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15
Driving forward, digitally
Lucas Rocha, President in Middle East and Asia, Tenaris, shares how customer collaboration, strengthened by digital transformation, is reshaping the OCTG and line pipe supply chain in the UAE.
06 Asia Pacific’s transforming energy landscape
Golak Patnaik, Principal Analyst, Asia Pacific Upstream Research, Wood Mackenzie, looks back at 2024’s upstream highlights for the Asia Pacific region, revealing the distinct dynamics at play in its varied oil and gas markets.
10 Shaking it up
Danny Salinas, Federico Mezzatesta, and Jessica Stump, NOV, explain how using a high-capacity, intuitive shaker can enhance drilling performance and efficiency.
Viridien is an advanced technology, digital and Earth data company that pushes the boundaries of science for a more prosperous and sustainable future. With our ingenuity, drive and deep curiosity we discover new insights, innovations, and solutions that efficiently and responsibly resolve complex natural resource, digital, energy transition and infrastructure challenges.
18
People are the key to everything
With a new name and its guiding vision to “see things differently”, Viridien (formerly CGG) focuses on human ingenuity to usher in a bright future across multiple sectors.
24 In the cold with cutting-edge consumables
Connor Docherty, SPM Oil & Gas, a Caterpillar company, highlights advances in durable pump consumables and how they promote greater operational efficiency.
28 Managing mercaptans
Jennifer Knopf, Dr. Ulf W. Naatz, and Neil Lawrence Tobin, Vink Chemicals, discuss mercaptan removal strategies in the oil and gas industry and highlight a way to effectively manage and control their presence.
Our priority is the safe on-time delivery of your global energy projects. CRC Evans utilises market-leading welding and coating services, technologies and advanced data solutions, combined with a right first time approach.
Comment
Elizabeth Corner, Senior Editor elizabeth.corner@palladianpublications.com
As the global energy transition accelerates, the oil and gas sector faces mounting pressure to demonstrate tangible progress in decarbonisation.
The recent publication of the Oil & Gas Decarbonisation Charter (OGDC) Baseline Report marks a significant step forward in this journey. Bringing together 54 signatory companies – representing nearly 45% of global oil production – OGDC has established a robust foundation for collective climate action. The report not only highlights the progress made in the initiative’s first year but also sets the stage for scaling efforts across diverse operating environments.
What makes this milestone particularly noteworthy is the momentum it has generated. With three new members joining the initiative (Oil India Limited, PetroChina, and Vår Energi), OGDC’s influence continues to grow. From committing to net-zero operations by 2050, to tackling methane emissions and eliminating routine flaring by 2030, the Charter’s goals reflect the sector’s potential to lead meaningful change. The emphasis on knowledge sharing and peer collaboration offers a pathway for companies to learn from best practice, overcome challenges, and align strategies with global climate ambitions.
Yet, the challenges ahead cannot be underestimated. The report underscores the critical need for standardised reporting frameworks and more cohesive approaches to emissions reduction. With signatories at varying stages of the decarbonisation journey, the initiative’s success will hinge on its ability to foster inclusivity, ensure transparency, and provide targeted support for those facing greater hurdles. As the industry navigates this transformative era, the OGDC stands as a beacon of what can be achieved when collaboration and ambition converge.
Looking ahead, the OGDC represents more than just an industry initiative – it is a model for how collective action can drive systemic change. By leveraging the diverse experiences and expertise of its signatories, the Charter is helping to bridge the gap between ambition and action, creating a blueprint for responsible energy production in a decarbonised world. As the industry continues to invest in future energy systems like hydrogen, carbon capture, and renewable technologies, initiatives such as OGDC will play a vital role in ensuring that oil and gas companies remain proactive contributors to the global climate agenda. The road to net-zero is long and complex, but with collaboration at its core, OGDC provides a tangible path forward for one of the world’s most pivotal industries.
In this issue of Oilfield Technology, Viridien (formerly CGG) introduces its new name and company ethos, describing how its efforts to focus on human ingenuity, in combination with smart technologies, will help to advance the oil and gas sector, among others. Viridien also hopes to bring the benefits of geoscience and data science to energy transition and environmental initiatives: “We believe if we can provide really good information, the world can do what it needs to do to provide energy with less negative impact” (Peter Whiting, EVP Geoscience). Read the article at p.18.
Also in this issue: 2024’s upstream highlights from the Asia Pacific region; intuitive shaker technology; reshaping OCTG and line pipe supply chains in the UAE; mercaptan removal strategies; and maximising pressure pumping with durable pump consumables.
wQatarEnergy entered into an agreement with TotalEnergies to acquire interest in block 2913B (PEL 56) and block 2912 (PEL 91), both located in the Orange Basin, offshore Namibia.
Australia
Falcon Oil & Gas Ltd. announced the spudding of the Shenandoah S2-4H well in the Beetaloo Sub-basin, Northern Territory, Australia with Tamboran (B2) Pty Limited.
Brazil
Shell Brasil Petróleo Ltda. announced the start of production of the floating production storage and offloading facility (FPSO) Marechal Duque de Caxias in the Mero field, offshore Brazil.
North Sea
Equinor has struck oil and gas near the Fram field in the North Sea. The discovery is estimated at between 13 - 28 million boe.
Central Asia
MOL Group and Kazakhstani national oil company KazMunayGas (KMG) have signed an agreement to jointly explore opportunities in the oil, gas and petrochemical sector.
Middle East
Kent, provider of engineering and project management services, announced it is collaborating with BASF on gas treatment in the Middle East.
United Kingdom
Mermaid Subsea Services (UK) Ltd has successfully wrapped up what is believed to be the largest vessel-based UK North Sea decommissioning campaign in history.
