 2023. 6 Shelf Drilling recently announced contract extensions for two of its jackups working offshore Egypt. Rig 141’s contract was extended for one year in direct continuation of its current term with Gemsa Petroleum Company for operations in the Gulf of Suez . Following this extension, the expected availabil- ity of the rig is February 2024. A one-year contract extension was also secured for the Trident 16 jackup in direct continuation of its current term with Belayim Petroleum Company (Petrobel) for operations in the Gulf of Suez . The contract includes a further one-year option period. The Trident 16 has been working with Petrobel in the Belayim fields since 2015. Following this extension, the expected availability of the rig is February 2024. Vito begins production in deepwater GOM Production has started at the Shell-operated Vito floating production facility in the US Gulf of Mexico (GOM). With an estimated peak production of 100,000 BOED , Vito is the com- pany’s first deepwater platform in the GOM to employ a simpli- fied, cost-efficient host design. The original design for Vito was rescoped in 2015, resulting in a reduction of approximately 80% in CO 2 emissions over the lifetime of the facility, as well as a cost reduction of more than 70% from the original host concept. Vito also serves as the design standard for Shell's Whale project, which will feature a 99% replication of the Vito hull and 80% of Vito’s topsides. In separate news, Shell's Pensacola discovery in the UK North Sea has the potential to be “one of the largest natural gas discoveries” in the region in over a decade, according to a co- owner of the license containing the discovery, Deltic Energy. Deltic, which owns 35% of License P2252 alongside Shell’s 65% and ONE-Dyas’ 5%, announced a “highly positive outcome” from Well 41/05a-2, the first exploration well at Pensacola. The well was drilled to a total depth of 1,965 m true vertical depth subsea , and the presence of mobile gas and oil in the pri- mary Zechstein Hauptdolomite carbonate target interval was confirmed via wireline logs. The well confirmed a reservoir thickness of 18.8 m . Based on the data collected during drilling and testing, Deltic estimates the Pensacola discovery to contain P50 EUR of 302 billion cu ft. The company also said it expects the dis- covery will open a new Zechstein play in this mature basin. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R DRILLING & COMPLETION TECH DIGEST • DEPARTMENTS RSS sets record, saves 7 days of drilling time offshore UK 160 Amplitude,e,e, rprprpmm Amplitud 140 120 100 80 60 40 20 0 Non-dampene Non-dam penedd pene Competitor HFTO HF TO supp supprereressor ssor Using the suppressor tool decreased shock peaks by 64% relative to non-damp- ened BHAs, according to simulations SLB performed using its IDEAS platform. Simulations demonstrate how HFTO suppressor tool can reduce shock amplitude in Permian wells Recent simulations have shown that using shock and vibration suppressor technology can reduce shock amplitude by 64% in Permian Basin wells, com- pared with offset wells, according to SLB. Operators in this region often experi- ence excessive shock and vibration, par- ticularly high-frequency torsional oscil- lation (HFTO). Excessive HFTO is the leading cause of downhole tool failures, including cracked drill collars, broken measurement tools and electronic com- ponent failures. These can lead to addi- tional trips, time and cost. In the past, Permian operators have used different types of shock and vibra- tion dampening tools to mitigate the effects of HFTO, but success has typically been limited. Field data showed simi- lar spikes in amplitude and frequencies between dampened and non-dampened BHAs. These high and sporadic shock amplitudes resulted in costly, fatigue- induced drillstring failures, including twist-offs and broken components in the rotary steerable and MWD equipment. SLB designed its HFTO Suppressor tool to reduce downhole shock and vibra- tion while drilling in challenging for- mations. The company used IDEAS, its integrated dynamic design and analysis platform, to simulate HFTO at various points throughout the BHA. This helped SLB engineers to determine the ideal location for the HFTO Suppressor within the assembly. The IDEAS simulations verified that the mechanical suppressor tool could reduce shock amplitude by 64% com- pared with drillstrings without dampen- ing tools. Additionally, the data revealed a 48% reduction in shock amplitude com- pared with other shock and vibration dampener tools. In a North Sea production well, an oper- ator sought to drill from a whipstock set in 13 ⅜ -in. casing in soft Tertiary formations and complete the section drilling through hard chalk formations. Other challenges included kicking off successfully from the main bore, as well as overcoming challenging directional profile with anti- collision. To achieve this, Weatherford deployed an integrated solution that included the 950 Magnus rotary steerable system (RSS). The strategy was to use the RSS on a sec- ond bit run through the chalks. Based on previous offset wells, the main challenges expected for this section were fluid losses, wellbore stability, abrasive wearing and vibration. The well profile was S-shaped with a 3-3.5° dogleg severity requirement, with the maximum inclination building to 40° and turning a total 246° azimuth from kickoff to section TD. The Magnus RSS drilled a total footage of 6,080 ft across the section, maintaining a rate of penetration average of 50 ft/hr. The optimized efficiency saved the opera- tor seven days of drilling time. The run met all directional objectives and even achieved a record for the longest- drilled run in the 12 ¼ -in. section to date in the field. LWD ultrasonic imager identifies fractures in Turkey well In Turkey, an operator was encounter- ing challenges logging the well due to borehole conditions. The operator was seeking high-resolution borehole image data to identify fractures in the vertical well, which was filled with 14.84 lb/gal oil-based mud. For this project, Weatherford ran its UltraWave logging-while-drilling (LWD) ultrasonic imager. The logging suite also included a real-time telemetry system, gamma ray, multi-frequency resistivity and sonic tools. UltraWave allowed the operator to directly identify fractures and other features in the borehole even in the presence of heavy mud and a high concentration of solids. The LWD tools were able to acquire gamma ray, resis- tivity and sonic data together with high- amplitude images from the UltraWave for reservoir evaluation and completion planning. Weatherford’s Magnus RSS helped to save an estimated seven days of drill- ing time in a North Sea production well by overcoming challenges around fl uid losses and wellbore stability. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 7 DEPARTMENTS • ENVIRONMENT, SOCIAL AND GOVERNANCE IADC North Sea Chapter calls for balanced approach to UK’s energy transition The site of ADNOC’s fully sequestered CO 2 injection well in a carbonate saline aquifer. The company says it expects to initially fully sequester at least 18,000 tons of CO 2 per year in Abu Dhabi’s onshore carbonate aquifers. ADNOC begins work on injection well as part of fully sequestered CO 2 injection project in carbonate rock ADNOC has begun work on what the company says will be the world’s first fully sequestered CO 2 injection well in a carbonate saline aquifer. The company expects to begin injecting CO 2 in Q2 2023 . “At Al Reyadah, ADNOC deployed the region’s first carbon capture project at scale, and we are taking another tangible step to deliver on our $15 billion decar- bonization action plan with the world’s first fully sequestered CO 2 injection well,” said Yaser Saeed Almazrouei, ADNOC Upstream Executive Director. Th e project follow s guidance from ADNOC’s Board of Directors to accelerate delivery of its low-carbon growth strat- egy and for the allocation of $15 billion to decarbonize ADNOC’s operations. Once operational, the project will ini- tially aim to fully sequester at least 18,000 tons of CO 2 per year via injection into Abu Dhabi’s onshore carbonate aquifers . The well location for CO 2 injection, as well as targeted geological forma- tions, were identified using the results of ADNOC’s 3D seismic survey and the com- pany’s subsurface modeling capacity. ADNOC says it expects the project will contribute to the production of lower- carbon ammonia, a cost-competitive hydrogen carrier that can be scaled up quickly and has lower-carbon intensity than other fuels. The project will also be monitored and assessed using advanced technology at ADNOC’s Thamama Digital Centre of Excellence . Denbury to develop CO 2 sequestration in Wyoming Denbury finalized a n agreement for the right to develop a CO 2 sequestration site on nearly 15,000 acres in Campbell County, Wyo ., directly underneath the company’s Greencore CO 2 Pipeline. Potential CO 2 sequestration capacity of the site , named Corvus, is estimated at 40 million metric tons. The company also announced goals to execute additional CO 2 transporta- tion and/or storage agreements from 8 both brownfield and greenfield projects so that, by the end of 2023, Denbury’s cumulative agreements will cover CO 2 emissions totaling 30 million metric tons per year. Denbury is working to further expand its dedicated CO 2 storage portfolio with the acquisition of additional sequestra- tion sites; these will likely be located near areas with high concentrations of current and future CO 2 emissions. The IADC North Sea Chapter issued a statement in February urging the Scottish and UK governments and all areas of the oil and gas industry to cooperate to better effect and ensure the sector takes a bal- anced, long-term approach to the energy transition. This comes in response to the North Sea Transition Authority stating that “a wave of new opportunities” for the UK’s offshore supply chain will be created by projects following a study it conducted in conjunction with the Global Underwater Hub . While the IADC North Sea Chapter back s the report’s general findings, with oil and gas supporting 75% of the UK’s energy requirements, it believes taking a longer-term outlook is needed in order to secure jobs across the industry, stabilize the UK economy and ensure a safe transi- tion to cleaner energy. “The recently announced projects rep- resent a fraction of what is truly needed to meet growing UK energy demands, as well as strengthen regional energy security, but frustratingly only amounts to minimal opportunities for drilling con- tractors,” said Darren Sutherland, Chair of the IADC North Sea Chapter. He added: “The oil and gas industry is aware of the environmental need to change the way the sector operates. However, it is a process that is likely to take decades to achieve and will involve all areas of industry, including drilling contractors. The transition to cleaner energy has to be done safely, sensibly and securely in terms of the national economy, national energy supply and pro- tection of jobs across the UK.” IADC Regional Director Stuart Clow said, “The North Sea continues to be a significant source of the UK’s energy sup- ply, and drilling contractors are ready to work with operators and governments to ensure that supply is not interrupted. The experience, knowledge and ingenuity of workers from the far north of Scotland to the south of England is driving the energy transition in a similar way that generations before them built the oil and gas industry into the crucial economic driver it has become.” M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R ENVIRONMENT, SOCIAL AND GOVERNANCE • DEPARTMENTS Nabors affiliate to merge with solar power company Nabors Energy Transition Corp (NETC), an affiliate of Nabors Industries, has entered a business combination agree- ment with Vast, a solar power company. NETC is a special purpose acquisition company that Nabors formed in 2021, and Vast marks Nabors’ ninth and largest energy transition investment to date. Nabors also recently launched Energy Without Compromise, the company’s vision to guide its energy transition efforts. The vision aims to unite Nabors’ sustainability efforts from both its core business and its other energy initiatives. Under the Accelerated Energy Decarbonization Scenario (AEDS), part of GECF Global Gas Outlook 2050, natural gas-based blue hydrogen with CCS will ac- count for 40% of total hydrogen output by 2050. That would require more than 930 billion cu m of natural gas. GECF commentary: Natural gas-based blue hydrogen with CCS will be a key player in the energy transition The Gas Exporting Countries Forum (GECF) recently issued a commentary highlighting the critical role that blue hydrogen can play in the energy transi- tion. Compared with green hydrogen, which is produced through the electroly- sis of water using renewable power, blue hydrogen is natural gas based. As such, it is currently more cost-competitive because it uses the existing natural gas infrastructure and technologies for car- bon capture and storage (CCS). While cost depends on factors like location, production method and scale of produc- tion, each kilogram of blue hydrogen is currently estimated to cost between $1.5 to $3, while green hydrogen is estimated to cost up to $6/kg. However, as renew- able energy sources become cheaper and more widespread, the cost of green hydrogen is expected to decline – by an estimated 50% by 2030. The cost of blue hydrogen is also expected to fall in the next decade, as CCS technology improves and becomes more widely adopted. Under the GECF’s Accelerated Energy Decarbonization Scenario (AEDS), it’s expected that approximately 200 million tonnes of hydrogen will be generated using natural gas with CCS, accounting for 40% of total output, by 2050. This level of hydrogen production will require more than 930 billion cu m of natural gas by that year, according to the AEDS. Cross-border CO 2 storage being studied in Europe CapeOmega and Neptune Energy announced NoordKaap, a concept for cross-border CO 2 storage for industri- al emitters across Europe. NoordKaap would involve transporting CO 2 via ves- sels suitable for directly injecting the CO 2 at offshore locations and for terminal offloading . The project will examine the potential for a network-based approach to carbon capture & storage (CCS) via marine transport . The overall objective is to pro- vide cost-effective, scalable infrastructure solutions to facilitate large-scale, flexible CO 2 transport and storage from multiple industrial emitters clusters. NoordKaap aims to offer CCS solutions to industrial clusters where ship trans- port is the primary or earliest available export option. It would provide access to CO 2 subsurface storage sites offshore the Netherlands and Norway . Report shows geothermal industry in Texas may be poised to make a breakthrough Researchers at five universities – UT Austin, Southern Methodist University, Rice University, Texas A&M University and the University of Houston – as well as the University Lands Office and the International Energy Agency have pub- lished “The Future of Geothermal in Texas: The Coming Century of Growth & Prosperity in the Lone Star State.” The report includes analyses of the location and quality of Texas geothermal resources, evaluations of technology developments, the role that the oil and gas industry can play , as well as environmental, regulatory, economic and legal issues . Researchers hope the report can provide a scientific basis for informed decision making among elected officials, regulators and others . The map at right shows the temperature of Texas geothermal resourc- es at 6.5 km depth. M uch of the state is believed to be at or near conventional minimum viable temperatures for geother- mal power generation. Source: Adapted from SMU Geothermal Laboratory D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 9 DEPARTMENTS • OIL & GAS MARKETS Westwood forecasts marketed utilization of offshore rigs will average 95% this year Offshore rig activity was robust in 2022 and will likely remain so throughout 2023, according to recent insights shared by Westwood Global Energy Group’s Head of RigLogix, Terry Childs. On the jackup side, marketed utilization reached 91% in December, and 398 of 437 marketed units were under contract or committed for work. This ramp-up was led by the Middle East, with a large number of jackups – including existing units that had been stacked as well as newbuilds – receiving multi- year contracts. Mr Childs also noted that jackup dayrates have increased in almost all markets, mostly growing by double digits. This year, he expects global marketed utilization for jackups to increase to an average 95%, up from 90% last year. For floating rigs, marketed utilization ended last year at just under 90% in December. However, if viewed separately, drillship demand was much stronger at an average 93% utilization for the year, while semis saw a much weaker 82% utilization rate. The US Gulf of Mexico and South America both led the way in terms of floater demand ; the former even saw 100% marketed utilization for the nearly entire year, from February through December. Dayrates also improved throughout 2022, particularly for drillships. The average fixture rate for drillships rose to just under $360,000, up from around $230,000 in 2021. Mr Childs noted his continued expectation for decreased floater availability in 2023. For drillships, the marketed supply and demand will remain tight, keeping utilization around 95%. Demand for semis may be impacted in the North Sea due to the UK windfall tax, he said, where some operators have said they’re reconsidering previously planned drilling programs, but globally the marketed utilization is still expected to average 94%. 10 Global marketed utilization rates for both jackups (top) and fl oaters (bottom) improved last year, leading to strong dayrate growth, according to Westwood. Jackup utilization averaged 90% in 2022, buoyed in particular by demand in the Middle East. Floater utilization was also robust, although the favor tilted much more toward drillships than semis . Longer-term contracts may offer more stability as Europe grows LNG imports More than 65% of UK project starts from 2023-2027 expected to be in upstream The competition for LNG between Europe and Asia is grow- ing and set to intensify in the next two years, a ccording to Shell’s LNG Outlook 2023. European countries, including the UK, imported 121 million tonnes of LNG in 2022, an increase of 60% compared with 2021 . This enabled the country to withstand a slump in Russian pipeline gas imports . A 15 million tonne fall in Chinese imports combined with reduced imports by South Asian buyers helped European countries to secure enough gas , but Europe’s rising appetite for LNG pushed prices to record highs and generated volatility in markets around the world. LNG is becoming an increasingly important pillar of European energy security, supported by the rapid development of new regasification terminals in northwest Europe . Steve Hill, Shell’s Executive Vice President for Energy Marketing, said the war in Ukraine and resulting impacts on energy security has “underscored the need for a more strategic approach – through longer-term contracts – to secure reliable supply to avoid exposure to price spikes.” Total global trade in LNG reached 397 million tonnes in 2022. Industry forecasts expect annual LNG demand to reach 650 mil- lion or even surpass 700 million tonnes by 2040. The upstream segment dominates upcoming oil and gas projects in the UK, accounting for more than 65% of the total project starts anticipated between 2023 and 2027, according to GlobalData . Its new report shows that , of the 94 projects expected to start operations in the UK during that time period, 61 will be upstream projects . Many of them will be in the North Sea’s shallow waters, said Himani Pant Pandey, Oil & Gas Analyst at GlobalData . “The shallow waters of the North Sea still have an important role to play in promoting the UK energy security, especially in the context of weaning away from the Russian oil and gas supplies.” Rose Bank will be a key project, with a total production capac- ity of 121,000 bbl of oil equivalent per day. To be operated by Equinor , the project is expected to commence operations in 2026. “Despite concerns from the climate activists and an increase in windfall tax by the UK government on the oil and gas sec- tor, the latest North Sea oil and gas licensing round in 2022 attracted around 115 bids, an increase of 11 when compared to the previous licensing round in 2019,” Mr Pandey said. “The latest licensing round reflects efforts of the UK government to boost oil and gas production in the country.” M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R OIL & GAS MARKETS • DEPARTMENTS 2022 discoveries drive value creation of exploration projects to record levels Cashflow analysis of 25 North Nor th American independent E&Ps E&P s . F. Forecasted orecasted cashflow assuming current trends in production, produc tion, operating expenditur exp enditur enditure,e,e, capita capitall expenditure,e,e, dept repayments, expenditur repayments , share purchases, purchases , dividends, dividends , and other cash expenses f for or 25 companies analyzed. Operating cash fl ows in the upstream market are expected to remain high in the foreseeable future, even if oil prices drop to $65-70/bbl, according to McKinsey. High cash flows among North American E&Ps likely to drive new consolidation wave, McKinsey report shows McKinsey and Company says it expects a fresh wave of M&A in the North American upstream market in the coming years, fueled by high operat- ing free cash flows. In a new report, the firm analyzes historical cash flows and projected operational and financial performance for the leading 25 North American E&P companies. Operating cash flows are projected to remain high, with levels between $70-$90 billion in 2023 and between $50-$70 billion to 2027 – even if oil prices drop to $65 to $70/bbl. The E&Ps analyzed are expected to generate a total of $140-$200 billion in operating cash flow in 2023. Operators are taking advantage of these high cash flows by pulling all the traditional levers of capital management. For example, industry debt load decreased by $25 bil- lion from 2021 to 2022 and is forecast to fall by a n additional $15-$20 billion by 2027. With debt burden reduced, returning shareholder value will be pri- ority, and McKinsey expects dividends to climb to between $30-$40 billion over the next year. But with a high volume of cash, these traditional levers will hit a natural cap. McKinsey’s analysis shows that only inorganic growth is unbounded going forward, suggesting that cash will be deployed through M&A. Tom Grace, Partner at McKinsey & Company, said, “Even after these uses of cash have been exhausted, the industry is likely to remain cash-flow positive in 2023 and beyond, with a ‘war chest’ of $100-$230 billion. The primary tool left in the corporate finance toolkit is deploy- ment of cash through M&A. A common refrain from industry veterans discuss- ing M&A is, ‘You are either at the table, or you’re on it.’ This is a harsh reality, but companies with strong M&A capabilities and bold strategies often exit the cycle fully fed and healthy.” Industry trends suggest that multiple M&A strategies are driving this next wave of consolidation. Basin consolida- tors will likely look to add scale and lever- age operational advantages to achieve outsized returns. Integrators may seek to add assets in adjacent portions of the value chain to expand margins and increase resilience. The bold will prob- ably use a portion of their cash to seed businesses to reshape their portfolios and position for the energy transition. “The oil and gas industry is entering a period of unprecedented uncertainty characterized by the energy transition, evolving investor sentiment, and mount- ing energy security concerns,” said Jeremy Brown, McKinsey Consultant . “Now is not the time to bask in the glow of recent success. As in the past, success- ful industry players will work tirelessly to define and deliver a strategy rooted in sound M&A investments to accelerate their future growth and performance.” The global oil and gas exploration sector had its strongest year in 2022 in more than a decade. In its work to improve portfolios by adding lower-carbon, lower-cost advan- taged hydrocarbons, the sector created at least $33 billion of value and achieved full-cycle returns of 22% at $60/bbl Brent prices, according to a recent report from Wood Mackenzie . It states that exploration well numbers were less than half the numbers during pre-pandemic years, yet the total volume of 20 billion bbl of oil equivalent matched the average annual volumes of 2013-2019. “Explorers were able to drive very high value through strategic selection and focusing on the best and largest pros- pects,” said Julie Wilson, Director of Global Exploration Research at Wood Mackenzie. The highest value came from a new deepwater play in Namibia, as well as resource additions in Algeria and other deepwater discoveries in Guyana and Brazil . “The average discovery last year was over 150 million barrels of oil equiva- lent, more than double the average of the previous decade,” she said. National oil companies and majors con- tinued to lead in exploration , accounting for almost three quarters of new resources discovered . These include companies like TotalEnergies, QatarEnergy and Petrobras. Newly discovered resources in 2022 created at least $33 billion in value even though the number of exploration wells were less than half of pre-COVID years. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 11 DEPARTMENTS • DRILLING & COMPLETION VIDEOS MORE VIDEOS ON DRILLINGCONTRACTOR.ORG » Patterson-UTI showcases performance-enhancing, emission-reducing rig technologies On 26 January, Patterson-UTI hosted a showcase event at its rig- up yard in Houston, Texas, highlighting the company’s low-carbon technologies. In this video taken from the event, DC speaks with several of the company’s leaders, including Mike Holcomb, Chief Operating Officer of Patterson-UTI Energy. » SOCAR AQS looks to grow with new land rigs, drive down well costs with expanded capabilities In this video, Samir Mollayev, General-Director of SOCAR AQS, explains how the company is working to identify ways to reduce well costs for operators, including enhancing the company’s drilling engineering and geology capabilities. Emissions reduction is another key focus, as is development of SOCAR AQS’ technical workforce. » New addition to NOV Max platform allows for real- time monitoring of equipment during completions Through its Max Completions software, NOV is looking to enable the large-scale collection, aggregation and analytics of real-time equipment data during completions operations. In this video, Travis Thomas, Director of Digital Completions, discusses how to quantify value from the platform and how operational uptime can be impacted. 12 » SOCAR: Caspian faces new challenges and opportunities as it moves to exploring deeper waters At the 2023 IADC Drilling Caspian Conference in Baku, Azerbaijan, DC spoke with Yashar Latifov, VP Field Development for SOCAR, about challenges related to the company’s exploration of deeper waters, the Caspian Sea’s landlocked nature, and the area’s geology, which features a lot of unconsolidated fine sand formations. Halliburton: Automation enables companies to gain clearer picture in frac operations The incorporation of automation and AI in hydraulic fracturing operations has been a key focus area for Halliburton in recent years. DC spoke with William Rhule, Strategic Business Manager, at the 2023 SPE Hydraulic Fracturing Technology Conference about its SmartFleet operating system and its Zeus electric pumping unit. Frac monitoring app adopts standardized data format to boost productivity, interoperability In this video, DC talks with Brett Chell, Founder and CEO of Cold Bore, about how standardizing data can help boost efficiency during a frac operation. Its SmartPAD application now uses a standard data format allowing connections from different control systems so they can communicate with one another without the need to clean data. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R IADC Drilling Onshore CONFERENCE & EXHIBITION 18 MAY 2023 H YAT T R E G E N C Y HOUSTON WEST HOUSTON, TEXAS GOLD SPONSORS SILVER SPONSORS EVENT SPONSORS www.iadc.org/event/2023-iadc-drilling-onshore-conference-exhibition For more information, contact IADC by phone at +1.713.292.1945 or via email at iadcconferences@iadc.org I N NOVATI N G WH I LE DR I LLI N G Going the distance: Drillers push innovations to drill extended laterals Extreme depths necessitate solutions to handle high torques and lateral vibrations, ensure accurate horizontal wellbore placement BY STEPHEN WHITFIELD, ASSOCIATE EDITOR E xtended-reach drilling has become not only more common in recent years but also more extended than ever. Operators are drilling longer and longer laterals in order to access previously untapped hydrocarbons, often from existing offshore platforms or from one single pad location. The value propositions are clear: Fewer number of wells have to be drilled to achieve the same production goals, and there is lower cost per foot. “We’re seeing dramatic increases in lateral levels in many of the areas we’re working,” said David Millwee, VP – Drilling Performance at Patterson-UTI. “The 7,500-ft laterals are kind of Highlights In some shale basins, 10,000-ft laterals are becoming standard even as 12,000- and 15,000-ft laterals are pushing rig engines, top drives and mud pumps to new limits. New floor wrench designed with enhanced gripping and sensors can help to prevent over-torqued connections. To maximize chance for one-run laterals, downhole tool reliability and accurate well placement are key. Using AI-enabled bit guidance software can help increase lateral footage placed in drilling window. 14 going away, and we’re seeing more of a 10,000-ft standard, with some companies pushing 12,000 or 15,000 ft. For the operator, that additional 2,000 or 3,000 ft of lateral wellbore gives them better paybacks than trying to drill another well.” On the flip side, extended-reach wells are notoriously challeng- ing and require specialized planning to execute. It can be difficult to hit target zones. Lost circulation and wellbore instability risk is higher. Downhole tool reliability is also challenged. “As we’re drilling deeper laterals, we’re seeing that the current tools we have are hitting their technical limit,” said Chris Jones, Field Service Manager at Helmerich & Payne (H&P). Addressing these challenges will require companies to consid- er both operators’ short-term production demands and long-term needs to reliably handle downhole stresses. In this article, DC speaks with Patterson-UTI and H&P about recent efforts to enable better drilling of extended-reach wells. Handling excessive torque downhole In recent years, H&P has made significant upgrades to its rig equipment to help handle the challenges associated with longer laterals in extended-reach wells. These include an engine pack- age to increase the rig’s power output, upgrading top drives from 800 hp to 1,200 hp, as well as mud pumps with higher pressure capacity to handle the increase in fluid pressures and flow rates. More recently, the company has also been focused on new ways to address challenges around the surface torque limit on drill pipe and couplings. Longer lateral wells typically require drill pipe connections to be exposed to extreme torques that may render them ineffective in getting the drill string to location; sealability can also be compromised. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G Extended-reach drilling has become more common and more extreme in recent years as operators seek to generate more production out of each well, but drilling long laterals comes with significant challenges, like excessive torque and damaging lateral vibrations. Last year H&P launched its Failure Prevention Package to address problems often encountered in long later- al s. The company says it has already seen fewer unplanned trips and more footage drilled between unplanned trips. The two points of contact that a standard torque wrench has with the drill pipe can create a slight bowing effect on the drill pipe, and the wrench can sometimes relax its grip on the pipe as it moves downhole. These two variables increase the likeli- hood of inaccurate readings of the torque value on each connec- tion, which can lead the driller to apply an excessive amount of torque. “If you over-torque downhole, you’re having to rig up manual tongs to break your connections, which slows the whole well cycle down. Additionally, you’re damaging pipe and making it unusable. That’s added costs and added time we need to avoid,” Mr Jones said. To combat this challenge, H&P worked with a third-party equipment manufacturer to develop the HexGrip 120 automated floor wrench , which can handle higher torques than a con- ventional torque wrench. Rather than using two dies to make contact with the drill pipe like a conventional wrench, the new wrench contains six dies, creating a concentric gripping effect where the dies grip around the circumference of the drill pipe. The improved gripping of the six-point torque wrench also translates to less connection deformation on the tool makeup and improved torque accuracy. The new wrench also contains sensors so it can provide an exact reading of the back-off torque inputs, or the torque needed to break a given drill pipe connection. This gives the driller a more accurate view of how much torque is being applied to the drill pipe at any given time. “With the type of downhole environments we see, there will be sections where you’re adding torque, so you need to know exactly how much is going to break out,” Mr Jones said. “If you’re not correct, you’re going to see a lot of problems when you have to go downhole and break the connections loose. Having that functionality to adjust and make sure our torque loads are exactly what we want them to be and what we need for the hole conditions – that helps to avoid a lot of the problems we face.” H&P has been field-testing the floor wrench on a Permian rig since early 2022, and a second wrench was added to a rig in Oklahoma this year. The company foresees adding more of these tools across its rig fleet this year. The extreme torques seen in extended laterals can also increase the possibility of encountering damaging lateral vibra- tions, resulting in stick-slip, whirl and overall downhole tool failure. This can lead to longer drilling times, higher costs D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 15 I N NOVATI N G WH I LE DR I LLI N G LEFT: H&P’s HexGrip 120 automated floor wrench uses six dies to make contact with the drill pipe; that compares with two dies on a conventional wrenc h. The result is a concentric gripping effect, where the dies grip around the circumference of the drill pipe. This allows the wrench to better handle the higher torques often seen in extended laterals. RIGHT: H&P has seen a con- sistent increase in average lateral length for its horizontal wells , with averages for the Midland and Appalachian basins each surpassing 10,000 ft in 2021. and even increased emissions and safety risk from the need to retrieve stuck pipe. H&P introduced its Failure Prevention Package in mid-2022, comprised of three solutions to better tackle this issue: FlexB2D 2.0, FlexTorque and StallAssist tech- nology. The main components of the Failure Prevention Package work together to counteract problems commonly seen in long laterals. The FlexB2D 2.0 software automatically and consis- tently stages drilling set points after tagging bottom; FlexTorque mitigates stick-slip and bit whirl; and the StallAssist technology detects, mitigates and recovers from downhole stalls. According to H&P, over the past six months, rigs in the Delaware Basin of West Texas running the Failure Prevention Package experienced 37.1% fewer unplanned vertical trips and 37.3% fewer unplanned lateral trips per rig per month. Those rigs also saw 9.6% more vertical footage drilled and 17.7% more lateral footage drilled between unplanned trips. Improving bit guidance At Patterson-UTI, a guiding principle while drilling extended laterals is the value of keeping downhole tools in the hole as long as possible, as it helps to minimize the number of runs needed. “The longer you push your footage, the longer you’re going to be in the hole. You’re going to have an exposed wellbore before you can get the casing set. The better we can get with managing our downhole tools, the better we have assurance of getting casing to bottom in one run,” Mr Millwee said. “We want to try to get as many one-run laterals as we can, so that we can have less of that exposed wellbore before we have to change the BHA for the cus- tomer. Being able to stay longer in the hole mitigates everyone’s risk.” Recognizing that downhole tools have to stay in the hole for longer and longer distances, Patterson-UTI has been focusing on improving the accuracy of horizontal wellbore placement in the wells it drills. In extended laterals, the risk of missing the target zone increases as the BHA moves further downhole; the risk is even higher if the target is thin and the subsurface varies greatly within a short distance. If drillers have to course-correct with the 16 BHA, well productivity may be reduced. “When you go from 10,000 to 15,000 feet, that window of uncertainty may stretch a multitude of feet. When we’re being told to hold the pay zones in narrow windows at extended depths, the uncertainties can be more con- cerning and impactful,” Mr Millwee said. Over the past five years, Patterson-UTI and two of its subsidiar- ies – Superior QC and MS Directional – have worked to develop HiFi Guidance, a software program that utilizes proprietary AI algorithms to refine the calculation of rotational tendencies and motor yields in real time, allowing for forward projections and optimized slide scheduling through each well section. When combining this cloud-based software with rotary steerable sys- tems, it can enhance and reduce change sequencing, thus reduc- ing overall downlinking times. The forward projections provided by the software enable the system to maximize footage placed within the window, Mr Millwee said. “When you’re drilling these long laterals, you need to be as efficient as possible. If I go off in the opposite direction from the plan, I could be leaving hydrocarbons in the wellbore,” he said. “When you can accurately place and reduce the risk of uncertainty with the well, we get better at drilling the well.” The technology development was enabled by Patterson-UTI’s 2018 acquisition of Superior QC, a provider of software focused on wellbore placement and data analytics . “We’re seeing dramatic increases in lateral levels in many of the areas where we’re working. The 7,500-ft laterals are kind of going away, and we’re seeing more of a 10,000-ft standard, with some companies pushing 12,000 or 15,000 ft.” - David Millwee, Patterson-UTI M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G or an f a list o Sc Upon its launch in 2022, HiFi helped Patterson-UTI see a 27.8% increase in the amount of lateral footage placed in the drilling window compared with its average in the previous year. After the system was rolled out to the company’s APEX rigs, it saw an 8% increase in average daily footage drilled from 2021 to 2022, and an average well depth increase of 500 ft in the same time span. In one Eagle Ford project, Patterson-UTI deployed the software system in an area where high ROP was common, so there was an increased need for precise lateral targeting and deliberate steer- ing decisions. The company determined that reducing the sliding percentage and the overall number of slides could yield a reduc- tion in drilling time, resulting in a smoother wellbore. A pre-job analysis of directional drilling in offset wells revealed an average of four slides per 1,000 ft, with a 35% variance between the day and night directional driller. For this project, the operator had the directional drillers follow their standard operating proce- dure for four offset wells on the pad, and a fifth well would utilize the HiFi Guidance system to make all steering decisions in the lateral. Results showed the four offset wells had an 8.6% average slide percentage, compared with just 3.3% for the fifth well – this marked a 62% reduction in sliding percentage in the lateral. Additionally, the number of slides was reduced by 46% when comparing the directional drillers versus the HiFi Guidance sys- tem in the lateral. Drilling time was reduced by 17 hours, resulting in a direct savings of $35,000. DC Algorithms built into Patterson-UTI’s HiFi Guidance system refine the calculation of rotational tendencies and motor yield in real time, optimizing slide schedulin g. The company says it has seen a 27.8% increase in lateral footage placed in the drilling window since launching the technology last year. SERVICE & REPAIR CENTERS ur Licensee s f o WORLDWIDE QUALIFIED & LICENSED BY TSC DRILL PIPE LOCATED BY YOUR WELLSITE FASTER TURN AROUND MEANS LESS DOWN TIME LOW COST OF OWNERSHIP HAVE A PREFERRED SHOP YOU WANT LICENSED? CALL NOW +1 832-230-8228 www.drillpipe.com D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 17 I N NOVATI N G WH I LE DR I LLI N G Preventing lost circulation, instability offshore Malaysia BY STEPHEN WHITFIELD, ASSOCIATE EDITOR From an operator’s perspective, minimiz- ing downhole losses while maintaining wellbore stability is one of the biggest challenges to successfully drilling an extended-reach well. Michael Yao, Senior Rock Mechanics Advisor at Hess, noted that extended laterals tend to have more breakouts than vertical or less deviated wells. This means a higher mud weight is often required to keep the wellbore stable. Equivalent circulating density (ECD) is also typically higher. Moreover, there is a greater uncertainty in how the cuttings transport will behave, which can make hole cleaning more difficult. If ECD, mud weight and hole cleaning are not managed properly, the operator runs the greater risk of wellbore instabil- ity, borehole collapse and lost circulation, all of which can increase the potential for the well to miss its target depth and to add significant costs to the drilling program. “If you’re drilling a less deviated well, the drilling margin is typically wide. We have much more freedom to navigate mud weight and ECD between the pore pres- sure and the fracture gradient. It’s like driving in light traffic,” Dr Yao said, noting that drilling an extended-reach well is more akin to driving in a traffic jam. “Hole cleaning becomes more challenging, and the difference between the ECD and mud weight is much larger due to the hydrau- lics of these wells. There are much more challenging conditions to maneuvering the mud weight and ECD.” Further, addressing the dual challenges of lost circulation and wellbore instability in extended-reach wells requires a holistic approach to strengthening the wellbore if the formation is depleted, he said. This has to be a collaborative effort among the operator’s drilling engineers, subject mat- ter experts and rig site teams, as well as the service companies. Dr Yao highlighted one such effort on a shallow gas field offshore Malaysia at an IADC Drilling Engineers Committee Technology Forum in November. In its most recent extended-reach well in the formation, the company had experienced lost circulation in the reservoir section, which showed unexpected depletion from production, and well startup was delayed. Hess drilled the 8 1/2-in. section of an extended-reach well offshore Malaysia with an ECD ranging from 12.0-12.6 lb/gal and a 10.8-gal mud weight. By maintaining these parameters, the operator was able to drill the section without any losses. 