EIA: US crude oil production establishes new record in August 2024
The US Energy Information Administration (EIA) has recorded that an average of 13.4 million bpd of crude oil was produced in the USA during August 2024, a new record according to data from EIA’s Petroleum Supply Monthly. More crude oil was produced in the United States during August 2024 than during December 2023, when the previous monthly record of 13.3 million bpd was set. In the first eight months of 2024, average monthly US crude oil production only fell below 13 million bpd once, in January. For the full year of 2024, we forecast US crude oil production will average 13.2 million bpd, according to EIA’s most recent Short-Term Energy Outlook, published on 13 November. That volume would be more than the 2023 annual average of 12.9 million bpd, which is the current annual production record. In 2025, EIA forecasts US crude oil production will average 13.5 million bpd. The US became the world’s top crude oil producer in 2018, a position it has maintained each year since.
Similarly, EIA also recently reported that US production of associated-dissolved natural gas, or associated natural gas, increased 7.9% in 2023 compared with 2022, averaging 17.1 billion f3/d last year, according to data from Enverus Drillinginfo. Associated natural gas production, which is natural gas produced by wells that predominantly produce oil, comes mainly from five major oil-producing regions in the US – the Permian, Bakken, Eagle Ford, Anadarko, and Niobrara.
bp awarded NCMA 2 exploration block
bp has announced that it has been awarded the NCMA 2 block offshore Trinidad as part of the Shallow Water 2023/24 bid round that closed in May 2024. NCMA 2, located approximately 30 miles off Trinidad’s north coast, opens a new area of exploration for bp in Trinidad & Tobago, as all current production comes from the Columbus Basin off Trinidad’s east coast.
bpTT President David Campbell said: “Continued exploration activity is crucial for sustaining our industry and I am very pleased that we have secured this block. The NCMA area is new to bp in T&T and I am looking forward to maximising its potential. Although geographically new to us, we will be able to draw on our 50-plus years of exploration experience in Trinidad and Tobago.”
This announcement is the latest demonstration of bp’s Trinidad strategy to access new basins while maximising production in existing acreage. Since the beginning of the year, bpTT has successfully completed its infill drilling programme, announced the divestment of some of its mature assets, entered into a joint venture arrangement with EOG Resources for the Coconut development and is close to completing the Cypre development drilling campaign.
Vaca Muerta sets crude output record in 3Q24
Argentina’s Vaca Muerta shale play reached a new oil production record of 400 000 bpd in 3Q24 and is on track to hit 1 million bpd by 2030, according to Rystad Energy’s latest analysis. The 35% y/y surge in 3Q production was driven by improved productivity and expanded takeaway capacity, led by flagship operator Yacimientos Petrolíferos Fiscales (YPF) and bolstered by local independent producers.
This growth is also reflected in the increasing number of horizontal wells put on production, which averaged 40 wells per month in Q3, up from 33 in Q1, and 34 in the second. A record 46 new wells were brought online in September alone, of which 39 were in the oil zone and the remainder in the gas zone, underscoring the continued operational efficiency and momentum of Argentina’s flagship shale play.
World news
ExxonMobil transfers Block 52 offshore Suriname to Petronas
ExxonMobil Exploration & Production Suriname B.V. has formally notified Suriname’s national energy company, Staatsolie, that it will withdraw from Block 52 in the Surinamese offshore area effective 14 November 2024. This withdrawal is part of ExxonMobil’s ongoing evaluation of assets in its global portfolio. ExxonMobil is transferring its fifty percent working interest to Petronas Suriname E&P B.V., which is the operator of the block. With this transfer, Petronas now holds a 100% working interest in Block 52. Operations in Block 52 will continue as usual.
Block 52 covers an area of 4749 km2 and is located north of the Surinamese coast. A gas discovery was made in this block in 2020 with the Sloanea-1 exploration well. Petronas is further exploring the gas discovery by drilling the Sloanea-2 appraisal well earlier this year. A Letter of Agreement (LoA) was also signed with the Contractor on 4 March 2024.
The production sharing contract allows parties to bring in partners to a block or transfer their interests to another party. Staatsolie expects Petronas to continue the activities in Block 52 without interruption and is confident in the continuation of the good partnership between the two companies.
DNV certifies first CO2 storage site in the Middle East for ADNOC CCS project
DNV has certified the feasibility of ADNOC’s West Aquifer CO2 storage site in the UAE, marking a significant milestone in the Middle East’s carbon capture and storage (CCS) efforts. This certification supports ADNOC’s ambition to reach net zero by 2045 and the UAE’s Net Zero 2050 Strategy, highlighting the region’s commitment to climate action and sustainable energy solutions. DNV, the independent energy expert and assurance provider, has certified the feasibility for CO2 storage of ADNOC’s West Aquifer site in the UAE, marking a significant step in the region’s efforts toward carbon capture and storage (CCS). This certification supports the decarbonisation of the Ruwais industrial site and forms a key part of ADNOC’s broader CCS ambitions, which align with the UAE’s strategy to reach Net Zero by 2050.
Santiago Blanco, Executive Vice President & Regional Director Southern Europe, Middle East, Latin America and Africa, Energy Systems at DNV, commented: “Certifying the West Aquifer CO2 storage site is an important milestone, not just for ADNOC but for the region’s commitment to addressing climate challenges. This project serves as a tangible step toward meeting the UAE’s Net Zero goals and highlights the vital role that CCS will play in shaping a sustainable energy future.”
According to DNV’s 2024 Energy Transition Outlook, the global energy transition is accelerating, with significant investments in CCS technologies expected to play a crucial role in reducing greenhouse gas emissions. The report highlights that CCS is essential for achieving net-zero targets, particularly in hard-to-abate sectors.
Hanan Balalaa, ADNOC Senior Vice President for New Energies, said: “The certification of ADNOC’s West Aquifer site by DNV builds on our track record of successful deployment of carbon capture across Abu Dhabi and our global leadership in this critical decarbonisation solution. We will continue to work with our partners and customers to develop and scale up this technology as we aim to expand our carbon capture capacity to 10 million tpy by 2030.”
This certification underscores the importance of independent verification in ensuring that industry best practices are followed. DNV’s expertise in rigorous assessment processes, including due diligence across all technical aspects, helps to ensure that the site is equipped for safe and effective CO2 storage.
November/December 2024
18 - 20 February 2025
Subsea Expo Aberdeen, UK https://www.subseaexpo.com/
4 - 6 March 2025
SPE/IADC International Drilling Conference and Exhibition
Offshore Technology Conference (OTC) 2025 Houston, USA https://2025.otcnet.org/
19 - 23 May 2025
29th World Gas Conference (WGC2025) Beijing, China www.wgc2025.com
2 - 5 September 2025
SPE Offshore Europe 2025 Aberdeen, Scotland https://www.offshore-europe.co.uk/engb.html
Web news highlights
Ì Prospex Energy announces progress on Viura-1B well testing onshore Spain
Ì Reuters: Exxon executive says US oil firms unlikely to ‘drill, baby, drill’ under Trump
Ì Glamox wins smart lighting contracts for new North Sea platforms
Ì DeepOcean awarded eight year IMR contract with Equinor
Ì DUG and PetroVision sign collaborative agreement for seismic data processing solutions
To read more about these stories, and for more event listings, visit:
www.oilfieldtechnology.com
Golak Patnaik, Principal Analyst, Asia Pacific Upstream Research, Wood Mackenzie, looks back at 2024’s upstream highlights for the Asia Pacific region, revealing the distinct dynamics at play in its varied oil and gas markets.
Asia Pacific remains a diverse hub for upstream oil and gas activities, characterised by varied exploration and development projects, strategic mergers and acquisitions (M&A), and evolving licensing rounds.
This article provides a comprehensive overview of upstream oil and gas activities in the region so far this year, focusing on four key parameters – exploration, field development, M&A and licensing rounds –across Southeast Asia, Australasia and the Indian subcontinent.
Southeast Asia: balancing exploration and development
In Southeast Asia, 2023 was a standout year, with material discoveries in Malaysia and Indonesia reinvigorating interest in key basins. With some of the largest finds of the year, it signalled that the region was not as mature as many thought, and there was still considerable upside left to find.
Although 2024 has not been quite as blockbuster by comparison, it has still revealed new finds across the region. In Indonesia, exploration primarily focused on the North Sumatra, South Sumatra, East Java, Tomori, and Salawati basins. The biggest find of the year to date has been Mubadala-operated Tangkulo gas discovery in the emerging deepwater
North Sumatra play. Next up is the key appraisal of the giant Layaran find from 2023.
Exploration drilling in Malaysia’s Sarawak, Sabah and Malay basins resulted in a number of discoveries, but unlike last year, where most of the finds were in Sarawak, this year all the finds – most notably the Bunga Aster and Bekok Deep fields – have been made in the mature Malay basin.
In Vietnam, Eni’s long awaited Sao Truc wildcat in the frontier Phu Kanh basin was unsuccessful. However, Murphy Oil has plans to drill two wells in the Cuu Long basin near its under-development Lac Da Vang oil field, which could add commercial volumes for tie-in.
Also oil-focused was Valeura Energy’s drilling in Thailand’s Pattani basin, resulting in the small Nong Yao D and Wassana North discoveries.
Recent exploration successes have generated interest from exploration and production operators, and governments and regulators are keen to capitalise on this with new licensing rounds. To this end, Malaysia has offered five exploration blocks in the frontier areas of Langkasuka and Eastern Sabah. The country is also offering discovered resources opportunities.
Production began on several key Malaysian gas projects, including TotalEnergies’ Jerun, PETRONAS Carigali-operated Kasawari and the Hessoperated Bunga Teratai.
Development activities in Indonesia include the Jadestone-operated Akatara gas field and the Pertamina Hulu Energi-operated Titi oilfield, both of which were brought onstream. Genting has begun construction on the 1.2 million tpy FLNG facility that will receive its gas supply from the Kasuri PSC, which includes three gas fields: Asap, Kido, and Merah (AKM).
On a far bigger and more consequential scale, Eni had its plan of development for four deepwater gas fields in the Kutei basin approved by the authorities. This includes the multi-trillion f3, Geng North field, which was only discovered in September 2023. Eni is aiming to set new speed records for the development of deepwater gas both in Indonesia and further afield.
After a wait of over a decade, state NOC PetroVietnam and its partners sanctioned the development of US$3.2 billion ‘Block B’ gas project in Vietnam’s Malay basin.
Valeura started production at the Nong Yao C field in Thailand’s Pattani basin.
M&A activities in Southeast Asia generated over US$1.6 billion of deal-spend in 1H24, with the most notable deals being TotalEnergies’ acquisition of SapuraOMV’s assets in Malaysia and then divesting its interests in Brunei to Hibiscus (Figure 1). The transactions align with TotalEnergies strategy to monetise mature assets and focus on gas production growth from low-cost and low emission assets.
Australasia: energy security and sustainability
Exploration drilling has been subdued across the region in recent years, in part due to strict environment and emission guidelines, and this is reflected in rather low-key results in 2024. In Australia, key exploration wells like INPEX’s Basset Deep-1 in the Browse basin were dry, although
there continued to be small gas discoveries made in the Perth basin, one of the areas of Western Australia that is still seeing regular drilling.