18 With this well, which had a measured depth (MD) of 12,642 ft and true vertical depth (TVD) of 3,925 ft, Hess aimed to pre- vent losses and maintain wellbore stabil- ity in the 8 ½-in. lateral section. Modeling showed the level of breakout at different mud weights ranging from 10.6 lb/gal to 11.2 lb/gal. Understanding limited level of breakouts need to be tolerated, Hess chose a 10.8-lb/gal mud weight for the section as a reconciliation between wellbore stability and lost circulation concerns. Hydraulics modeling showed that ECD for the section would range between 12.3- 12.9 lb/gal at the 10.8-lb/gal mud weight. However, even at that mud weight and ECD, the section could still see losses if the pore pressure fracture gradient was on the low side due to depletion. Hess formulated a “stress cage” to prevent losses in case of low pore pressure fracture gradient. A stress cage is a wellbore strengthening model of the mechanism that boosts up the fracture gradient to be above expected ECD through the addition of mud additives. The 8 ½-in. section was drilled at an average ROP of 50 ft/hr, with a pump rate of 450 gal/min and a rotation of 140-150 rev/min. The ECD stayed primarily within the range indicated by hydraulics mod- eling (12.0-12.6 lb/gal). Stress cage was implemented prior to drilling into depleted reservoir as precaution. Reservoir pressure was then measured by the Formation Pressure While Drilling (FPWD) tool once the sensor was in con- tact with permeable formation. Based on that, the fracture gradient was expected to be higher than the ECD. The stress cage materials were deemed unnecessary and then screened out. The well was subse- quently drilled to total depth (TD). Dr Yao noted the importance of collabo- ration between different stakeholders in drilling the well without any losses. “We put tremendous scrutiny into our plans for the wellbore strengthening material ahead of time, and during the operations we had a lot of eyes looking at screens while the drilling was happening to see how every- thing was performing. Communication and collaboration were key during the whole process.” The well also provides a valuable blue- print for handling similar wells in the future, he added. DC M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R IADC DDR Plus™ THE NEW IADC STANDARD FOR DRILLING DATA RECORDING The IADC DDR Plus™ is a print and electronic data collection system aimed at securing accurate and relevant drilling data that industry can use to assess performance against drilling Key Performance Indicators, and is available in print format and as an electronic schema. This revised edition expands the legacy main codes and incorporates a series of cascading sub-codes to improve granularity in reporting. 3174556 No. DAILY DRILLING REPORT LEASE WELL NO. REPORT NO. API WELL NUMBER WATER DEPTH OPERATOR CONTRACTOR SIGNATURE OF OPERATOR’S REPRESENTATIVE SIGNATURE OF CONTRACTOR’S RIG MANAGER D.P. SIZE WEIGHT GRADE TOOL JT O.D. TYPE THREAD REPORT DATE RIG NO. FIELD OR DISTRICT MUD PUMP STROKE LENGTH STRING NO. NO. OF DAYS FROM SPUD FUEL USED CUMULATIVE ROTATING HOURS FUEL ON HAND MP1 DATE TIME DRILLING ASSEMBLY / BHA (At end of tour) SPUD RIG RELEASE NO. PAUSE ITEM O.D. LENGTH BIT RESUME TD MP3 BIT RECORD TIME DISTRIBUTION – HOURS 1 2 SIZE WEIGHT IADC CODE PRESSURE GRADIENT FUNNEL VISCOSITY TYPE PV/YP SERIAL NO. GEL STRENGTH FLUID LOSS JETS TFA DEPTH OUT 3. REAMING 4. CORING 5. CIRCULATE & CONDITION MUD 6. TRIPS LENGTH WIRE LINE RECORD RKB. TO CSG. HD. SET AT TYPE SIZE REEL NO. NO. LINES DRILLING CREW PAYROLL DATA LENGTH SLIPPED LENGTH CUT OFF START DATE OF TOUR 1 _____________________________ PRESENT LENGTH WELL NAME & NO. __________________________________ WEAR OR TRIPS SINCE LAST CUT DEPTH INTERVAL FROM TIME 2. DRILLING NO. JOINTS COMPANY _________________________________________ CUMULATIVE WEAR OR TRIPS MUD RECORD BIT NO. 1. RIG UP / TEAR DOWN / MOVE STATE / COUNTRY WEIGHT & GRADE MAKE MP4 MANUFACTURER CODE – OPERATION NO. COUNTY SIZE LAST CASING TUBING OR LINER MP2 TO DEPTH DRILL..D REAM..R CORE..C DEV. CORE NO. DIR. FORMATION (SHOW CORE RECOVERY) HORIZ DISP. TVD DEVIATION RECORD TIME LOG pH FROM TO ELAPSED TIME RPM DEPTH & EQUIPMENT CODE NO. ACTIVITY SUB CODE & SUB CODE WT. ON PUMP BIT PRESSURE DEV. DIR. RIG MANAGER _____________________________________ RIG NO. ____________________ MP 1 LINER SIZE MP 2 S.P.M. LINER SIZE HORIZ DISP. TVD S.P.M. DEPTH MP 3 LINER SIZE MP 4 S.P.M. DEV. LINER SIZE DIR. S.P.M. TVD TOTAL PUMP OUTPUT TOUR 1 CREW FROM ______________________ TO _______________ EMPL. ID NO. NAME INJURED ON THIS TOUR? YES OR NO? INITIALS HRS. HORIZ DISP. DETAILS OF OPERATIONS IN SEQUENCE AND REMARKS SOLIDS DEPTH IN T O U R TOTAL DRILLED STANDS __ D.P. TYPE TOTAL HOURS SINGLES __ D.P. 1 INNER CUTTING STRUCTURE OUTER DULL CHAR. MUD & CHEMICALS ADDED AMOUNT TYPE AMOUNT BEARINGS/ SEALS TOTAL 8. REPAIR RIG GAUGE OTHER DULL CHAR. T O U R 1 LOCATION KELLY DOWN 7. SERVICE/MAINTAIN RIG REASON PULLED WT. OF STRING 9. REPLACING DRILL LINE 10. DEVIATION SURVEY REMARKS 11. WIRELINE LOGS 12. RUN CASING & CEMENT 13. WAIT ON CEMENT 14. RIG UP / DOWN BOP 15. TEST BOP 16. DRILL STEM TEST NO. OF DAYS SINCE LAST LOST TIME ACCIDENT ____________________ DRILLER 17. PLUG BACK DRILLING ASSEMBLY / BHA (At end of tour) 18. SQUEEZE CEMENT 19. FISHING NO. 20. SPECIALIZED DIRECTIONAL WORK ITEM O.D. LENGTH BIT BIT RECORD FROM TIME SIZE WEIGHT PRESSURE GRADIENT FUNNEL VISCOSITY 21. OTHER IADC CODE 22. OTHER MANUFACTURER 23. OTHER TYPE PV/YP 31. RUN/RETRIEVE RISER EQUIP. SERIAL NO. 32. SURFACE TESTING JETS GEL STRENGTH FLUID LOSS TFA 33. OPERATING STATUS 35. WELL CONTROL 36. COILED TUBING 37. COMPLETION ACTIVITIES 38. SUBSEA INSTALLATIONS TYPE TOTAL HOURS SINGLES __ D.P. INNER DRILL..D REAM..R CORE..C DEV. CORE NO. DIR. FORMATION (SHOW CORE RECOVERY) TO ELAPSED TIME HORIZ DISP. TVD CODE NO. RPM DEPTH ACTIVITY & EQUIPMENT SUB CODE & SUB CODE WT. ON PUMP BIT PRESSURE DEV. DIR. MP 1 LINER SIZE TVD MP 2 S.P.M. LINER SIZE HORIZ DISP. S.P.M. DEPTH MP 3 LINER SIZE MP 4 S.P.M. DEV. DIR. LINER SIZE S.P.M. TVD TOTAL PUMP OUTPUT TOUR 2 CREW OBM (YES/NO) _______ FROM ______________________ TO _______________ EMPL. ID NO. NAME HRS. INJURED ON THIS TOUR? YES OR NO? INITIALS HORIZ DISP. DETAILS OF OPERATIONS IN SEQUENCE AND REMARKS SOLIDS TOTAL DRILLED STANDS __ D.P. 2 CUTTING STRUCTURE OUTER DULL CHAR. LOCATION MUD & CHEMICALS ADDED AMOUNT TYPE AMOUNT T O U R 2 KELLY DOWN BEARINGS/ SEALS TOTAL TOTALS DEPTH TIME LOG FROM DEPTH IN T O U R TO DEVIATION RECORD pH DEPTH OUT 34. SAFETY DEPTH INTERVAL MUD RECORD BIT NO. GAUGE OTHER DULL CHAR. REASON PULLED WT. OF STRING DAYWORK TIME SUMMARY (OFFICE USE ONLY) HOURS W/CONTR. D.P. REMARKS HOURS W/OPR. D.P. HOURS WITHOUT D.P. HOURS STANDBY BOILER HRS TOTAL DAYWORK NO. OF DAYS SINCE LAST LOST TIME ACCIDENT ____________________ DRILLER DAILY MUD COST © 2020 International Association of Drilling Contractors TOTAL MUD COST APPROVED © 2020 International Association of Drilling Contractors APPROVED No. 3174556 OBM (YES/NO) _______ © 2020 International Association of Drilling Contractors APPROVED No. 3174556 PRINTED IN U.S.A. Phone: +1-713-292-1945 bookstore@iadc.org Buy this form and more at store.iadc.org IADC TECHNICAL RESOURCES PRACTICAL TOOLS TO ENHANCE EXPERTISE Copyright © 2023 International Association of Drilling Contractors I N NOVATI N G WH I LE DR I LLI N G Combination of extended-reach drilling, maximum reservoir contact wells and artificial islands helps ADNOC access offshore reserves with land rig Wellbore tortuosity and instability, hole cleaning and collision risk among many challenges ADNOC overcame to drill 32,101-ft MD well BY STEPHEN WHITFIELD, ASSOCIATE EDITOR To increase production from shallow- water reservoirs in the Arabian Sea, the Abu Dhabi National Oil Company (ADNOC) has been utilizing a combination of artifi- cial islands and land rigs to drill extended- reach drilling/maximum reservoir contact (ERD/MRC) wells. Built out of sand dredged from the sea- bed, these islands can provide a cost-effec- tive alternative to deploying offshore rigs. Then, by drilling multiple ERD sidetrack wells from a single pilot well from that island, ADNOC can explore the far reaches of the reservoir in the ocean without need- ing to install new subsea infrastructure, said Muhammad Ased Hashmi, Senior Drilling Engineer at ADNOC Onshore. The MRC aspect of the wells, which typically means the well has an aggregate reservoir contact in excess of 5 km, is intended to help the operator achieve higher levels of productivity with each well. CONDUCTOR INTERMEDIATE CASING 0 00 20 0 0 40 SURFACE CASING 0 00 6 PROTECTIVE LINER 00 8 0 0 0 0 10 16 0 00 1 2 0 00 10 80 0 0 2 0 0 0 00 0 0 60 0 0 40 0 00 0 0 8 0 N 00 0 6 0 00 0 4 0 0 0 0 00 12 00 00 00 14 0 0 0 14 20 18 1 4 0 0 1 0 2 0 0 1 0 0 0 The 32,101-ft MD well had a TD of just 9,127 ft, making it 2 an 000 exceptionally long and torturous well with a 3.52:1 extended-reach ratio. The well was drilled this way in 0 order to maximize its aggregate reservoir contact and increase productivity. 20 While this approach to accessing off- shore reserves has clear benefits, there are also myriad challenges. For one, drill- ing ERD wells can be extremely diffi- cult, as it requires wellbore stability to be maintained and higher levels of torque to be managed over longer distances. Additionally, because ADNOC uses a clus- ter drilling approach in order to maximize the well capacity of each island, devising optimal well locations and trajectories can be complex due to space limitations. “With an artificial island, we have a difficult well scheme from a trajectory point of view,” Mr Hashmi said. “In one cluster, we can have several wells being drilled in one area, all going in different directions and into differ- ent formations. It’s a planning challenge.” In this cluster drilling approach, ADNOC first drills a pilot well, which can serve as a reference well for acquiring open-hole data. That data can then be processed to assess and define nearby opportunities, as well as determine the number and location of additional wells to be drilled from the same pad. Speaking at the 2023 IADC Drilling Caspian Conference in Baku, Azerbaijan, on 8 February, Mr Hashmi discussed his experience while drilling one such well offshore Abu Dhabi. As the target reservoir was shallow, the total vertical depth of the well was only 9,127 ft even though its MD reached 32,101 ft. This resulted in a fairly high extended-reach ratio of 3.52:1, which is well above the 2:1 ratio that typi- cally defines an extended-reach well. This meant that the well would be exceptional- ly long and torturous, which has implica- tions on the well completion phase. Other difficulties anticipated included high torque, difficulty in hole cleaning, collision risk and subsurface deviation errors. The well was drilled in six sections: ■ a 157-ft, 36-in. hole section using surface casing with an OD (outer diameter) of 30 in.; a 2,054, 22-in. section with 18 5/8-in. casing; a 7,458-ft, 16-in. section with 13 3/8-in. casing; a 5,326-ft, 12 1/4-in. section with 9 5/8-in. casing; a 3,772-ft, 8 ½-in. section with 7-in. cas- ing; and the 6-in. lower completion section, which was 13,334 ft in length and was M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G drilled with a pre-perforated liner and swellable packers. Because the well was among the later wells to be drilled in a cluster of 14 wells, not to mention in the presence of other well clusters, congestion in the area was a big challenge. Actions taken to mitigate the related risks included utilizing a real- time gyroscope check-shot survey tool to check for magnetic interference from adja- cent wells in close proximity to the cased- hole sections. “We’ve been drilling these types of wells for a long time, but after a while, you don’t have too much space. We need to take the logging data and check the boundaries of the reservoir to see what we can maximize at the boundaries of the reservoir,” Mr Hashmi said. While drilling the surface hole, ADNOC closely monitored losses vs gains to ensure the hole was full at all times. If the level of fluid dropped due to uncontrolled losses, the drill string would be pulled back to the conductor casing to avoid loose sand being dropped on the BHA and leading it to become stuck. Because of the presence of multiple depleted aquifers in the well path, which could lead to a total loss of fluid, ensur- ing good hole cleaning would be critical. Mitigating steps included removing any surplus cuttings so they wouldn’t increase the equivalent circulating density (ECD) on the annulus. Mud weight was also decreased to further reduce the hydro- static head on a weak formation. Interbedded shale formations were also present, leading to instability issues. ADNOC alleviated the challenge by decreasing the angle of the drill bit when it drilled through the interbedded forma- tion and then closely monitoring the mud properties. Further, the shale’s reactiveness with the water-based mud meant the well had higher-than-normal torque throughout the drilling process; this increased the risk of a stuck BHA. Mr Hashmi said ADNOC had to closely monitor torque and drag in real time, as well as conduct several short wiper trips to prevent the need for exces- sive back reaming during final POOH (pull out of hole) operations. Running casing was difficult, as well. When casing became stuck in the aquifer zone, the operator had to pump 100-200 bbl of freshwater pill, which reduced the hydro- Last October, ADNOC announced a word record 50,000-ft well, which was also drilled from one of its artificial islands using a land rig. static head, cleaned the area across the casing and freed the pipes to run to bottom. The use of solid centralizers also helped with cleaning and lowering the casing. Finally, because the well was closely geosteered across thin layers of reservoir to ensure maximum contact, well tortuos- ity posed significant obstacles in running the lower completion to TD, Mr Hashmi said. ADNOC’s solution was to run 4 ½-in. tubing to 22,980 ft in the lower comple- tion section, then utilize swellable packers with pre-perforated liners for the remain- der of the section. The packers, which were installed every 500 feet to total depth, helped mitigate potential wellbore instability in the section. The packers swelled on contact with the drilling fluid and sealed the annulus around the drill pipe. The small size of the packers made it suitable for traversing the slim hole in the lower completion section, enabling ADNOC to run the section to total depth. Overall, the successful completion of the well highlighted the key steps that ADNOC took to manage the increased operational challenges associated with drilling ERD wells in a cluster setup. Mr Hashmi said the lessons learned from this and other ERD wells will help the company to con- tinue exploring the boundaries of its res- ervoirs. “We have to reach for the edge. We want to see the boundary of the reservoir. When we’re planning the drilling, we have to make sure we have options to diverge from the main area and explore.” In October last year, ADNOC announced it had set a world record for the longest oil and gas well at 50,000 ft. The well had also been drilled from an artificial island using the ERD concept, at its Upper Zakum Concession. In announcing the achievement, ADNOC noted that the record ERD well allowed the operator to tap into an unde- veloped part of the reservoir, which had the potential to increase the field’s pro- duction by 15,000 bbl/day – without the need to expand or build any new infra- structure. The artificial island concept has already resulted in significant cost savings and environmental benefits, ADNOC said, com- pared with traditional approaches that typically require more offshore installa- tions and infrastructure. Upper Zakum is the largest producing field in ADNOC’s portfolio. The company plans to increase the field capacity to 1 million bbl/day by 2024 through a mega expansion project valued at AED 110 bil- lion. The project includes the construc- tion of four artificial islands in shallow water: Umm Al Anbar, Aseeifiya, Ettouk and Al Ghallan. Together, these islands can accommodate 450 wells and 90 plat- forms, in addition to drilling rigs, process- ing facilities and other infrastructure. ADNOC has said the concept was moti- vated by goals to reduce its environmen- tal footprint while delivering additional energy resources. DC D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 21 I N NOVATI N G WH I LE DR I LLI N G Drill pipes, BHAs evolve as wellbore geometries push existing boundaries Industry steps up downhole performance by giving connections greater fatigue resistance and enhancing BHA steering capabilities BY STEPHEN FORRESTER, CONTRIBUTOR E xtended well lengths, deeper well depths and more com- plex wellbore geometry are leading to the need for higher- performance drill pipe and BHAs. Technology providers are focusing on improving durability and decreasing cost of ownership, through things like better fatigue resistance, the use of steel with a higher alloying content, and integration with drill- ing software. Connection technology for drill pipe, BHAs In the drill pipe market, innovation cycles do not occur with nearly the same frequency as that of downhole technologies or rig equipment, explained Guillaume Plessis, Senior Director of Highlights Innovations around connections focus on greater fatigue resistance, increased makeup torque and faster makeup speed. Proprietary connections gain market share amid increasing use of advanced BHAs, such as automated RSS for precise directional control. More accessories are being added to BHAs to remove friction, dampen vibration and reduce stick-slip, while better integration of simulation with rig systems are allowing for automated, optimized steering decisions. 