In New Zealand a new government is reversing the previous administration’s ban on offshore oil and gas exploration, in place since 2018. Falling gas production and reserves has led to severe gas shortages and a spike in energy prices, prompting the government’s decision to review energy policy and the role of gas in the energy mix.
Exploration activities in Papua New Guinea also began to gather momentum after a dormant period with the news that PETRONAS was acquiring a 50% interest in the TotalEnergies-operated deepwater exploration block PPL 576. The block holds the large Mailu prospect, which is planned to be drilled in 2025, the country’s first deepwater well.
On the field development front, work continued on key large gas fields needed to backfill LNG projects, such as Santos’ Barossa field, due onstream in late-2025, and Woodside’s Scarborough, due onstream in 2026. On a smaller scale, Beach Energy fired-up its Enterprise gas and condensate field in the Otway basin, but unfortunately pressure levels were lower than expected and reserves on the field have been downgraded. Woodside also took the final investment decision (FID) for on its Lambert West field, a subsea gas development in the North Carnarvon basin.
Like its E&A drilling, Australia’s licensing activities have seen steep declines in recent years, with no awards in 2023 and limited interest in the 2022 licensing round. However, the government did award offshore exploration acreage to ExxonMobil and Beach Energy on the east coast and to Chevron, INPEX, Melbana and Woodside on the west coast. Additionally, 10 CCS exploration permits were put up on offer.
On the M&A front, the market in Australia was more muted than a rather frenetic 2023, but investors’ appetite for quality Australian gas assets
remains strong. Japan’s LNG giant JERA acquired a 15.1% interest in the Woodside-operated Scarborough field in February (Figure 1).
Indian subcontinent: looking for a licensing renaissance
Growing energy demand and shrinking production are driving governments in the Indian sub-continent towards offering exploration licences with lucrative fiscal incentives and higher investor returns compared to their peers in Southeast Asia and Australasia (Figure 2).
India continues to refine its licensing approach to attract investment and enhance production. In 2019, the government enabled previously no-go areas to be offered for hydrocarbon exploration. Since then, there have been expressions of interest for significant areas in the OALP-IX and OALP-X bid rounds. The government has also tabled a bill for an amendment to the Oilfields (Regulation and Development) Act 1948 to address the long-standing demands from IOCs for fiscal stability and improved business conditions.
In a similar vein the government of Bangladesh approved the new Offshore Model Production Sharing Contract, which provides revised gas pricing as well as enhanced cost recovery and profit sharing in favour of the contractor. With that clarified, it then launched in March a new offshore licensing round, offering nine shallow water and 15 deepwater blocks. We understand these have attracted the interest of Majors, Large Caps and regional NOCs. However, ongoing political instability may deter companies from participating in the round.
Pakistan’s offshore areas have remained largely unexplored and have seen limited success when drilled. However, with enhanced fiscal terms, these areas are expected to attract investment during another upcoming bid round, focusing on attracting interest to the shallow-water and deepwater areas of the Indus basin.
In 2024 exploration drilling continued to focus on the proven onshore areas of the Indus and Potwar basins. The focus on these established regions reflects a strategy of maximising returns from known reserves and quick tie-ins to existing infrastructure.
In India, Reliance’s ultra-deepwater exploration well UD-1 in the Krishna-Godavari basin turned out to be a dry hole. However, the state-run oil and gas explorer ONGC did make some deepwater discoveries in the Mahanadi and Cauvery basins. Despite these successes, the development of deepwater fields remains challenging and we understand ONGC is looking to partner with the Majors for technical support.
Oil production from ONGC’s long-delayed deepwater fields in KG-DWN-98/2 started in January. However, the full potential of the fields has yet to be realised, due to a delay in the completion of the offshore processing facility, which is restricting production.
Over on India’s western coast, production is slated to increase with the ongoing Bombay High Redevelopment Phase-V project and the development of satellite fields. Other ongoing activities include the implementation of enhanced oil recovery (EOR) to arrest the production decline in older fields.
Nepal also featured by spudding its first exploration well in 35 years in partnership with China’s CNPC. This move could open new exploration opportunities in Nepal, provided the results are positive. A licensing round was also launched, but the lack of any finds to date will likely restrict interest.
Conclusion
size (1 trillion ft3) deepwater (400 – 1500 m) gas field with a gas price of US$6/million ft3
Upstream activities across Asia Pacific reveal distinct regional dynamics. Southeast Asia stands out for its active exploration scene and dynamic gas market. Australasia while facing challenges in exploration, remains committed to field development for LNG backfill projects. The Indian subcontinent has a mix of activities, but with a real push by governments to drive new exploration via licensing rounds.
Figure 1. Deal spend by country in 2023 and 1H24. Source: Wood Mackenzie – Mergers and Acquisition Tool .
Figure 2. Government share and investor IRR for major regimes. Source: Wood Mackenzie – Fiscal Benchmarking Tool. The comparison assumes medium
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Danny Salinas, Federico Mezzatesta, and Jessica Stump, NOV, explain how using a high-capacity, intuitive shaker can enhance drilling performance and efficiency.
As drilling operations continue to increase in scale, speed, and complexity, drillers are expected to maximise efficiency and enhance crew safety while minimising costs, time, waste, and environmental impact. Service companies have developed new drilling equipment to help drillers meet these goals; however, the shale shaker, a vital element of the drilling operation’s solids control, has not changed much in the past three decades.
Shale shakers, the first line of defence in removing drill cuttings from the drilling fluids/mud, play a pivotal role in maintaining the integrity of the drilling fluid properties, enhancing equipment longevity, and ensuring operational efficiency. To meet today’s drilling demands, shakers must process more drilling fluids faster, safer, and more efficiently. Yet current shakers struggle to deliver drier cuttings and often lose more drilling fluids, which slows the overall drilling process, raises operational and disposal costs, and increases the operation’s carbon footprint.
Figure 1. NOV designed the intuitive, single-deck Alpha shaker to process more fluids and meet today’s drilling demands.
NOV developed the Brandt™ Alpha™ shaker, the first novel shale shaker in nearly 30 years, to resolve the decades-long challenges in solids control, deliver drier cuttings and retain more drilling fluids. With a higher fluid processing throughput, less fluid lost with cuttings, and a lower overall carbon footprint, this high-performance, single-deck shaker has proven to enable safer, more efficient, and sustainable drilling operations across the US.
Shaking up the market
Before going back to the drawing board, NOV canvassed the industry, speaking with operators and drilling contractors to identify their pain points in terms of performance, safety, efficiency, and maintenance.
Many customers expressed similar frustrations. For instance, the low handling capacities of current shakers slow the overall drilling process. They also did not get the drill cuttings dry enough, which increased disposal costs, required larger volumes of replacement fluids, and increased the drilling operation’s carbon footprint. Moreover, the customers considered ease of operation and maintenance a crucial need.
Guided by these insights, NOV set out to address all the operational bottlenecks and engineer the shortcomings out of the new shaker. A key focus was enhancing the linear motion of the single-deck shaker. This motion enables the shaker to exert more control over the vibration patterns, improving the efficiency of the separation process. This results in drier cuttings and better retention of drilling fluids without sacrificing the shaker’s capacity.
For more than two years, NOV designed and rigorously tested the Alpha at its facility in Conroe, Texas. The Alpha shaker underwent field trials on multiple land rigs in 2022 before its commercial release in 2023 across several fields in the US.
Higher processing capacity
The Alpha shaker processes cuttings at up to 40% higher capacity than any other single-deck shaker on the market. The performance gains in the shaker extend to other processes, enhancing overall efficiency.
Fewer cuttings in the return fluid improve the mud system’s efficacy. Additionally, pumping a cleaner mud back downhole reduces the risk of solids-induced erosion and wear of drill pipe, drill bits, and other downhole tools. Meanwhile, the ability to process more drilling fluids enables an operator to screen finer
and maintain better control over drill cuttings, which can lead to an increased rate of penetration (ROP) and reduced drilling fluid costs.
An Alpha shaker runs efficiently and reliably on small horsepower motors, providing greater processing capacity with lower fuel demands. While most land rigs have a footprint for three shakers, the Alpha’s increased capacity means that some drilling applications can run efficiently on just two units, with the third on standby. This not only reduces both power consumption and carbon emissions but also provides flexibility during unplanned shutdowns or maintenance activities. If one unit goes offline, the standby unit can be brought online to maintain fluid processing capacity and keep the drilling operation running at peak capacity.
In a trial conducted in the Midland Basin, an independent drilling contractor replaced two Brandt King Cobra shakers with two new Alpha shakers while drilling the Wolfcamp A/D and Sprayberry wells. The high-capacity shakers handled 900 gal./min. – all the flow – with various mud types without issues.
For the Sprayberry and Wolfcamp A wells, drilled open loop with water-based mud (WBM), the new shakers efficiently kept solids out of the mud system, reducing the number of times the company had to dump and dilute, as well as the volume of lube needed. In fact, there was an average of 37% less volume dumped per well. After each well, the rig pits had less buildup, which reduced cleaning time.
As for the Wolfcamp D well, drilled with oil-based mud (OBM), the drilling company was able to screen finer, switching from API 170 to API 230 screens. Screening finer resulted in cleaner mud and less diesel dilution. The driller also managed to displace to OBM without stopping to circulate, saving six hours of downtime.
Using two high-capacity Alpha shakers saved the operator nearly US$45 000. By delivering drier cuttings, the shakers retained more drilling fluids and reduced dilution costs. A 7% decrease in the volume of lube used saved the operator US$14 685 per pad, while a 27% reduction in diesel usage saved US$11 715 per pad. Additionally, reduced downtime contributed to US$13 750 in savings per pad, while the use of fewer screens saved US$4700 per pad. Impressed by the trial performance and cost savings, the drilling company purchased the Alpha shakers.
Meanwhile, in Colorado’s Piceance Basin, a driller deployed six Alpha shakers – three as flowline shakers and three as drying shakers – a first for these units. The company also ran six competitor shakers on an adjacent rig. The Alpha shakers’ superior cuttings removal and drying capabilities proved to be a significant advantage. By delivering drier cuttings, the high-capacity shakers substantially reduced waste volumes, minimising the need for additional mix-off material to dry disposal loads to meet environmental requirements.
This efficiency translated to tangible cost savings. After just six wells, the drilling company saved about US$78 000 in disposal costs. Notably, the Alpha shakers yielded 80% less waste than the competitor shaker, primarily due to reduced retention on cuttings (ROC) and less mixing material. The reduced waste also meant fewer haul-off trips and trucks on the road.
Drier cuttings
The Alpha shaker’s increased non-blanked open area enhances its ability to separate the fluid from the cuttings, producing considerably drier cuttings than legacy shaker systems. Drier cuttings translate to lower waste volumes and fewer waste hauloff trips. Since the new shaker retains more drilling fluid, less replacement fluid is required for the operation. Less waste and
Figure 2. By delivering drier cuttings and retaining more drilling fluids, the Alpha shaker enables operators and drilling contractors to lower costs and minimise the environmental impact of their operations.