22 Technical Support Services for NOV’s Grant Prideco business unit. So the company’s emphasis remains on its Delta drill pipe connection, which Mr Plessis said was designed to provide per- formance and lower total cost of ownership and has continually delivered on these two fronts over the past six years. Delta 544, for example, offers the option of using a larger 5 ½-in. pipe with a small tool joint outer diameter — comparable to that of 5-in. drill pipe — which allows drillers to drill an 8 ½-in. hole with a larger, stiffer pipe. This can lead to increased ROP. The company has also worked on giving the connection greater fatigue resistance, which eliminates the need for cold-rolling of drill pipe connections, as well as the capability to use an extended makeup torque — an increase of 17%. Compared with NOV’s pre- vious XT connection, Delta also has a 50% faster makeup speed, yielding up to 4 seconds saved per connection makeup and breakout. NOV is also working on the development of two other connec- tions. The first is a connection for bottomhole assemblies (BHAs), currently branded as AILM. “The objective is a bit different for this technology, as we want to optimize fatigue resistance,” Mr Plessis said. “The challenge with a BHA connection is that the tools are very stiff, and most bending occurs at the level of the connection, requiring innovative solutions to cope with fatigue.” The second technology is a smaller connection being run on a limited basis in niche applications. “The Nano connection is being run on a different type of strings used for clean-out or work- over operations, or in through-tubing drilling,” Mr Plessis noted. “These are very specialized operations, and we’re typically com- peting with premium tubing connections in this category. While ruggedness could be a benefit of implementing Nano, the cost is typically higher, and our customers do a very close evaluation M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G ABOVE: NOV’s Nano connection is being targeted primarily for specialized operations, such as on different types of drill strings used for clean-out or workover operations. RIGHT: NOV says its innovations around the Delta connection over the past six years have focused on higher performance and lower total cost of ownership. of the advantages of the technology versus the cost of running it.” To address this, NOV is looking at alternative ways to use the Nano connection to, once again, make it more cost-effective and relevant to that type of operation. Another area of interest for NOV is drill pipe risers. The com- pany recently finalized the qualification of a 20,000-psi connector on a sour service-grade. “This project has been technically very challenging,” Mr Plessis explained. “However, we’re done with the development of this second completion and workover riser to API 17G standard, and the product is currently threaded on a partner company’s product for use in a high-pressure project in the Gulf of Mexico.” This new connection diversifies NOV’s portfolio of metal-to- metal gas-tight connections, making it the broadest with seven designs. In the Middle East, sour service-grades for drill pipe and heavy- weight drill pipe are more prevalent, and NOV has commercial- ized a 135,000-psi, NACE Region 1 product that can be used in mild sour H 2 S environments. The product has been pre-qualified, and NOV said it plans to deliver the first string in 2023. High-torque, high-performance connection Innovation in the drill pipe market has been accelerating over the past five to 10 years, according to Mark Garrett, Senior Sales D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 23 I N NOVATI N G WH I LE DR I LLI N G NOV is working on enhancements of its Delta pipe connection, as well as the development of two newer connections. Addi- tionally, the company recently finalized the qualification of a 20,000-psi connector on a sour service-grade. Engineer at TSC Drill Pipe, a division of Texas Steel Conversion. “I’ve seen a significant increase in slim-hole drilling, which is when you have a smaller annulus between the drilling tool and the wellbore,” he explained. “We’re also seeing much deeper wells, with wellbores averaging a minimum total depth (TD) of 20,000 ft, and some going to 30,000 ft. This is quite a change from where we were just a decade ago.” Drilling contractors, in particular, have called for higher perfor- mance in the threaded connections that hold the string together so they can reach those deeper TDs. While there is still some limited use of single-shoulder API connections, Mr Garrett noted that most drilling programs now use double-shoulder design con- nections, with a growing percentage of those being proprietary thread technology from various providers. “With double-shoulder connections, we can achieve the higher makeup torque necessary in these more challenging wells,” he said. “Additionally, the proprietary double-shoulder connections typically have a larger bore through the threaded connection, which improves hydraulic performance in the drilling program.” On the heels of drilling projects that are incorporating increas- ingly advanced BHA technology, like automated rotary steerable systems (RSS) for precise directional control, Mr Garret remarked that proprietary connections have gained significant market share, becoming the new standard to enable newer systems to perform. “If you’re using an API rotary-shouldered connection for your drillstring threaded connection, it typically has a 2-in. taper-per-foot thread form, which results in a smaller diameter in the threaded connection when compared with the manufacturer’s proprietary connections,” he explained. “Most of these proprietary connections have a much slower, more gradual taper on the connection, which is how you achieve the larger inner diameter necessary to improve hydraulic performance.” TSC Drill Pipe’s PTECH+ is the company’s most recent entrant into the high-performing connection market. The connection was designed to encapsulate the essential characteristics required for extended-lateral oil and gas drilling: maximized hydraulic 24 performance, increased makeup torque and improved fatigue resistance. “How do you achieve fatigue resistance on these high-per- forming connections?” Mr Garrett asked. “When designing PTECH+, testing and analysis proved that a large radius at the root of the thread form reduced peak stresses in the connection. This reduction in connection peak stress mitigates the potential for connection fatigue and failure when exposed to downhole bending.” Mr Garret also noted that the materials used to manufacture the connection impact performance. “There’s been a step-change in the materials we use, such as steel with a higher alloying content to provide improved toughness with a higher hardness,” Mr Garrett explained. “Typically, in steel technology, the higher the hardness, the more brittle the steel may become. Using better alloying, coupled with precisely controlled heat treatment, we can effectively eliminate this problem. This practice increases the performance capabilities and assures the durability of the PTECH+ connection.” Although the connection maintains a streamlined geometric design, torque capacities for the connection average 85% to 280% greater than API drill pipe connections of the same dimensions, according to the company. TSC Drill Pipe recognized that a draw- back to most higher-torque connections is that they typically require more turns to make up to be shouldered, compared with API drill pipe connections. Accordingly, a critical design criterion was to reduce the number of necessary turns to make up without sacrificing performance. Depending on the connection size, the turns to make up range from 7.5 to 9.6. Another trend with present-day drilling programs and deeper wellbores is the use of drillstring oscillating programs, which involve alternating clockwise and counterclockwise rotation of the drillstring while drilling. “One problem we are seeing result- ing from these oscillating programs is that the connections may have a tendency to break out,” Mr Garrett said. “The PTECH+ con- nection is designed to provide for higher makeup torques on the M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G TOP: A rig in the Marcellus/Utica that is running TSC’s PTECH+. The connection was designed with the principle that having a large radius at the root of the thread form reduces peak stresses in the connection. Being able to reduce this peak stress mitigates the potential for connection fatigue and fail- ure when exposed to downhole bending, according to TSC. BOTTOM: TSC says it focused on factors like hydraulic perfor- mance, makeup torque and fatigue resistance when devel- oping its PTECH+ connection to ensure it would be ideal for drilling extended laterals. threaded connections, and we have realized successes in over- coming that challenge.” As higher torque thresholds are required for drilling programs to achieve deeper wells and longer laterals, a growing number of land rigs are being retrofitted with upgraded components, raising the threshold capability of drillstring con- nection makeup torque. The proprietary PTECH+ connection technology has the poten- tial to be utilized in a variety of applications in addition to drill pipe, including subsea tubulars, workover risers and other down- hole components. While it is currently used primarily in land drilling, it can also be used for offshore and other specialized drill- ing programs by incorporating a gas-tight seal feature. BHA and drilling engineering software In the BHA segment of the market, Stéphane Menand, Technical Fellow at Helmerich and Payne (H&P), said that, while there have been few true breakthroughs in BHA components over the past few years, there has been a lot of ongoing work refining exist- ing technologies to increase durability and enable more rotating hours downhole. “We’ve pushed the limit with RSS and high-powered mud motors. We’ve also seen the development of several accessories that go in the BHA to remove friction, dampen vibration and reduce stick-slip. Lastly, we’ve seen more providers with high- frequency torsional oscillation mitigation technology that can be implemented directly inside the RSS.” For technologies that have the potential to drive step-changes in the future, Mr Menand said he is “intrigued by at-bit steering technology, where there is a drill bit with active pads to allow better trajectory control and more accurate wellbore placement.” Another point of interest, he said, is putting very small sensors along the BHA and in the bit to get better data, which can help to validate H&P’s models. Mr Menand also highlighted the benefits of drill bit forensics, which use pictures from a scanning device and analyzes them with artificial intelligence-driven algorithms to provide detailed 3D imaging for dull grading. “The idea is to better measure the wear of the bit, and then reduce the time necessary to design a new bit for a new application,” he said. “This eliminates the need to manually measure the type and amount of wear on individual cutters, which would otherwise take a significant amount of time and could be inaccurate. It’s a great process for the bit providers when it comes to iterative design improvements.” D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 25 I N NOVATI N G WH I LE DR I LLI N G The bit and BHA analysis module is one of four primary modules in DrillScan’s drilling engineering software. H&P has been working to integrate more of Drillscan’s applications into its rig fleet since acquiring the company in 2019. As the industry moves toward true digitization, Mr Menand explained that a focus area of H&P has been integrating the many downhole products and technologies that the company deploys as part of a package that enables automated drilling. “What we’re trying to do at H&P is better control the BHA from the surface with a different level of automation,” he said. “Whether a new or existing BHA, we’re looking at how we can control it in terms of operating parameters, drilling performance and steering recom- mendations. With more complex wells and increasingly long laterals, we really have to look at combining technologies if we’re going to push the envelope, because otherwise there is a technical limitation, at least for now.” In 2019, H&P acquired the DrillScan drilling engineering soft- ware, which has four primary modules – well planning, well integrity, BHA and bit analysis, and drill string modeling. They leverage modeling and simulations to reduce the time to target, enhance BHA integrity and increase reservoir contact. “We want to integrate software applications from DrillScan software on H&P rigs for automation,” Mr Menand said. “The software’s physics- based algorithms integrate with the AutoSlide technology, for example, working with the equipment at surface to steer the BHA. The idea is to try to predict the amount of friction and find an opti- mum weight-on-bit RPM given a well trajectory. We want to opti- mize all of H&P’s machines to drill with the best ROP, experience less vibration and yield a smoother wellbore, and we use DrillScan software to enable the equipment to accomplish those objectives.” Once DrillScan software successfully integrates with the sur- face rig equipment and achieves these targets related to wellbore quality and drilling performance, H&P can then focus on another major goal: creating a digital twin to predict and model perfor- mance in real time. “We want to provide what I call a true digital twin, which means to have a live, real-time, virtual representa- tion of the condition of the drill string and BHA,” Mr Menand 26 “What we’re trying to do at H&P is better control the BHA from the surface with a different level of automation. Whether a new or existing BHA, we’re looking at how we can control it in terms of operating parameters, drilling performance and steering recommendations.” - Stéphane Menand, H&P explained. “Having this sort of eye downhole — that is, having a true digital twin of the entire drill string — allows us to better pilot that drill string in terms of ROP in terms of steering and in terms of vibration.” Once a stand is drilled, H&P can quickly analyze its performance to predict that of the next one. Mr Menand said he believes that having DrillScan software as part of H&P has provided customers with benefits that would have been more difficult to achieve with multiple third-party providers. “We have the rig, we have the people on the rig, and we have the technology, meaning that we can master and control everything from A to Z because we’re all in the same company,” he explained. “When you bring in third-party technology providers, there’s potential for issues with integration or miscommunica- tion, but having DrillScan software as part of H&P’s portfolio helps ensure that we understand what we need to do, and we have the data from H&P’s sensors to back up those decisions.” DC DrillScan and AutoSlide are registered trademarks of H&P. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G Case study: Laser measurements, machine learning boost motor performance in the Permian As the Laser-AI algorithm evolved, it allowed the stator to be rejected with the same criteria as a dyno-test, but results were realized before the motor was built, rather than after it was assembled and shipped to a dyno-testing facility. Results BY LONNIE SMITH, TURNCO An operator in the Permian Basin was having inconsistent runs caused by motors that were either not producing the horsepower expected or were failing prematurely for power section chunking. In both scenarios, the motors exhibited the same power section fit and were run in similar drilling circumstances, yet did not perform with the same consistency. To reduce nonproductive time (NPT), the operator sought to accurately measure and test its motors prior to installation . The power section of positive displace- ment motors consists of an internal (rotor) and external (stator) component . When paired , they create a “fit” and maintain a critical seal at the bottom of the well. The rubber lining within the stator can swell or shrink when exposed to heat and drilling fluids . If the stator cannot handle these conditions, it will disable the power sec- tion’s ability to uphold the fit required to maintain a seal. This failure can cause the rubber lining to chunk or stall, resulting in motor failure or weakness. Traditionally, the power section fit of a motor is determined by a vector gauge. Because so many manual measurements are required with this method , miscalcu- lations can occur frequently. To resolve performance inconsistencies, the opera- tor instituted dyno-testing on all motors before deployment. The additional testing proved useful, and motor run reliability improved. However, the additional test- ing was costly and time intensive. It also put additional strain on vendors’ supply chains as each motor had to be sent for testing prior to installation. According to results provided by a leading dyno-testing provider in North America approximately 6% of approxi- mately 14,400 motors failed between 2018 and 2021. A large group of manufacturers of power sections and motors were repre- sented in this data set. More cost-effective solution As an alternative to the dyno-tests, the operator sought out Turnco’s Laser-AI . In November 2021, Turnco began taking mea- surements of stators with an inspection system laser device. Each measurement took up to 3,600 laser measurements and produced a 360° profile of the stator. These images were then stitched together into one electronic file . The 360° profile mea- surement gave the operator a digital log and comprehensive view of the stator, not just the ID minor (a limitation of the vec- tor technology). After being measured, the stators were assembled onto a motor and shipped to dyno-testing. Part of Turnco’s initial efforts included testing its data set against the dyno-test, ensuring the accuracy of its algorithm . Ultimately, Laser-AI combined each motor’s data set with supervised machine learning techniques and was able to pre- dict stator performance on the dyno-test with greater than 95% accuracy. The operator was able to modify its quality program to only dyno-test a sam- ple of the motors, rather than every single one, reducing spend on dyno-testing by 80%. Additionally, the operator shortened its supply chain, enabling motors to go directly to the rig, saving two days of mobilization and transportation efforts. Most importantly, vector measurements were taken for each stator and compared with measurements the laser produced. It was discovered that, on average, the sta- tor measurements were more accurate by 0.004 in. when utilizing Turnco’s method, resulting in more consistent motor per- formance outcomes. In 11% of instances, stators were more then 0.011 in. off or were completely out of tolerance. Turnco’s methodology enabled the oper- ator’s motor vendor to perform the laser measurements internally and upload files into the Laser-AI software . Ultimately, the technology eliminated the inconsistencies in stator performance and improved NPT by rejecting motors prior to use. DC A histogram of the absolute difference between laser and vector measurements of the stator minor. On average, the laser results were more accurate by 0.004 in. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 27 I N NOVATI N G WH I LE DR I LLI N G Digital tools streamline design, testing process during drill bit selection Digital twins, in-bit sensors among innovations shortening the iteration cycle to help operators get bits into the field faster BY STEPHEN WHITFIELD, ASSOCIATE EDITOR T here is a lot that goes into a service company’s process when helping operators to select the right drill bit for a given hole section. They need to work with operators to understand the plan for drilling the section. They need to mea- sure the dynamics of the rock to be drilled, typically through rock strength data provided by the operator. They need to determine the amount of customization a given bit design and a given well might need in order to help the operator achieve its objectives. Often, they have to deploy simulation software to gather infor- mation about multiple aspects of the bit’s potential downhole Highlights In the ultra-competitive bit business, manufacturers must constantly push performance by leveraging previous lessons learned, adopting new solutions. In some cases, digital twins can reduce the need for field testing of new bit designs, but this approach requires a higher level of trust between operator and supplier. Technologies like in-bit sensors and automated dull grading are producing better data, better understanding of bit/rock interactions and, ultimately, better bit designs. 28 performance. That’s typically followed by field testing, which can sometimes yield different results from the simulations, sending everyone back to the drawing board. On top of the challenges in managing these variables, bit manufacturers are constantly looking for ways to push the limits of their products’ performance, recognizing that operators are always seeking to reach deeper target depths at faster speeds. “Because the bit business is so competitive, if you’re not in the background trying to figure out how to beat your own prior perfor- mance, you’re going to be displaced pretty quickly,” said Matthew Jennings, Product Line Director – Drill Bits at NOV. “We have to constantly beat ourselves and improve on our performance with the bits we design. If we don’t, someone else will.” Making even small incremental performance gains is critical right now as drilling activity continues to ramp up around the world. “A lot of times our customers are seeking a quick solution,” said Derek Nelms, Product Line Manager – Drill Bits at Baker Hughes. “Our goal is to find that optimal solution to push the per- formance of the bit to the level the customer needs, and to do it in the quickest way possible. Our expertise in the formations they’re drilling in, our understanding of how our bits perform and the technologies we need to deliver that best outcome – all of that is so important to the process.” In this article, DC speaks with Baker Hughes, Halliburton and NOV to discuss steps they’re taking to enhance their simulation software. Better software not only provides better understanding of how a given bit will interact with the target rock formation, but it can also shorten the time required for bit design and field testing, allowing operators to get the bits into the field faster so they can start drilling and producing. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G Digital tools have helped Baker Hughes streamline the drill bit selection process while still providing an accurate analysis of bit performance. In some cases, operators even favor using digital twins instead of field tests to make their selections. A digital twin of the bit Like with most other processes in the drilling of a well, com- panies are always striving for more efficiency in the bit selection process. Baker Hughes has an assortment of tools available to help operators find the right drill bit for their applications. For instance, at its office in The Woodlands, Texas, it has a surface rig that can drill with full-sized drill bits in test situations. It also has a pressure vessel that can take a rock core and simulate drilling conditions in a downhole environment. However, to streamline the process while still providing an accurate analysis of a drill bit’s performance, Baker Hughes says it is not only continuing to invest in better software but also find- ing ways to better leverage its decades of field data from various product lines. “Our customers are drilling into more challenging lithologies, but we know going into the bit selection process what our toolbox is and how we can design bits to solve very specific challenges,” Mr Nelms said. “We can shorten the design process because we know how our technologies behave downhole.” One of the key pieces in Baker Hughes’ bit design process is its proprietary bit drilling simulation software, which can create a digital twin of the bit and the target formation. It then evaluates cutter and bit body interactions of the bit and the rock using pro- prietary cutter force models. This software is used to evaluate the performance of various design concepts and customizable solu- tions using customer inputs to model performance-limiting chal- lenges from their drilling applications. These can be anything from formation variation to optimizing the drill-out operation of cementing float equipment. After the user inputs well parameters and rock properties, the software conducts a simulation that can determine the drilling behavior of specific designs to predict aggressiveness and loading conditions on the cutting structure. This type of digital twin capa- bility allows for greater flexibility in modeling drill bit behavior because it can also make predictions based on the performance of similar rock formations and similar bit designs using previous digital twin data. This capability provides Baker Hughes with a more compre- hensive picture of how the bit will perform. In some cases, having a digital twin has led to the need for fewer or even no field tests, shortening the iteration cycle by days or weeks . “As we’ve created these models, built out the digital twins and built out a library of simulations, we can answer customer ques- tions much faster because we can take previous models we have D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 29 I N NOVATI N G WH I LE DR I LLI N G us reduce that setup time even further. We’re putting a lot of our focus into making that process even faster.” Insights from in-bit sensors Baker Hughes’ bit drilling simulation software can create digital twins of the bit and the target formation. It then uses proprietary cutter force models to evaluate cutter and bit body interactions of the bit and the rock . Operators’ specific performance-limiting challenges can be modeled to find customizable solutions. already built and modify them to meet current needs. Because a lot of the upfront work has already been done, the whole process is streamlined,” he said. Baker Hughes said it still runs field tests, but it finds that some of its long-time clients now favor using digital twins in place of field tests. This approach requires a higher level of trust between customer and supplier, however. “We spend a lot of time calibrating our digital capabilities with past field data and lab data, and when you add that to having strong relationships with your customers, that means we can really work together to streamline the process.” In some cases, digital capabilities have been effective in help- ing operators set performance records without the need for field testing. In 2021, for example, a company in the Permian Basin had reached a ceiling with its ROP while drilling the 12 ¼-in. inter- mediate hole section. Using computer simulations, Baker Hughes pinpointed cutters as the primary ROP limiter and then lab- tested different cutters and their placement across the bit face. Ultimately, the company recommended the Prism shaped-cutter technology with its Dynamus drill bit because the simulations showed that the point-loading on the Prism cutter would be ideal for maximizing ROP in the ductile pressurized shale formations of the hole section. In the field, the Dynamus bit with Prism cutters drilled the entire intermediate section from 1,405 ft to 5,200 ft in 16.3 hours, resulting in an average ROP of 232.8 ft/hr. This was 37% above the operator’s target and even set a record for the hole section, accord- ing to Baker Hughes. Mr Nelms said the next step with its digital twin modeling is to use machine learning to automate the building of the digital twin once the drill bit design and field data have been input into the system. “A lot of digitalization efforts are centered around manually creating the models and building out the digital twins, but over time we’ve built out a library of simulations,” he explained. “This means we can have a faster process because a lot of the upfront work has already been done and we can adjust and modify previ- ous models to help build out new models. Automation can help 30 Halliburton had previously relied on data captured at the sur- face to feed into its drill bit designs, but with the introduction of its Cerebro Force in-bit sensors in 2020, the company says it can now better understand and document the motions of the drill bit from well to well. Cerebro Force captures weight, torque and bending measure- ments directly at the bit, allowing the company to map the down- hole motion of the bit and any associated drilling dysfunctions. This can prove valuable when it comes to improving future bit designs. “Cerebro is all about understanding the subsurface conditions,” said David Sostarich, Strategic Business Manager at Halliburton. “Surface data is gathered thousands of feet away from the drill bit, but in-bit sensing allows us to see what’s happening from a downhole perspective. It gives us a clearer picture of what’s going on at the bit-to-rock interface and provides us with better insights into design. We’re looking at where lateral vibration, axial vibra- tion, stick-slip and whirl are happening, and then marrying that information with bit design, selection and implementation.” In one Williston Basin project, data from the in-bit sensors helped the company to design a Cerebro drill bit . Field test data showed the bit achieved the fastest ROP, while minimizing torque, at points when the rolling element engaged with the formation. As the rollers engaged, the torque was minimized, thus increasing ROP. However, the sensor data also showed that rollers were only engaged for small percentages of each test run. Halliburton then decreased the depth of cut at which the roll- ers were engaging, a move that enabled the rollers to engage for a greater percentage of the run and increase ROP. Whereas the highest ROP prior to the change was 113.0 ft/hr, ROP post-change maxed out at 160.2 ft/hr. More recently, Halliburton added another tool to its bit-design toolbox – Oculus, which is an automated software program that serves as bit dull grading system. Launched in 2021, the soft- ware uses machine learning algorithms to capture precise dull information for individual cutters on a bit. The program analyzes images taken of the bit after it has been pulled out of hole and catalogues the data in a cloud database. It then automatically grades the wear on each cutter. By automating the dull grading process, the subjectivity of visual examinations by human inspectors is eliminated, and Halliburton gets more precise measurements and classifications of bit dulling. It also becomes easier to utilize the dull analysis over a large number of bits, including during the testing phase of the design process, Mr Sostarich added. “When we would evaluate drill bits previously, we would see a lot of subjectivity, even utilizing the IADC code. One individual might grade a bit a 1-2, another might grade it a 1-3 and another might grade it a 2-3. What we wanted to do with Oculus is take a digital image of each cutter, input it into the system and give it a more specific and objective grade, so we can take these very sub- jective things and turn them into objective data,” he said. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R I N NOVATI N G WH I LE DR I LLI N G Halliburton’s Cerebro Force in-bit sensors, launched in 2020, cap- ture weight, torque and bending measurements directly at the bit, allowing the company to map the bit’s downhole motion . Oculus is utilized at Halliburton’s service centers globally for fixed cutter dull analysis. Its newest Hedron fixed cutter platform, launched in 2022, utilizes Oculus as a key component of design for more efficient and durable PDC bits. In one project last year, the company worked with a direc- tional driller in the Middle East that was looking for a bit to help increase ROP. Halliburton, using historical data of similar forma- tions, picked its Hedron PDC bit with Geometrix shaped cutters in the shoulder area as a starting point. In subsequent simulations and testing, it was found that decreasing the diamond volume negatively affected the bit’s stability and exacerbated minor breakage seen in the shoulder during formation transitions. This finding led Halliburton to look for ways to alter the design pro- file to increase cutter efficiency and minimize the potential for instability. Based on data provided by the Oculus system, the company kept the same profile and cutter positions as the reference bit, but it introduced an optimum back rake scheme to increase efficiency and lower susceptibility to impact damage. After a test run in Halliburton’s proprietary modeling software, the cone, nose and shoulder were examined before adjusting the back rake regime. No changes were made in the cone area of the bit, as design simulations performed in its bit design software indicated that such changes might lead to over-engagement of the cone cutters, which could lead to aggravated vibration levels and increase the potential for downhole dysfunction. A final test run in the modeling software saw a 26% increase in bit efficiency compared with the reference bit. Then, a field test of the updated bit set a field record for ROP – 81.2 ft/hr, nearly 12 ft/ hr higher than the previous record of 69.6 ft/hr. “Oculus has really helped us in terms of understanding – at scale – how cutters perform in many different applications, whether that’s abrasions, impact environments or thermal-type environments,” Mr Sostarich said. “We’re able to make better selections on introducing new technologies to our customers.” Collaboration and performance NOV uses a wealth of software programs to help operators find the right drill bit. Terra-Scope, the company’s long-standing downhole seismic monitoring system, analyzes rock strength data and outputs the most likely failure mechanisms for the tar- get formation. For example, it can determine whether the bit is more likely to fail under stress – which would require 3D-shaped cutters – or more likely to fail under strain – which would require full round cutters. The company then uses its Orbits software to run simulations showing how a given bit design might perform with rock properties specified by the operator. Despite the sophistication of software like Terra-Scope and Orbits, there’s still a lot of work required from field engineers to “sort through all the different things that can happen on a rig or happen to a bit while drilling a well,” NOV’s Mr Jennings said, adding that looking at all the data available and making sound recommendations requires a lot of coordination. This is why NOV Engineer Brice-Herve Benie said he believes the drill bit selection process is actually all about collaboration with the operator. Choosing a profile to run in the Orbits simulator, D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 31 I N NOVATI N G WH I LE DR I LLI N G NOV says it has been focusing on improving cutter grades and shapes as part of efforts to help operators improve their drill- ing performance. Its new ION+ 5DX cutter, launched last year, is one example and features a working ridge designed to withstand sudden impacts while imparting high compressive loads into the formation. for example, is typically a back-and-forth process, with the opera- tor providing its performance targets and outlining the limiters it has identified while drilling the formation in previous runs. “It might take two or three iterations for us to come up with the right profile for the operator to maximize value from the application,” Mr Benie said. Especially in basins like the Permian, where operators drill a variety of hole sizes in every rock formation imaginable, drill bit designs need to be more customized. In these cases, initial field testing often proves extremely valuable. While the simulation software provides a good estimate of how the bit will perform – providing theoretical potential for vibrations and aggressivity, for example – a physical run is still often required to get a clearer picture of specific elements of drill bit performance. For instance, NOV runs add-on applications to its simulation software that analyze the potential for downhole dysfunctions like whirl and stick-slip, but the models that are programmed into those add-ons can only provide estimates. While the process of selecting a drill bit has remained relatively unchanged over the years, NOV says where it has made the most progress is in terms of using bits to improve operators’ drilling performance. This includes taking the insights gained from pre- vious bit designs to achieve efficiency gains in future projects – in particular, the company has been focused on improving cutter grades and cutter shapes to help make the bit more stable and increase its durability. 32 “The way that operators are going to save money is by reduc- ing the amount of days to drill a well,” Mr Jennings said. “ROP in single intervals has reached a critical point, so now we’re looking at how we can do more intervals with the same bit so we don’t have to trade for the same set of tools. That presents a unique challenge for the cutters because now you’re going through different types of rock failures in the same run. We’re looking at how can we build a cutter array that will go through an abrasive shale, back into an abrasive sand, then back into a shale – all in one interval without needing different bits to drill independently.” In March 2022, NOV launched its ION+ 5DX cutter, which incorporates a working ridge that is designed to withstand sudden impacts while imparting high compressive loads into the formation. The goal with the layout of these cutters is to minimize impact damage while maximizing ROP. The company said that the 5DX has shown a 60% increase in material tough- ness – or the amount of energy per unit of volume that a material can absorb prior to rupturing – over the average of commercial cutters. “The cutter group is constantly working on new cutter grades, trying to improve the cutter shape and the array,” Mr Benie said. “As we make cutters that are more impact-resistant, we can be more aggressive on the design side and help our clients exceed their targets. If an operator can drill 9,000 ft of lateral in 24 hours, we can help them drill the same distance in less time tomorrow.” DC M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R HYDRAULIC FRACTURING ADVANCES Sensor-based system allows real-time detection, monitoring of emissions in frac operations Users can be alerted to take immediate remedial action, while over time the data can help to identify emissions, equipment trends BY STEPHEN WHITFIELD, ASSOCIATE EDITOR As the oil and gas industry continues to adopt more stringent measures for reduc- ing greenhouse gas (GHG) emissions, espe- cially from significant contributors like heavy fracturing equipment, it is criti- cal companies can get accurate emis- sions measurements directly in the field to enable comprehensive monitoring and tracking. Last year, SLB launched a real-time sensor-based emissions detection and monitoring system for hydraulic fractur- ing operations, which the company says can also be adapted for other applica- tions like drilling. The sensors are placed near heavy fuel-burning equipment like engines and generators to analyze their emissions data, which is then sent to the cloud. Users can view visualizations of the data on dashboards, and they also receive alerts if GHG and other emission levels surpass a predetermined threshold. “As we look toward a net-zero future, we’ve come to the conclusion that the first step in solving the problem is to capture the greenhouse gas emissions from the wellsite as accurately as possible,” said Rishika Narang, Information Management Engineer at SLB. “We want to enable real- time monitoring, and we want to make sure that we can visualize the data in a way that users don’t get stuck looking at information they have no way to com- prehend. We want the asset managers to get notified whenever a key performance objective for emissions levels that we have in mind are breached.” Ms Narang, who spoke at the 2023 SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, on 2 February, said the system utilizes electrochemical sensors that react with gases in the air and identifies CO, CO 2 , NO 2 , hydrogen sulfide (H 2 S), nitric oxide (NO), ozone (O 3 ) and methane (CH 4 ). Continuous readings are sent through an application programming interface (API) to a standard query language server, which processes the data and moves it to a cloud server at one-minute intervals. Real-time data visualization and analyt- ics dashboards, available at the wellsite and in offices, can then help users to monitor emissions levels. If an emission level crosses a user-set threshold for a given parameter, an alarm pops up on the dashboard to notify the user to examine the source of the emissions and potentially take remedial action. This might include stopping specific pieces of equipment that are generating an abnormal amount of emissions. This type of monitoring can also be use- ful for equipment monitoring and mainte- nance. If users notice an increase in emis- sions generated from a piece of machinery, they can check it for potential issues like corrosion. Further, SLB’s cloud-based algo- rithms can spot trends related to issues like fuel adulteration, as well as identify low-performing assets emitting high lev- els of emissions. Data aggregation and analytics is anoth- er key benefit. The system allows all emis- sions data from a frac operation to be collected in one place, so companies don’t have to deploy different kinds of meters and capturing devices that might produce disparate data that are difficult to aggre- gate and analyze. Ms Narang said this functionality makes it easier for asset managers to keep track of data over time. It will also be beneficial for frac crews who might not have been pres- ent at an earlier stage in the frac operation, as they will have the ability to easily view emissions data from any point in time. “Having this application gives us the freedom to be in touch with the entire data set, so you know exactly where the emissions are coming from and where all potential breaches could be happening,” Ms Narang said. Taking an even longer-term perspec- tive, the emissions data accumulated over time can help companies understand how they can reduce their overall carbon foot- print across multiple operations, as well as provide critical data points for corporate sustainability reports. Pilot project Last year, SLB conducted a pilot study of the sensor system on a hydraulic fractur- ing site for an unnamed operator. Sensors were mounted near exhaust pipes of the frac engines, where the maximum level of emissions could cross the sensors. Sensors were also placed within an enclosed cabin on the frac site in order to measure the cabin’s exhaust efficiency. For this particular project, the sensors were calibrated to measure two types of particulate matter – fine particulate mat- ter (PM2.5, which is less than 2.5 micro- meters in diameter) and coarse (PM10). They also measured CO 2 , NO 2 and H 2 S, along with temperature, humidity and air quality index. Live data of all the gases were success- fully captured and transmitted without requiring manual calculation, according to SLB. The pilot also aimed to test the machine learning algorithms within the cloud- based system. Because the sensor system requires continuous electricity to oper- ate, the algorithms can be useful in the event of electrical failures, by interpolating emissions readings that might have been missed. During the pilot, two sensors mea- “Emissions monitoring system” continued on page 35 D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 33 HYDRAULIC FRACTURING ADVANCES Centralized start-stop system helps reduce fuel consumption, emissions from idling engines in hydraulic fracturing operations Field testing in Permian last year showed promising results, with significant decreases in engine idling hours and emissions levels BY STEPHEN WHITFIELD, ASSOCIATE EDITOR As the industry continues to deploy inno- vations like battery energy storage sys- tems, dual-fuel and natural gas engines to lower fuel consumption and mitigate emissions during hydraulic fracturing operations, another source of NO x , CO 2 and particulate matter emissions is getting more attention on the sustainability radar: idling frac engines. “These engines that we’re using on frac sites were never designed to idle. They were designed to run very efficiently at 50%, 60%, 70% power. The more load they have on them, the better their lubrication systems and radiation packages work. But that means they’re consuming a lot of fuel,” said Robert Fulks, VP of ESG Technology at MGB Oilfield Solutions. “Frac engine emis- sions have come way down because of the technologies applied by manufacturers, but they’re not as efficient in their fuel con- sumption as you’d like them to be.” Speaking at the 2023 SPE Hydraulic Fracturing Technology Conference on 2 February in The Woodlands, Texas, Mr Fulks outlined the development and field testing of a new start-stop system designed to mitigate fuel waste from idling engines. Industrial diesel engines rely on per- manently mounted batteries to drive elec- tric starters. When a start-stop system is added, it automatically shuts down the engine when it’s not being used and restarts it when it’s needed. This reduces idling time and, therefore, fuel consump- tion. The technology has been used in the automotive industry for decades and was adopted into the frac industry within the past five to six years. Last year, MGB launched its version of the start-stop system with the addition of a centralized power unit. This made a significant difference as it meant that each start-stop system would not have to be manually activated on each individual engine. By installing the start-stop system inside the centralized starter unit, an entire fleet of frac pumps can be started from a single power source, or be shut off when the pumps are not needed. This reduces the time needed to stop/restart a frac fleet to less than 10 minutes, com- pared with around 45 minutes for a start- stop system without a centralized starter function, according to MGB. “The big holdup with adopting start- stop systems has been the amount of time needed to restart an entire fleet,” Mr Fulks said. “But now you can press a but- ton and start-stop an entire frac fleet. You don’t need to do the old way of having two people go out to charge the hydraulic pump on each tractor. This is a big deal if you want to talk about efficiency.” Additionally, the start-stop function can be performed either remotely or autonomously, if used with third-party automation software. Different configurations for system setup MGB’s centralized hydraulic start-stop system can be configured in two settings – a daisy chain setting where the main hydraulic supply line runs from the start-stop unit to the first pump, and then subsequently to each pump on the pad; and a manifold setting where hydraulic power flows from the start-stop unit to a series of manifolds to the hydraulic pumps. Either configuration allows an entire fleet of frac pumps to be started from a single power source. 