Over 60 years of engineering expertise combined with the knowledge and experience of our specialists and strategic partnerships in the process industry.
replacement fluids mean fewer trips to and from the drill site and fewer trucks on the road, which minimises the drilling operation’s environmental impact.
Shakers struggle in Oklahoma’s Anadarko Basin because of the sticky, heavy clay, resulting in low throughput. A driller installed an Alpha shaker to increase fluid processing rates and boost drilling efficiency. The rig’s current shakers could not increase throughput without producing wetter cuttings and lowering fluid recovery.
During the maximum flow test – 708 gal./min. – the Alpha shaker processed all the drilling fluids with several hundred gallons of spare capacity. While most shakers sacrifice drier cuttings for higher capacities, Alpha alone had the same 12 - 13% ROC as when the fluids were spread amongst the three operating shakers. Retaining more drilling fluids improves efficiency and reduces dilution costs and disposal trips, which, in turn, lowers the carbon footprint and cost of the drilling operation. These field tests convinced the driller the Alpha shaker could meet the demands of faster drilling without sacrificing performance.
Solids removal efficiency
Solids removal efficiency is a critical aspect of a drilling operation, as it helps maintain optimal mud/drilling fluid properties, reduce waste, and improve overall operational efficiency and performance. As mentioned earlier, by processing more drilling fluids, an operator can screen finer and maintain better control over the drill cuttings, leading to increased ROP and reduced costs. The Alpha shaker screen’s Premium X-Tended Life (PXL) and Rectangular Heavy Duty (RHD) cloths combine durability with effective cuttings removal, resulting in drier cuttings, cleaner drilling fluid, and lower disposal costs.
In the Utica Basin in Ohio, a driller’s previous shakers could only manage flow using API 170 screens without losing fluid. Three Alpha shakers not only processed the higher flow rate efficiently but also enabled the company to screen finer with API 200 screens for the first time. Using the finer PXL API mesh reduced screen cost per foot drilled by 61.4% and lowered dilution.
In addition, the drier cuttings lowered the waste volumes and the amount of mix-off material, such as lime, needed to dry the disposal loads to meet Ohio’s environmental regulations. As a result, the company needed fewer haul-off trips from the wellsite, reducing fuel consumption and carbon emissions. By upgrading to the Alpha shakers and screens, the driller has saved more than US$108 600 due to the savings from screens, diesel, and lime.
Ease of operation and maintenance
The Alpha shaker’s streamlined design allows for safer and more intuitive operation and maintenance at the rig site. By running at reduced noise levels – 72.1 dBA – the shaker protects the rig crew while minimising disruption to surrounding communities.
NOV designed the Alpha shaker with a novice rig hand in mind, acknowledging the varying levels of experience among rig personnel and the need for quick task execution with minimal training.
Its simple, pneumatic screen clamping system ensures easy screen access from one safe location, while also preventing solids bypass around the screen. Front-loaded, lightweight screens enable the crew member to maintain a more ergonomic position throughout the installation and removal processes, eliminating bending, climbing, or reaching into the shaker. Moreover, because there are no bolts or wedges, screens can be easily installed or removed without hammers or other tools. In field trials, rig crews have reported screen changes of less than two minutes.
Conclusion
As the first major innovation in single-deck shakers in nearly three decades, the Alpha shaker sets the standard for future advancements in solids control technology. This high-capacity, intuitive shaker helps operators and drilling contractors enhance safety, boost efficiency, lower operating costs, and minimise the environmental impact of their increasingly demanding operations.
In addition to meeting today’s drilling demands, the Alpha shaker is designed to integrate into automated rig systems of the future. NOV’s WellSite Services design team collaborated with the real-time drilling instrumentation team of the company’s M/D Totco group to develop seamless, plug-and-play connectivity with the Shaker Hawk™ remote monitoring and automation platform.
By enabling real-time data analytics, predictive maintenance, and remote expertise, the system optimises shaker performance, reducing non-productive time while empowering safer, more sustainable drilling operations.
Figure 3. Front-loaded, lightweight screens enhance safety by eliminating bending, climbing, or reaching into the shaker.
Figure 4. The Alpha shaker screen’s PXL and RHD cloths combine durability with effective cuttings removal, resulting in drier cuttings, cleaner drilling fluid, and lower disposal costs.
Driving forward, digitally
Lucas Rocha, President in Middle East and Asia, Tenaris, shares how customer collaboration, strengthened by digital transformation, is reshaping the OCTG and line pipe supply chain in the UAE.
Over the past decade, one of the most significant transformations in upstream operations has been driven by the power of collaboration and digitalisation. By partnering with customers throughout each step of their drilling projects, companies can transform the tubular supply chain in the oil and gas industry. For example, Tenaris is making waves with its Rig Direct® mill-to-well service model. Tenaris is expanding its service offering in the UAE through Rig Direct, using expertise and technological solutions to enhance ADNOC’s operations. With these services available locally, Tenaris’s approach has been thoroughly tested worldwide and verified to meet the regional needs. ADNOC has taken the lead as a regional pioneer in adopting these services since 2017, further strengthening
a partnership that has spanned over 25 years and boosting operational efficiency in the local energy industry.
Incorporating new digital solutions can simplify every aspect of customers’ drilling operations, with safety and quality at the core. By capturing and processing more and better data, companies can foster real-time monitoring and data-driven decision-making to support well integrity in a fast-paced market where optimisation is key.
Reimagining the tubular supply chain
The Rig Direct model adds value throughout the whole cycle. During well planning, technical experts actively engage in drilling team discussions, assist in string design, and share the latest trends in technologies and materials used in similar environments worldwide. This approach optimises product selection to maximise performance while streamlining costs.
Through supply chain integration, pipe production and accessory management are adapted to the operators’ drilling schedules, optimising timing and delivery. By leveraging its global manufacturing capabilities, Tenaris can respond quickly due to the proximity of its production and service facilities, leading to shorter lead times and more responsive services.
In the UAE, Tenaris has recently inaugurated a 200 000 m2 industrial complex in Abu Dhabi that features a state-of-the-art OCTG threading facility and a pipe service yard for storage, inspection, and preparation of tubulars.
Through Rig Direct, ADNOC has reduced inventory obsolescence, working capital costs, and total cost of ownership. OCTG components
are delivered directly to the well site, minimising the need for extended storage at yards. It is also environmentally beneficial, significantly reducing the number of manufactured pipes and the truck trips needed to deliver them to the rig site.
Today Tenaris is serving more than 76 rigs through Rig Direct in the UAE, ensuring each customer has the right products, when and where they are needed. This integrated approach allows ADNOC to focus on its business, while Tenaris takes care of the pipe.
A digital identity for every pipe
An essential component and enabler for the Rig Direct model is PipeTracer® technology. This digital identification system ensures pipe-by-pipe identification, with full access to its physical and technical specifications, across the manufacturing process, supply chain management, and on-site operations, now also including the actual running in the UAE.
PipeTracer technology facilitates real-time communication between customers and Tenaris field service representatives, enabling online visualisation of critical stages while capturing and storing valuable data throughout the entire process.
As an integrated OCTG manufacturer, traceability goes back to the raw material at Tenaris. Each pipe is measured and weighed within the required tolerances at the mill. Pipes and thread protectors include QR codes linking to the complete manufacturing history of each product, technical specifications, and any related certification.
After unloading the pipes at the well site, Tenaris personnel use the PipeTracer online application, accessible from mobile phones or tablets, to scan the QR codes on each product and create digital tallies, avoiding the need for manual measurements, reducing pipe handling, improving accuracy, and simplifying operations.
Before the use of PipeTracer technology, operators typically required a crew of six to eight people to receive around 20 trucks, measure each pipe on-site, and manually record the measurements. This time-consuming process, which would take at least four to five hours, has been dramatically optimised. Now, one or two technicians can complete the task by simply scanning QR codes.
Simplicity, delivered
Leveraging years of field experience, Tenaris took on the challenge of further simplifying operations for its customers by delivering pipes directly to the rig site, ready-to-be-run, through its RunReady™ service.
In the UAE, the RunReady service covers a wide array of tasks such as ID measurement, removal of protectors, visual inspection of the pipe body and connections, application of anticorrosive wax, measurement of pipe length, and pre-assembly of centralisers and other accessories.
A key aspect of the RunReady service is that the thread compound on the pipes does not need to be replaced at the rig site. During manufacturing, a specialised thread compound is applied that avoids the need to remove storage compounds and add running compounds, as it fulfils both functions. While Tenaris’s Dopeless® technology is used extensively in offshore and other complex operations as a coating solution, the company has also developed other RunReady coatings and compounds for other applications.
This approach has significantly contributed to time savings, reduced man-hours, and improved job site efficiency. From an environmental standpoint, it has also ensured a lower operational footprint, with less water used and less waste generated at the well site.
Another great addition has been the drift-on-the-fly. In line with quality procedures, each joint of pipe is drifted at the mill to ensure the inner diameters are correct, but companies usually repeat this process upon delivery at the rig site. Tenaris now equips casing crews with specially designed drifts that allow them to drift the pipe while
Figure 1. Tenaris is expanding its service offering in the UAE through Rig Direct®, using expertise and technological solutions to enhance ADNOC’s operations.
Figure 2. Today Tenaris is serving more than 76 rigs through Rig Direct® in the UAE.
it is being raised on the catwalk, saving valuable time during rig preparation procedures.
Tenaris has optimised its supply chain through its field service teams, PipeTracer technology, and the use of specially designed drifts, proprietary coatings, and compounds. By the time the pipes reach the customer, the tally has been completed, the running compound applied, and the pipes drifted.
In short, with the RunReady service, pipes are delivered ready to be run at the rig site. With Tenaris managing time-consuming delivery and preparation processes, operators have no need for special crews to handle these tasks at the rig site. This not only reduces pipe handling and the number of personnel in critical areas, but also lowers the risk of injuries, enhances safety, and cuts costs.
Data at the service of well integrity
Having addressed supply chain integration, end-to-end traceability, and optimised on-site operations, exploring how the digital revolution can maximise the lifecycle of pipe strings in the well emerged as the natural next frontier.
WISer™ is the most recent concept within the Tenaris Rig Direct mill-to-well model: a suite of digital solutions designed to support well integrity while enhancing the safety, efficiency, and reliability of drilling operations. The digital suite includes the iRun Casing® tool, and an on-site torque turn monitoring service, while PipeTracer technology is also a key enabler.
Used in over 1100 wells across the US since 2021, the iRun Casing digital solution has become a valuable tool in this quest. The technology provides real-time monitoring of casing installation, connecting directly to the drilling rig and processing large volumes of data.
This cloud-based monitoring tool is now available in the UAE, minimising the risk of lost lateral length and the associated lost production while preventing costly accessibility issues caused by fatigue damage, buckling, overtorque, or stuck pipes.
One of its most valued benefits is the reduction of non-productive time by providing guidance on the optimal point to begin rotating casing to alleviate axial drag. It also reduces the engineering hours required for torque and drag workflow automation, streamlining the entire process. With direct data access, best practices across rigs are identified, enabling knowledge transfer – a great example of how collaboration and digital transformation are driving progress in the UAE.