34 MGB’s start-stop system can be laid out in two configurations. One is the “daisy chain,” where the main hydraulic supply line runs from the hydraulic start-stop unit to the first pump on a row of frac pumps. Another hydraulic hose connects to this first pump and runs to the adjacent pump. This process repeats for all the pumps on that row, and the same process repeats for the other row. The other potential configu- ration is a manifolded distribution layout, where hydraulic power from the start-stop unit runs to a manifold system with a set M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R HYDRAULIC FRACTURING ADVANCES number of outlets, which then provide power to the connected frac pumps. The layout of the individual frac pumps determines the flow of the hydraulic fluid to the frac pump starter. Either of the two standard configurations of the frac pumps can be deployed with the MGB system, either with the daisy chain or the mani- fold setup. The closed center configura- tion means that, as hydraulic pressure is applied to the starter circuit, the actual frac pump starter motor will not engage until a start signal is transmitted. When a sig- nal is received, the solenoid valve on the starter sends hydraulic fluid to the starter to start the engine. For the other starter configuration, the open center, when the hydraulic fluid flows to the starter circuit, the fluid bypasses the solenoid valve and returns to a tank. When enough fluid has passed to start the engine, the solenoid valve activates and sends the fluid to the starter motor. An open-center setup requires additional ball valves to control the flow of the hydraulic fluid to each frac pump and eliminate flow when it is not needed. In a closed-center setup, no additional control valves are required – the solenoid valves control the flow to each frac pump. The MGB start-stop system, and the cen- tralized power unit, also reduce the need for auxiliary equipment – like tractors, air compressors, generators and diesel-pow- ered light towers – that is typically needed to power individual frac pumps. Mr Fulks said this reduction in equipment provides an added benefit to frac operators by reduc- ing the number of potential points of failure on a frac pad, lowering maintenance costs. “The single central unit is basically pro- viding all the power we need on location. “Emissions monitoring system” continued from page 33 suring CO 2 were run in the same location. One was kept running, while the other was intentionally stopped for a fixed dura- tion. The interpolated data points from the stopped sensor matched the CO 2 readings from the other sensor, indicating the accu- racy of the algorithms. While most GHG levels recorded during MONTHLY EMISSIONS DURING FRAC IDLE TIME UNITS BEFORE CENTRAL START/STOP AFTER CENTRAL START/STOP N0 X per pad grams 2,834,244 526,360 C0 2 per pad Kgrams 695,520 129,168 Particulate Matter per pad grams 26,372 4,898 Field testing of the centralized stop/start system, which took place over a three- week period last year in the Permian Basin, showed significant drops in selected greenhouse gas emissions and particulate matter. The centralized system had helped to remove an average of 135.78 idle hours per pump, resulting in a savings of 1,962.07 gallons of fuel per pump. So, we don’t need all the generators, light towers and compressors we have out there. You won’t see any tractors on location. You can daisy-chain everything to the unit.” Field testing in the Permian shows positive results Last year, ConocoPhillips tested the start- stop system on a frac pad in the Permian Basin, using a real-time data analytic soft- ware developed by Corva to measure frac pump diesel usage, engine idle times and emissions generated from the frac pad. Use of the centralized start-stop system took place during a three-week period in mid-summer 2022. ConocoPhillips then measured these totals against the average idle time and fuel usage for the same pad from a separate three-week period without the centralized system. The operator found that, with the cen- tralized system, an average of 135.78 idle hours were removed per pump over the three-week period. This led to a savings of 1,962.07 gallons of fuel per pump, or a total savings of 35,317.32 gals for the entire pad, the pilot were below the threshold set by the operator – 1 ppb of H 2 S, 12 ppb of NO 2 and 600 ppm of CO 2 – the sensor system did detect a higher-than-expected level of CO 2 levels in the closed cabin. This confirmed the need for better ventilation, Ms Narang said. Outside of the cabin, the frac site did not see higher-than-expected levels of GHG emissions. Another more unexpected find during the project was that there was a drop in which used 18 active pumps. Assuming an average diesel price of $3.80/gal, this meant a fuel cost savings of $134,205.83. When factoring in the reduction of generator usage and light tower usage, as well as the reduction in maintenance costs enabled by the reduction in auxil- iary equipment, the operator determined it achieved a total cost savings of more than a half-million dollars. From an emissions standpoint, the MGB system also recorded savings in NO x emis- sions, CO 2 emissions and particulate mat- ter (see graph above). “You’re not going to eliminate all the idle time because you’ve got to get the engines up to speed and then bring them back down – that takes time. But you can eliminate a lot of the idle time, and you can eliminate a lot of fuel consumption. The field tests showed a dramatic difference,” Mr Fulks said. DC More information in SPE 212357, “Reductions in Emissions and Fuel Cost with Start-Stop System Technology for Diesel Frac Fleets.” NO 2 emission levels during the daytime hours. The team traced this to the fact that, in the presence of sunlight, NO 2 is converted to NO, and O 3 is released as a byproduct; addressing this in the future would likely require those two gases to be measured, as well. DC For more information, refer to SPE 212323, “Towards a Net-Zero Future: Decarbonizing Hydraulic Fracturing Operations.” D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 35 HYDRAULIC FRACTURING ADVANCES Metal-seal dissolvable frac plugs use simplified design to improve reliability during plug and perf BY JINLU WANG, VERTECHS GROUP Compared with composite frac plugs, dis- solvable frac plugs currently only have less than 20% of the market share of the plug- and-perf completion method. Frequently cited disadvantages include casing ero- sion and issues with dissolving too fast or too slow, leading to increased costs and longer completion times. However, newer and more simplified dissolvable frac plugs could help to address these challenges and have the potential to achieve efficiency and cost savings in major unconventional plays around the world. One source of limitation with frac plugs is the elastomer. The oil and gas industry has used elastomers as a material for frac plugs – both in traditional composite frac plugs and dissolvable frac plugs – in zonal isolation for years. However, recent research and observations made through the use of downhole cameras indicate that elastomers can sometimes fail or extrude, leading to leakage and casing erosion. The chemical nature of elastomers tends to cause them to extrude under high pressure and temperature conditions. Still, elastomers can provide reliable isolation when properly designed with anti-extrusion mechanisms. These can be made of overlapping plates or rings that are compressed and flattened into a disc-like shape, blocking the elastomer from slipping through the gap of slip segments. In com- plex downhole conditions, however, these anti-extrusion mechanisms can sometimes fail or not deploy fully, leaving weak points that allow for extrusion to occur. To address the issues associated with elastomers, metal-seal dissolvable frac plugs have been developed. These plugs use a metal-to-metal seal to provide reli- able isolation under high pressure and temperature conditions, eliminating the need for anti-extrusion mechanisms. As a result, the design of the plug is sim- plified, requiring fewer components and materials. This can also make clean-out runs faster and more efficient. In addition, metal seals can eliminate running risks in high annular velocities. In challenging situations, hybrid seals can also be used; it combines both an elas- tomer ring and a metal-seal mechanism. The elastomer serves as the initial pres- sure barrier during stimulation, while the metal seal undergoes plastic deformation and fully engages with the casing wall as the pressure increases. This not only provides reliable isolation of the casing, but the metal seal also serves as a robust anti-extrusion component Compared with these newer and more simplified plugs, traditional dissolvable frac plugs are typically made of complex components that can be prone to failure risks. These components may be sensitive to temperature, pressure and other factors, which can make it difficult to predict and control the rate at which the plug dissolves. Another potential limitation of tradi- tional dissolvable frac plugs is that they are often heavily customized to dissolve at specific rates, which can be difficult to predict and control. This can make it chal- lenging to use these plugs in a wide range of wellbores and production scenarios, as the specific conditions and requirements of each well can vary significantly. Using dissolvable technology can be both beneficial, but it does comes with its challenges. To customize plugs that are suitable for different conditions, a thor- ough understanding of both application challenges and engineering are neces- sary. The tool supplier must consider all operational details, including the condi- tions and requirements, to design, simu- late, validate and optimize the plug in order to achieve optimal performance and results for end users. This requires a care- ful balance between tool performance and dissolvability. Striking a balance between the trade-offs in different applications and scenarios is crucial for success. DC LEFT: Vertechs’ traditional dissolvable frac plug design (left) versus its new design (right).The metal-seal dissolvable frac plugs use a metal-to-metal seal, eliminating the need for anti-extrusion mechanisms. RIGHT: A metal-seal dissolvable frac plug is rigged up before being run in hole. The plug’s simplified design meant fewer components and materials were needed. 36 M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R GLOBAL WORKFORCE DEVELOPMENT ExxonMobil’s Guyana project provides blueprint for building local workforce, infrastructure in emerging E&P markets Center for Local Business Development shows Guyanese suppliers how to maximize growth opportunities, improve safety management BY STEPHEN WHITFIELD, ASSOCIATE EDITOR In developing countries like Guyana, an oil company won’t be successful in their E&P projects if they see the oil and gas in the ground as the only resource being developed. They also must consider the potential local workforce and its techni- cal and business capacities as valuable resources, and then identify ways to devel- op them. For ExxonMobil, as it embarked on its exploration and development of the Stabroek Block in Guyana, it recognized that those efforts must also encompass programs to build a competitive and thriv- ing local business community. In 2017, as it began Phase 1 of the Liza project, the company launched the Center for Local Business Development in Guyana’s capital city of Georgetown. The aim was to provide training to Guyanese businesses and employees, developing their skills, knowledge and abilities so they could work more effectively in the oil and gas industry. The effort has been so successful in the past four to five years that Susan Scott, Socioeconomic Manager at ExxonMobil, said it can provide a model for other com- panies looking to jump-start local content development in other emerging markets. “The center really is a one-stop shop for local capacity building, mentoring, cre- ating networking opportunities and pro- viding a platform for information shar- ing,” she said. “The insights that we’ve gained from this experience can really be a benefit for others in determining how they can foster that local participation in emerging economies, whether through doing something like this or taking the individual components and applying them to their own initiatives.” Ms Scott spoke about the center’s development at the 2022 SPE Annual Technical Conference and Exhibition (ATCE) in Houston, Texas, late last year. When the center first launched, the focus was on engaging with local sup- pliers and enhancing the competencies of their workforce, as well as providing general business support. There were sig- nificant gaps in their awareness, not only of how the oil and gas sector functioned but also around its standards, practices and requirements, Ms Scott said. The center began holding three types of basic awareness seminars – HSSE (health, safety, security and environment), intro to offshore oil and gas, and procurement. The intro to offshore class was formulated to teach local suppliers about the fun- damentals, like what are the differences between the various tiers of contractors in the oil and gas sector. For example, local companies were often seeking to gain specific contracts directly with the operato r because they didn’t understand how the sector’s specialized business eco- system or procurement process operated. The seminar also showed attendees how to leverage opportunities created by local content requirements, along with the ben- efits their country could see from oil and gas development. “In the early days, we were in a country that had little to no energy literacy, par- ticularly within the local business com- munity. We had to ensure that the local business community was engaged and really in a position to benefit from the industry ,” Ms Scott said. The procurement seminar focused on the processes around electronic procure- ment and bidding for work with operators. Participants learned, for example, about standard payment systems in the industry, which are typically based on milestones and completed work instead of the upfront payments that were more common with Guyanese government contracts. From 2017 to 2021, more than 6,000 peo- ple attended the center’s seminars, and new courses have also been added on financial management, supply chain management and human resources management. “ We saw that the local companies we were working with were growing at a fast pace. As a center, we knew that we had to evolve,” said Natasha Gaskin-Peters, Director of the Center for Local Business Development. “While these businesses had a base knowl- edge of the fundamentals, they did not know how to build management systems, so we had to take them through the process of building those systems.” From 2017, when the Center for Local Business Development began operations in Guyana , to 2021, the country saw a surge in the number of local suppliers. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 37 GLOBAL WORKFORCE DEVELOPMENT TOP: The Center for Local Business De- velopment in Georgetown, Guyana, has played a critical role in helping local companies enhance their knowledge around basic functions of the oil and gas industry. Susan Scott (left), Socio- economic Manager for ExxonMobil, and Natasha Gaskin-Peters (right), Center Directo r, spoke at the 2022 SPE ATCE in Houston about the various programs that have been rolled out around things like HSSE, standard payment systems and the digital procurement proces s. BOTTOM: In 2018, the center began of- fering a program to help Guyanese companies enhance their HSSE man- agement system s. Companies were offered one-on-one sessions to help them review or even write related doc- ument s, like HSSE manual s. Once the center got off the ground, it then began providing tailored, individual sup- port to various Guyanese suppliers in the form of one-on-one mentoring. The bulk of these efforts centered on training on international standards and compliance. For example, the center’s first mentoring project involved working with a Guyanese management consultancy to help it obtain certification in ISO 9001, a safety manage- ment system standard. Overall, the center has mentored 26 companies in ISO 9001 certification, including companies focused on fabrication and machining, rigging and slinging, logistics and training . To help Guyanese companies enhance their HSSE management systems, the cen- ter also developed a program in 2018 that 38 offered one-on-one sessions to help them review related documents. If the company did not have existing documents to review, the center would provide information on how to write HSSE manuals, including how to develop standard operating pro- cedures, emergency preparedness policy and environmental policy. This program also included short courses on topics such as job safety analysis, workplace assess- ment and hazard recognition, and incident management. As of 2021, more than 370 Guyanese companies have participated in the program. The center also continues to work with Guyanese companies to develop HSSE- focused workforce training programs. While the training could be customized according to company needs, they typi- cally focus on five key areas of safety man- agement: loss prevention, working in con- fined spaces, working at height, excavation and working near moving equipment. In early 2022, the center kicked off its Project Management Mentorship program. ExxonMobil had identified a gap among Guyanese companies in their knowledge of how to manage multiple projects and deliverables simultaneously, effectively and in a timely manner. The center also has ongoing dialogue with Guyanese policymakers, regulators and other key stakeholders to ensure that regulations are put in place to help bolster the local supplier industry. This is critical for local businesses, many of whom are too small to directly engage with policymak- ers and to have a voice in important regu- latory discussions, Ms Gaskin-Peters said. “The businesses have been very keen to win opportunities, but they don’t know how to navigate the industry and engage with the key stakeholders,” she said. “We engage governments and all the business associations, and that’s key in getting that buy-in into the local community.” DC For more information, please refer to SPE 210444, “The Importance of Early Investments in Local Content: Lessons Learned from Guyana’s Enterprise Development Centre Five Years In.” M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R GLOBAL WORKFORCE DEVELOPMENT Gender equality study explores barriers women in Persian Gulf still face in oilfield careers Industry has shown progress, but more leadership will be needed to help women enter field-based roles, upper management BY STEPHEN WHITFIELD, ASSOCIATE EDITOR As drilling activity continues to ramp up across the Middle East, the growing need for a competent workforce also becomes more evident. To fill this talent gap, many countries in the region have provided more opportunities in recent years for its female workforce, allowing women to take advantage of higher education and industry-specific training. Still, a gender imbalance in the work- force remains . Texas A&M University at Qatar (TAMUQ) and Northwestern University in Qatar cited that as the key motivation behind a recent study explor- ing the obstacles that female petroleum engineers face. To gauge the oil and industry’s progress on gender equality in the workforce – both in Qatar and in the wider Persian Gulf region – the two schools conducted inter- views in 2020-2021 with nine women and three men working in the industry. Based on the personal experiences shared by those interviewees, the schools analyzed the findings and then provided recom- mendations for organizations to help sup- port women across all career levels. In particular, the study called for more oppor- tunities and encouragement for women to pursue upper management positions. “We’re trying to see what the challeng- es are ,” Albertus Retnanto, Professor of Petroleum Engineering at TAMUQ, said of the project’s goals. “What’s happening to women when they’re looking to get in the industry, and what happens to them once they get here? What’s the progress? Some women have built careers here and are starting to move up the ranks, but there is a leak in the pipeline, and it’s important for us to see why,” he said in a presentation at the 2022 SPE ATCE in October. Challenges in hiring and in the workplace The 12 participants who were inter- viewed included field engineers and managers working within the oil and gas industry in areas like reservoir perfor- mance and digital integration ; some were also academics in the petroleum engineer- ing field. Although not every participant was working in Qatar at the time of the study, they each had ties to the coun- try, either through education or former employment . Companies with employ- ees represented in the study include BP, ConocoPhillips, Halliburton, QatarEnergy, Shell and SLB. Among the top challenges the partici- pants cited when talking to the research- ers were a lack of policies or initiatives to promote women into executive positions , as well as explicit discouragement or even discrimination by coworkers and manag- ers during the recruiting and hiring pro- cess. For instance, female participants said they had to deal with biased assumptions and overly personal interview questions that were irrelevant to their professional capabilities and experiences. Several participants in the study also said they saw a stigma placed on women who wanted to take on technical field- based jobs. One woman noted that she was frequently questioned on why she would want to study petroleum engineering and work in the oilfield, and was even told that This graph from a 2019 McKinsey study shows that there is a lower percentage of women represented at all career levels in the oil and gas industry compared with other STEM industries. Representation was also lower in oil and gas versus the av- erage for all companies in the study – encompassing more than 250 companies in industries like banking, manufacturing, pharmaceuticals and healthcare. This and other findings from the study were cited in a 2022 report that looked more specifi- cally at gender equality among the oil and gas workforce in the Persian Gulf. Image source: McKinsey & Company, “How Women Can Help Fill the Oil and Gas Industry Talent Gap.” D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 39 GLOBAL WORKFORCE DEVELOPMENT women were better suited for office-based positions. Another woman noted that a recruiter suggested she not apply for a specific position because it was a “very male job.” Both men and women interviewed in the study pointed out that female new- hires were often sidelined into non-techni- cal positions with limited opportunities to advance or have influence. This created a negative environment where other women would then seek office-based jobs instead of field jobs in order to avoid being scruti- nized by male coworkers. Participants also discussed the cultural and social barriers that women had to confront. This included a lack of prop- er accommodations for women working on offshore rigs – several female inter- viewees mentioned, for example, a lack of women-only restrooms. There is often also a lack of PPE fitted for women, including coveralls and headgear for women who wear a hijab. The study also noted that company restrictions on women traveling alone was still common; one participant said her employer does not allow its female employees to travel without a mahram, or a male blood relative. Policies like this can restrict women from pursuing and explor- ing the various opportunities that their employer offers, like traveling to indus- try conferences or business meetings, or transfers to foreign countries. One male participant who was inter- viewed suggested that appointing more women to managerial positions can help to address some of these issues. The study noted his comment around how cultivat- ing “a diversity of gender allows us to be a lot more effective and solve problems in a smart way versus having only one way of thinking.” One female participant said she has seen, in many instances, that men are willing to help women when they face a lack of accommodations – for instance, not objecting when women have to use men’s restrooms on a rig. At the same time, she expressed skepticism that the industry will see significant change – especially in terms of providing women- specific accommodations – until there are more female managers setting policy and more women working at wellsites. 40 Universities can play an important role when it comes t o preparing female stu- dents to work in the oil and gas industry in the Persian Gulf region, TAMUQ Pro- fessor Albertus Retnant o said at the 2022 SPE Annual Technical Conference in Houston last October . But he also en- couraged those within the industry to do more to help promote gender inclusivity . Successes and suggestions While the experiences shared by the participants clearly show there is a need for improvement, the study also pointed to signs of progress . BP’s Young Adventurers camp in the United Arab Emirates is a good example. While it’s not meant only for women, it is inclusive of women and encourages them to consider engineer- ing careers. The camp puts participants through physical challenges, such as raft building, abseiling and other team activi- ties that encourage campers to use engi- neering skills and knowledge. The camp- ers are divided by gender, and the women’s camp features an all-female staff. One woman in the study said she partic- ipated in the camp when she was younger, and even cited the experience as a key factor in her decision to study engineering in school and, ultimately, begin an oilfield career. She now works as a petroleum engineer for BP and has continued her involvement with the camp as a volunteer. The study cited this statement from her: “There are still these places within this region that a girl can’t even imagine that she can be an engineer or there could be female engineers. That’s why I want to continue this program, to make sure these girls know that there are engineers in the field, and if she is interested and wants to do it, then she can.” Another example of progress is what universities in the region are doing to prepare female students for jobs in the oilfield, Dr Retnanto said. At TAMUQ, for example, women made up nearly 70% of its petroleum engineering graduating class in 2021. Every year, the school organizes field trips for all of its petroleum engineer- ing students, including women, to visit onshore E&P sites. Overall, all the participants in the study said promoting gender inclusivity within the industry will require even more effort from company leadership . They suggested that companies leverage internship pro- grams to incentivize more female students to consider careers in oil and gas, as well as programs that encourage women to enter managerial roles once they start their careers. One male participant in the study encouraged women to enhance their technical capabilities by participating in as many hands-on training and intern- ships as they can. Flexible work hours could also go a long way toward promoting gender inclusivity. Several women said they believe schedule flexibility and remote work can allow orga- nizations to retain more female employees who may face challenges around childcare and caring for aging relatives. One male participant said his employer has given more attention to this in recent years by providing female employees with a blue- print for how to return to work after they take maternity leave. Other things that women themselves could do to promote gender equality include taking the initiative to ask ques- tions , or speaking up when they see unfair treatment. The participants also encour- aged women to report discriminatory remarks they encounter in the workplace to their managers, and said it was impor- tant for women in the workplace to sup- port one another. DC More information available in SPE 210236, “First- Hand Perspectives of the Pro-Female Notion in the Oil and Gas Industry in the Gulf.” M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R NEWS CUTTINGS • DEPARTMENTS ART Committee names new Co-Chairs, recognizes service of previous Chairman Blaine Dow, SLB Drilling Technology Manager, and Sarah Kern, Helmerich & Payne Senior Industry Affairs Specialist, have taken on the positions of Co-Chairs of the IADC Advanced Rig Technology (ART) Committee, succeeding the previous Chairman, Assaad Mohanna . Mr Dow has spent his entire career in drilling, with the past 17 years focused on technology development and deployment in directional drilling, MPD and drilling automation. He has written technical papers and served in volunteer posi- tions with SPE and IADC committees. Ms Kern joined H&P upon graduating from Oklahoma State University with a degree in elec- trical engineering and marketing. Her various roles at H&P have spanned engineering, operations, communications, marketing, intelligence and industry affairs. At its 2023 kickoff meeting on 31 January, the ART Committee presented Mr Mohanna with a plaque in recognition of his ser- vice. Mr Mohanna, who currently serves as a Partner at ERM, had initially served the ART Committee as Vice Chair of the ART Data, Controls and Sensors Subcommittee , which was then the Drilling Control Systems Subcommittee. He began his term as ART Chairman in early 2021 and has overseen the completion of major projects like the IADC Rig Sensor Stewardship Guidelines. Assaad Mohanna (right) receives a plaque from new IADC ART Committee Co-Chair Blaine Dow (left) at the group's 2023 kickoff meeting in Houston on 31 January. New officers elected to lead IADC UW student chapter The IADC Student Chapter at the University of Wyoming (UW), which was established in 2019, recently elected new officers : ■ Josh Stone – President ■ Julian Dawkins – Vice President ■ Pierson Lauterbach – Secretary ■ Cody Zayonc – Treasurer The chapter has been staying active, for example, by inviting alumnis to share their experiences with current petroleum engineering students . Other upcoming events include an IADC well control training course in March and a potential field trip/rig tour in Colorado with Ensign Energy Services in the spring. IADC student chapters attend Patterson-UTI rig showcase IADC ISP releases Q4 2022 report, announces project to develop online portal On 26 January, IADC released its Q4 2022 Incident Statistics Program (ISP) report, which provided a year-end sum- mary of safety-related data from partici- pating drilling contractors . As in previ- ous years, the data is compiled separately for both onshore and offshore operations within nine geographic regions. Through the end of Q4 2022, ISP participants record- ed a total of 329,745,043 manhours worked, tallying 1,103 recordable incidents, 311 lost- time incidents and 15 fatalities. Also in January, a kickoff meeting of the IADC ISP Subcommittee, which oper- ates under the HSET Committee, was held to initiate the first phase of a project to develop an online portal for entering and accessing ISP data. Once completed, par- ticipating compan ies will be able to more easily enter their data in the cloud, as well as get real-time comparisons of their data against wider industry data . David Millwee (left), VP of Drilling Performance at Patterson-UTI, leads a rig tour for a group of students on 26 January . A total of 14 students from three IADC Stu- dent Chapters – Texas A&M University, the University of Louisiana-Lafayette and the University of Texas at Austin – attended Patterson-UTI's technology show- case, held at the company's Houston rig-up yard . The students had the chance to get a fi rst-hand look at a variety of cutting-edge drilling and completion technologies. A link to DC's video from the showcase can be found on Page 12. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 Scan me to access the IADC Incident Statistics Program Q4 report. bit.ly/3SOvVDP 41 IADC CONNECTION • EDITORIAL Next-gen engagement and enthusiasm continue to flourish FROM THE PRESIDENT Attracting and retaining new talent for the industry’s workforce is not a new topic, yet it is a highly resonant one. That’s no sur- prise – drilling contractors will continue to drill for vital resources for the world to use, and that is only possible because of the people behind the operations . The US Energy Information Admin- istration is projecting that, while renew- able energy may be the fastest-growing source, petroleum and natural gas will remain the most-consumed sources of energy in the US through 2050. In order to continue meeting the world’s rising energy demands, we must ensure that our workforce is plentiful and prepared. The needs of the younger workforce are shifting; it’s critical that we meet them where they are and inform them of the importance of what we do. In the last issue of this magazine, Subodh Saxena, Senior VP at Nabors Industries, said it well: “The cultural change involves understanding who today’s workers are and recognizing that we have to trans- form ourselves and move toward them.” How do we do this? How do we under- stand the professional expectations of the up-and-coming workforce, and then ensure that we’re living up to those expectations? I think the best way is to go directly to the source – to engage with these young professionals as early as possible in their careers with as much earnestness and authenticity as possible. I view this as a mutually beneficial relationship. Drilling contractors and established energy professionals have knowledge, resources and ample oppor- tunities to offer . Similarly, I believe the younger workforce can provide innova- tion, new perspectives and ingenuity . IADC has been constructing a pathway for interested young professionals , begin- ning with our Student Chapter program . It allows students to participate in the industry and start building their profes- sional networks before they even gradu- ate from college. 42 The number of participating schools has grown from four at the start of 2019 to 14 now , and we’re anticipating the addi- tion of two to three new Student Chapters over the next year, working toward the ultimate goal of 20 participating schools. Since the inception of the Student Chapter program, IADC has sponsored more than 900 students to attend our international conferences. David “D.J.” LaRosa, Chairman of the IADC Marietta College Student Chapter, attended our Annual General Meeting for the first time in November. In a DrillBits article about the event, D.J. stated, “We were able to make connections with our parents’ gen- erations and our own generation, which, in my opinion, is a rare experience to get in college. I wholeheartedly believe that the conference benefitted my future career. I have more business cards from this conference than every other confer- ence I have attended in college combined. I feel like I made real connections with people that could last a lifetime.” Connections are a vital part of busi- ness and a valuable component of the Student Chapter program. In fact, many of the connections and opportunities provided to Student Chapters are only possible because of IADC members. For example, 14 students from Texas A&M, the University of Texas at Austin, and the University of Louisiana at Lafayette were recently invited to participate in an event hosted by Patterson-UTI. The students had a phenomenal time touring a rig and learning about different aspects of rig life. During the event, Smith Mason & Co, which is heavily involved in hosting IADC-accredited training for UL-Lafayette students, connected with students from UT and discussed a similar partnership to prepare them for entering the workforce . The next step in the career pathway includes encouraging recent graduates and young professionals to join IADC committees or to become involved in other ways that speak to them. Jason McFarland, IADC President The IADC Young Professionals (YP) Committee provides opportunities for those new in their careers to engage with the IADC community , and there are plans to further increase the committee’s scope this year. This is evidenced in part by the recently added subcommittees and expanded leadership positions within the committee. They are planning to offer a variety of occasions for networking and an increased number of “Luncheon with Leaders” events, along with a new series of professional development webinars. In the past year, we’ve witnessed the formation of two new YP Subcommittees under the branches of IADC Regional Chapters in South Central Asia and Australasia. These YP Subcommittees have been offering occasions for net- working and connecting YPs with estab- lished industry experts in these regions. All of this makes me believe that inter- est and eagerness are both alive and well within the younger workforce. I see spe- cific examples of individuals stepping up to volunteer their time, to pay it forward with their efforts in areas they’re passion- ate about. These individuals are represen- tative of a broader workforce, one that is plentiful and prepared for today’s energy demands and those of the future. Our role is to teach them about the importance of what we do and why it’s necessary, to inform them of the oppor- tunities available, and to provide a clear pathway for them in this industry. It’s our job to show them who we are and how much we care about the same things they care about – working with purpose, seek- ing solutions to complex issues, acting as respectful stewards of the environment , and leaving the world a slightly better and safer place than we found it. DC M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R EDITORIAL • IADC CONNECTION Evolution of IADC student chapters 2017 The fi rst IADC Student Chapters established at Texas A&M University, Missouri S&T and University of Louisiana at Lafayette 2018 2020 2019 2021 2022 Chapters established at Bossier Parish Community College, Lone Star College, Pandit Deendayal Energy University, and University of North Dakota Chapters established at Curtin University (Perth) and University of Texas – Austin Chapters established at Louisiana State University, Maharashtra Institute of Technology and University of Wyoming Chapters established at King Fahd University for Petroleum & Minerals and Marietta College 2023 D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 43 IADC CONNECTION • WIRELINES NOIA ESG report highlights emissions reduction case studies by member companies The US National Ocean Industries Association (NOIA) released a report in January highlighting the work done by its ESG Network and other members to share and develop ESG best practices across the offshore energy industry. The report features case studies in emis- sions reduction from 16 member compa- nies, including BP, Halliburton, Noble Corp, NOV, Oil States International, Shell,  SLB, Talos Energy, TechnipFMC and others. The Noble case study, for example, discusses how the company is using data to drive emissions reductions. With advanced monitoring equipment on its deepwater rigs, fuel consumption can now be accu- rately tracked and modeled to derive car- bon emissions data. One notable result of the measurement has been a significant optimization of thruster operations. NOIA’s report also discusses the work of the its Carbon Capture and Storage (CCS) Workgroup, including a CCS policy paper published in 2022. The group is also work- ing with the Offshore Operators Committee to support a forward-looking offshore car- bon sequestration regulatory regime. Further, the report outlines NOIA’s suc- API urges EPA to adopt modifications to methane rule API submitted a letter and 160+ pages of comments to the US Environmental Protection Agency (EPA) on 13 February urging the agency to modify its supple- mental proposed rules to reduce meth- ane emissions in oil and gas operations. While API supports cost-effective and direct regulation of methane, it empha- sized that these efforts should not com- promise innovation or production of American energy. In its comments, API outlined its con- cerns with several aspects of the pro- posed rule, including the applicability date of the final rule, the implementation of the Super-Emitter Response Program, the lack of flexibility for the use of alter- native detection technologies and asso- ciated gas provisions. API also provided recommendations that aimed to foster industry innova- tion and bring about a “final rule that is cost-effective, feasible to implement and achieves continued meaningful reduc- tions in methane emissions.” API noted that voluntary, industry-led initiatives such as the Environmental Partnership “have built on the progress industry has made to reduce emissions and continuously improve environmen- tal performance.” Since its founding in 2017, the Partnership has grown to include more than 100 companies repre- senting over 70% of total US onshore oil and natural gas production. The letter also pointed out that average methane emissions intensity declined by nearly 66% from 2011-2021 across all seven US major producing regions. Scan me to read API’s comments to the US EPA. bit.ly/3KJSpDB UH signs MoU with India to establish energy data center The Directorate General Hydrocarbon (DGH), the technical arm of the Indian Ministry of Petroleum and Natural Gas, has signed a memorandum of under- standing (MoU) with the University of Houston to establish a data center. It will house a geoscience data repository with display capability and software to inter- pret E&P data and knowledge of India’s sedimentary basins and fields. The five-year agreement aims to pro- vide reliable, high-quality data – includ- 44 ing seismic, well, reservoir and produc- tion data – for research and develop- ment, as well as to investors and compa- nies based in the Greater Houston area and the US Gulf Coast to encourage com- mercial opportunities involving Indian offshore offerings. “This MoU is essentially an agreement to spur collaboration and combine the strengths of the involved parties for great- er good,” said Ramanan Krishnamoorti, VP of Energy and Innovation at UH. cessful lobbying efforts for key offshore oil and gas, wind and carbon storage provi- sions in the US Inflation Reduction Act. NOIA launched its ESG Network in January 2020 as a platform for learning, collaboration and continued improvement in ESG. Scan me to read NOIA’s 2023 ESG Network report. bit.ly/3ELp3RL US Labor Department updates OSHA penalties, enforcement guidelines In January, the US Department of Labor announced changes to Occupational Safety and Health Administration (OSHA) civil penalty amounts based on cost-of-living adjustments for 2023. OSHA’s maximum penalties for serious and other-than-seri- ous violations will increase from $14,502 per violation to $15,625 per violation. The maximum penalty for willful or repeated violations will increase from $145,027 per violation to $156,259 per violation. The Labor Department also issued new enforcement guidance, which the agen- cy says are designed to make its penal- ties more effective in stopping employers from repeatedly exposing workers to life- threatening hazards or failing to comply with certain workplace safety and health requirements. OSHA Regional Administrators and Area Office Directors now have the author- ity to cite certain types of violations as “instance-by-instance citations” for cases where the agency identifies “high-gravi- ty” serious violations of OSHA standards specific to certain conditions where the language of the rule supports a citation for each instance of non-compliance. The pre- vious policy had only applied to egregious willful citations. Further, OSHA reminded its Regional Administrators and Area Directors of their authority not to group violations together, and instead cite them separately, to more effectively encourage employers to comply with the intent of the OSHA Act. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R UPCOMING IADC EVENTS • IADC CONNECTION IADC HSE AND S U S TA I N A B I L I T Y ASIA PACIFIC IADC Drilling Onshore C C O O N N F F E E R R E E N N C C E E CONFERENCE & EXHIBITION & & E E X X H H I I B B I I T T I I O O N N 23-24 MAY 2023 GRAND HYATT KUAL A LUMPUR KUAL A LUMPUR, MAL AYSIA 18 MAY 2023 H YAT T R E G E N C Y HOUSTON WEST HOUSTON, TEXAS IADC International Tax SEMINAR 8-9 JUNE 2023 SEMINAR G R A N D H YAT T S A N A N TO N I O R I V E R WA L K S A N 2023 IADC WORLD DRILLING CONFERENCE & EXHIBITION A N T O N I O , T E X A S IADC WELL CONTROL CONFERENCE OF THE AMERICAS & Exhibition 20-21 JUNE 2023 PULLMAN LONDON S T. PA N C R A S H O T E L LONDON, UNITED KINGDOM 22-23 AUGUST 2023 THE N E W RITZ CARLTON O R L E A N S , L O U I S I A N A To register for these and other conferences please visit us online at www.iadc.org/conferences/upcoming. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 45 IADC CONNECTION • DRILLING CONTRACTOR DON’T MISS OUT ON OUR NEXT ISSUE! EDITORIAL PREVIEW May/June ◊ ◊ ◊ ◊ Shale Drilling: Innovations to Fill Technology Gaps Offshore Technologies & Markets Coiled Tubing & Well Interventions Carbon Capture, Utilization and Storage DISTRIBUTION: OTC [1-4 MAY, HOUSTON, TEXAS] IADC Drilling Onshore Conference [18 MAY, HOUSTON, TEXAS] IADC HSE and Sustainability Asia Pacifi c Conference & Exhibition [23-24 MAY, KUALA LUMPUR, MALAYSIA] OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS DRILLINGCONTRACTOR.ORG IADC.ORG SPE/IADC Middle East Drilling Technology Conference & Exhibition [23-25 MAY, ABU DHABI] IADC World Drilling Conference [20-21 JUNE, LONDON] AD CLOSING: 31 MARCH MATERIALS DUE: 7 APRIL News 46 Visit DrillingContractor.org for the latest drilling industry news and videos DNV research finds energy security is top priority in energy trilemma for 2023 IWS appoints Shiblee Hashem as new VP of Operations Surging prices make oil and gas sector top choice for energy workers, says new report INEOS enters US onshore market as operator with Eagle Ford asset acquisition Stena Drilling awarded contract with Ithaca in UKCS New BP Energy Outlook incorpo- rates impacts from Russia-Ukraine war, US Inflation Reduction Act M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R PEOPLE, COMPANIES & PRODUCTS • DE PAR TM E NTS Nabors acquires digital twin developer MindMesh Nabors announced its acquisition of MindMesh, including the company’s downhole simulation and modeling tech- nologies . With this acquisition, Nabors expects to integrate MindMesh’s physics-, AI- and machine learning-driven mod- els with Nabors’ Smart Suite of drilling automation and digitalization products. Nabors says it expects to rapidly advance its ability to predict drilling dysfunctions in real time . Additionally, MindMesh Co-Founder and Chief Technology Officer Raju Gandikota joined Nabors as a Director in the Controls and Automation group. Baker Hughes nets greenfield project contract offshore Angola Baker Hughes has been awarded a major contract to provide subsea equipment and services to Azule Energy for the Agogo oilfield, offshore Angola. This award represents the first major new greenfield project awarded offshore Angola in more than five years. The scope of work includes 23 stan- dard subsea trees, 11 Aptara manifolds, SemStar5 fiber optic controls and the relat- ed system scope of supply. Baker Hughes will also provide services and aftermarket support for the Agogo integrated west hub subsea production system. Wild Well, Endeavor partner on well control training simulators Wild Well Control announced a part- nership with Endeavor Technologies to provide drilling simulators for its well control training simulator rooms across the US. The launch will begin in Houston, and W ild Well plans to install the simula- tors in all US locations by the end of 2023. The simulators are expected to aug- ment the training environment so stu- dents can better enhance their under- standing of well control concepts using hands-on scenarios. Oceaneering looks to wind to electrify offshore assets Oceaneering has signed a memoran- dum of understanding (MoU) with Kontiki Winds to pursue the application of float- ing offshore wind for remote microgrid renewable power generation. The goal is to electrify offshore assets, such as oil and gas platforms, as well as other small-scale power-generation opportunities among island states currently producing electric- ity by fossil fuel. The MoU has a particular focus on the Gulf of Mexico, Brazil and Northern Europe. KCA Deutag integrates Saipem’s Kuwait business KCA Deutag completed the acquisition of the Kuwait component of the Saipem Onshore Drilling business, part of its over- all deal to acquire the company. This adds Cudd Well Control launches new global headquarters Cudd Well Control has consolidated its offices and warehousing in one location, at a new 27,000-sq-ft global headquarters in Hockley, Texas, in the Houston area. Advanced well control training will be held onsite . ABS names Ryan as CTO ABS has appoint- ed Patrick Ryan to the role of Chief Technology Officer. Mr Ryan had served as Senior VP of Global Engineering and Technology at ABS since 2019. Patrick Ryan Hopkins promoted to VP of Upstream Policy at API API promoted Holly Hopkins to VP of Upstream Policy. Ms Hopkins formerly served as API’s Director of Upstream Policy and succeeds Cole Ramsey, who is returning to API’s Office of General Counsel as Senior Counsel. GD Energy Products upgrades Texas facility to other completed acquisitions last year, which included Saudi Arabia, the UAE and Africa. Acquisitions of the Latin America business, as well as rigs in Romania and Kazakhstan, are expected to be completed during the first half of 2023. Expro adds to portfolio with DeltaTek Global acquisition Expr o has acquired well construction cementing specialist DeltaTek Global, which offers a range of low-risk open water cementing solutions . LYTT joins AWS cloud network LYTT and Amazon Web Services (AWS) will collaborate on scaling LYTT’s sensor fusion insights platform using AWS’ cloud infrastructure. LYTT offers a cloud-based, end-to-end data analytics platform used in multiple industries, including oil and gas. GD Energy Products completed a large-scale renovation of its plunger manufacturing facility in Aledo, Texas, to expand its manufacturing capabili- ties and improve workplace condi- tions while reducing its environmental footprint. Shell merges Integrated Gas, Upstream businesses Shell announced it will merge its Upstream and Integrated Gas busi- nesses into an Integrated Gas and Upstream Directorate , led by Upstream Director Zoe Yujnovich. The Strategy, Sustainability and Corporate Relations Directorate will be discontinued. Strategy will be brought together with New Business Development. Strategy and Sustainability will report to CFO Sinead Gorman. Corporate Relations will report to CEO Wael Sawan. As part of the change, Shell will also reduce its Executive Committee from nine to seven members. D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 47 DE PAR TM E NTS • PEOPLE, COMPANIES & PRODUCTS TWMA reaches 4.5 million LTI-free work hours in the Middle East TWMA, a drilling waste management company, announced it has achieved 4.5 million work hours without a lost-time incident (LTI) across its Middle East oper- ations. The milestone was achieved over the course of 10 years, the company said, and is a result of a focus on identifying and controlling hazards, reducing expo- sure to health and safety risks, and sup- porting the general health and well-being of its team members. DNV to advise Ocyan on hydrogen conversion process for rigs Ocyan has named DNV as an inde- pendent third party in the qualification process of a system injecting hydrogen as an additive in the internal combustion engines of its drilling rigs. The goal is to reduce diesel consumption and green- house gas (GHG) emissions from drilling. DNV’s technology qualification process will ensure that the technology achieves the expected degree of maturity. The proj- ect is supported by Shell Brasil, through the RD&I investment clause of Brazil’s National Agency of Petroleum, Natural Gas and Biofuels. Logan Industries achieves API 8C monogram license for hoisting equipment Logan Industries, a hydraulic repair, manufacturing and rental company, has completed the requirements for API 8C Monogramming for Hoisting Equipment at its manufacturing facil- ity in Hempstead, Texas. The license currently includes hoist- ing sheaves at PSL 1 and PSL 2. This product certification enhances Logan’s abilities under its Quality Management System API Q1 and ISO 9001: 2015 cer- tifications. “We understand that this API certi- fication marks a new era of opportu- nity for Logan Industries, and we have acquired additional assets to ensure control of our internal processes,” said Dean Carey, Technical Director at Logan. Products Baker Hughes solution targets asset management Baker Hughes launched Cordant, an integrated suite of solutions supporting industrial asset performance manage- ment and process optimization. It builds on the company’s expertise around rotating equipment, critical sensors, valves, pumps, gears and inspection service. E&Ps’ digital assets, tools and insights can converge within Cordant and easily integrate with existing Baker Hughes technologies, as well as tech- nologies from other manufacturers. Cordant can be deployed as a hard- ware/software bundle; software as a service; on-premise offerings; or as an outcome-based solution tied to specific performance indicators. Baker Hughes also announced a strategic investment and collaboration with Corva to bolster rig visualization capabilities. Baker Hughes will become an international reseller of Corva well construction products, as well as being the exclusive international reseller for Corva in certain regions. In addition, Baker Hughes will introduce new appli- cations on the Corva App Store. 48 Industrial-grade sealing device ideal for leak stoppage Denios has introduced the RuptureSeal family of leak-stopping devices, which can be deployed in 20 seconds to form a secure mechanical seal that stops leaks for up to 10 hours. The devices are avail- able in four sizes and are compatible with over 40,000 substances. With full fuel and chemical compatibility, as well as an oper- ating range of -16°F to 122°F, they are ideal for controlling chemical and fuel spills, pipe leaks and breaches. Halliburton partnership to provide digital emissions management Halliburton and Siguler Guff, a private markets investor, have formed Envana Software Partners, which will provide emissions management software-as-a- service (SaaS) solutions to track green- house gas emissions. Halliburton created the Envana digital emissions manage- ment solution to give companies action- able information to manage their car- bon footprint. Additional products are in development to support methane detec- tion and quantification management. The venture’s first offering, Envana Catalyst, is an SaaS system that helps increase transparency of the environmen- tal impact of drilling and completions operations. It was built on Halliburton Landmark’s iEnergy hybrid cloud environ- ment. Envana Catalyst allows customers to choose the methodologies used to esti- mate emissions from a library of emis- sions sources tailored to the oil and gas industry. It is available both as a stand- alone solution and as additional func- tionality integrated into E&P workflows within the Halliburton DecisionSpace 365 suite of products. M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R AD INDEX Derrick Corporation........................................2 GD Energy Products.....................................52 IADC Accreditation..........................................5 IADC Bookstore................................................ 19 IADC Drilling Onshore Conference & Exhibition...................................................... 13 Noble Corporation........................................49 Offshore Europe 2023.................................. 51 TSC Drill Pipe...................................................... 17 Sign up for DrillBits www.iadc.org/ newsletter-signup Global Sales Manager For all sales inquiries regarding Drilling Contractor, official magazine of the International Association of Drilling Contractors, please contact: BILL KRULL Phone: +1-713-292-1954 Cell: +1-713-201-6155 bill.krull@iadc.org Drilling Contractor / IADC Houston HQ LINDA HSIEH - Vice President, Editor & Publisher linda.hsieh@iadc.org STEPHEN WHITFIELD - Associate Editor stephen.whitfield@iadc.org BRIAN C. PARKS - Creative Director brian.parks@iadc.org ANTHONY GARWICK - Director – Web & IT Services anthony.garwick@iadc.org Find us online Stop by our LinkedIn page to join the conversation, keep up with news and conference updates on Facebook and Twitter, then check out our YouTube video channel! 9,255+ Followers 30k+ Followers 5,365+ Followers 2.82K Subscribers 2,295,150+ Views D R I L L I N G C O N T R AC T O R • M A R C H/A P R I L 2023 49 DEPARTMENTS • PERSPECTIVES Richard Grayson, Nabors: Being flexible is critical to a long career in an industry of constant change BY STEPHEN WHITFIELD, ASSOCIATE EDITOR The oil and gas industry draws people for many reasons. Maybe they have family in the industry or a love of geology, or perhaps they were awed by the sight of a drilling rig at a young age. Some people, however, are drawn to it for more practical reasons. For Richard Grayson, Senior QHSE Manager at Nabors Industries, it was a way to make good money. Though he grew up surrounded by rigs in Noble, Okla., Mr Grayson never thought much about a career in oil and gas. He was good at the natural sciences, and upon entering the University of Oklahoma in 1973, he decided to study zoology and ani- mal biology. Drilling didn’t enter his life until after his freshman year, when he joined a friend on a summer job working as a floor hand on a land rig in Oklahoma. “I needed money to go to school. It was more money than I could make anywhere else. I worked there all summer and just kept doing it,” he said. That first rig hand job became a means for Mr Grayson to help pay for college. He would work summers, weekends, holiday breaks, or whenever another floor hand would want a day off. Soon, Mr Grayson realized that the oilfield offered a better future than zoology, so he kept working on rigs, even after graduating from the University of Oklahoma in 1977. He worked for multiple drilling com- panies in Oklahoma over the next sev- eral years, switching jobs depending on the needs of the company and the rig: Sometimes he was a toolpusher, some- 50 times a derrickman. By the early 1980s, he’d become a rig manager. The constant ups and downs of life in the industry ultimately began to wear on him though. “I kept getting laid off because a rig would finish a contract. You never knew what would happen.” After the industry went into a downturn in 1982, he switched gears and took a teach- ing job at the University of Oklahoma’s well control school. In 1985, that position led to a job in Houston as a well control instructor at Reading and Bates (R&B), an offshore drilling contractor. In 1990, Mr Grayson was promoted to HSE and Training Supervisor, and in 1995 he was named Training Manager for International and Deepwater Operations. Throughout the years, he taught well control and con- ducted safety audits worldwide. Mr Grayson said his time at R&B taught him a lot about leadership. “I learned how to be a supervisor in a multinational cor- poration,” he said. “There are certain things you must do to be a good leader. Listening to your direct reports, being willing to train because most people want to move up in the world, understanding all aspects of your people’s jobs, and controlling your emotions are a few.” In 2000, he joined Nabors Industries as QHSE Manager, attracted by the change in scenery and the chance to work onshore again, which he had not done for near- ly two decades. As part of this job, Mr Grayson developed new strategies around health, safety, environment and training. He also oversaw various aspects of Nabors’ safety training protocols when the nature of safety training was rapidly changing. In 2016, Mr Grayson added Global Well Control Focal Point to his title. In addition to overseeing various safety protocols, he conducts crew assessments and well con- trol equipment readiness inspections. He also manages the company’s well control documents, several of which he authored, and leads the company’s internal well con- trol committee. Volunteering with IADC Mr Grayson is no stranger to IADC. He first got involved in the 1980s, during his training days at R&B. He helped restart the HSET Committee, then called the Training Committee, after it had been suspended Richard Grayson, QHSE Manager and Global Well Control Focal Point at Na- bors Industries, has been involved with IADC for many years in activities related to safety, well control and training. He has chaired multiple committees and now sits on an advisory panel for the IADC WellSharp accreditation program. for lack of interest. His first appearance in this magazine came in the June/July 1990 issue, when he co-authored an article on a well control worksheet that helps control slanted-hole kicks. In the decades since, Mr Grayson has chaired the IADC Training and Well Control committees. He is a member of the HSET Committee and sits on the advisory panel for the WellSharp accreditation pro- gram. He also sits on a three-person panel that reviews well control instructor appli- cations for IADC. Mr Grayson said his work with IADC focuses on helping drillers work in chang- ing times. For instance, the WellSharp Live distance learning option was developed during the COVID-19 pandemic, but its adoption has continued as drillers have adopted more remote work into their oper- ations. Change is the one constant he has seen in the industry, he said, and learning to adapt is critical to thriving in the future. “Some people would say that oil and gas is a sunset industry and that we’re on the way out, but I don’t believe that. I do believe – and it’s been true in my career – that you need to be willing to change,” Mr Grayson said. “There will be a lot of change in our industry, and it will be a very interesting time. You just need to embrace it.” DC M A R C H/A P R I L 2023 • D R I L L I N G C O N T R AC T O R 5-8 SEPTEMBER 2023 P&J LIVE, ABERDEEN ACCELERATING THE TRANSITION TO A BETTER ENERGY FUTURE • Gain industry exposure Showcase your new technologies and services to the entire offshore energy value chain to meet evolving energy needs • Make connections that matter Effectively develop your sales pipeline and meet with leading buyers and suppliers from across the offshore energy supply chain. • Keep your business competitive and progressive Share ideas, expand your infl uence and gain the knowledge and skills through our live and online content BOOK A STAND offshore-europe.co.uk/iadc Organised by WE BUILD CONFIDENCE INNOVATION THAT IMPACTS PERFORMANCE. At GD Energy Products, , we’ve always led through innovation – helping our customers achieve more for nearly two centuries. From the revolutionary pumps and parts we produce, to the support provided by our dedicated team of expert engineers and service team members, we remain dedicated to delivering solutions that set standards across the industry. We’ve led through innovation from day one. WATCH THE VIDEO TO LEARN HOW