Knowledge and data analytics
Another key component of WISer is on-site torque turn monitoring. This service includes the collection and analysis of real-time torque data at the well by field services experts using Tenaris’s advanced equipment, enhancing the reliability of connection make-up, reducing the risk of errors, and improving the overall integrity of the assembly. The system also improves operational efficiency and quality control, ensuring that casing installation meets the highest standards.
The torque monitoring service has significantly simplified the process for operators, who previously needed to outsource torque measurements and analysis of make-up graphs to third parties to assess the work of the running services provider. This integration means one less person on the rig floor, contributing to a safer working environment.
By combining the knowledge gained during casing installation with real-time data analytics from connection makeup monitoring, the torque monitoring service improves decision-making and enhances the consistency and reliability of casing crew operations.
field service representatives.
200 000 m2
Driving pipeline innovation
Tenaris has recently introduced its One Line™ project management service for integrating pipeline construction activities connected with the pipe, drawing on experience with Rig Direct and building on the know-how gained from servicing over 350 onshore and offshore pipeline projects worldwide.
One Line integrates a full array of services from the design phase through execution, optimising efficiency across the entire project supply chain. This leads to shorter delivery times, consistently highquality standards, lower logistical costs, and a reduced environmental footprint.
Following the integration of Shawcor in 2023, Tenaris has consolidated a unique portfolio of coating solutions to better support its line pipe customers for both offshore and onshore projects. This addition has also expanded Tenaris’s industrial footprint in the Middle East, with the addition of a specialised pipe coating facility in Ras Al Khaimah.
The Ras Al Khaimah facility has coated more than 6500 km of pipes in the region, including some of the most prestigious projects for major NOCs and IOCs. The plant offers anti-corrosion (FBE, DLFBE, 3LPE, 3LPP), concrete weight coatings, anode installation, and internal flow-efficiency coatings for domestic and international projects and has become a hub for the GCC and further afield in the Middle East.
Figure 3. PipeTracer® technology facilitates real-time communication between customers and Tenaris
Figure 4. In the UAE, Tenaris as a
industrial complex in Abu Dhabi that features a state-of-the-art OCTG threading facility and a pipe service yard.
People are the key to everything
With a new name and its guiding vision to “see things differently”, Viridien (formerly CGG) focuses on human ingenuity to usher in a bright future across multiple sectors.
The oil and gas industry has seen rapidly changing trends over the last decade, driven as ever by the latest developments in technology and tapping into artificial intelligence (AI) and high-performance computing (HPC) to become more efficient. Energy technology companies are at the forefront of these innovations, but the skills and tools they have developed to serve their core clients are proving to have applications in a range of industries.
One such technology company, CGG, became Viridien this year, a new brand that builds upon a 90+ year legacy of innovation in geoscience to support oil and gas discovery and development. Although its focus remains primarily on exploration and production, the company recently started bringing the benefits of geoscience and data science to other industries. Peter Whiting, EVP Geoscience, talks about Viridien’s history and future, the decision to change its name, and the importance of developing people, who are at the heart of its success.
“The geoscience business is exciting and varied, covering a wide range of data, from seismic, satellite imagery, geology and geophysics to engineering, drilling and production. Enriching this data through our sophisticated algorithms allows clients to solve their challenges and work in an efficient, safe and successful manner,” he says. “This is true for the oil and gas, energy transition, and other science-reliant markets that we work with.”
Expanding the reach of geoscience and data science
Peter explains that the company had been thinking for some time about rebranding, particularly after it left the seismic acquisition market in 2018, which was quite a focus change that differentiated it from other geophysical companies. While the core of the business is still the oil and gas sector, the company has been moving into other areas, like mineral exploration and carbon storage as part of its commitment to support the energy transition, as well as addressing client challenges in HPC, data transformation, and infrastructure monitoring. To reflect this repositioning, it was decided a new name was needed.
“It’s more about evolution than change,” Peter explains. “Obviously, we are all very proud of the CGG name, and the legacy of 90 years of service and innovation behind that. We are not changing our strategy towards oil and gas and are as fully committed as ever to research and development for that sector. In fact, our expertise and capabilities are more needed now than ever for oil and gas as the industry actively supports and successfully adapts to the energy transition. However, we are also keen to build on our skills to expand the company in other ways, while not detracting from our core business. The new name is about looking forward, with pride in where we have come from. The word Viridien is based on Latin, meaning ‘green and drawn from its roots’;
looking ahead to future developments while still drawing on our long history.
“We see this name as a way to demonstrate our new direction and differentiate the company while stressing we are committed to oil and gas, which still makes up about 90% of our business. We’re the same company, but definitely adding to what we are.”
Delivering customer-focused solutions from peopledriven technology
Peter believes it is important to understand customers and their needs in order to discover what technologies will be most useful to them. “You can’t innovate and create new technology without the right people, and you also can’t understand clients or deliver excellent service without them. You have to really get to know the client and work out exactly what their problems are; then you need people who can solve these problems. In technology, it’s relatively simple to get a prototype, or 80% solution, but few people can fine-tune that to create a high-end commercial product. In addition, you need to provide an excellent service, which is delivered on time and without mistakes,” he explains.
Having people with the right focus and attitude is vital, as is developing a culture that allows them to thrive. Peter admits it is sometimes challenging to find such employees and explains how Viridien strives to build ever stronger teams, with staff encouraged to recommend new people to join the company. “It’s not just intelligence we’re looking for,” he continues. “We need people with a real passion and ability to work together for the technology and service we’re developing. We must manage them well and give them a good culture to work in, help them develop their talents, and offer them good career opportunities. It’s important to get the best people possible and keep improving their skillsets.”
Remaining at the forefront of technology with a diverse portfolio of offerings
“Staying at the edge of technical advancements really goes back to people,” says Peter. “People who are open and curious and then can solve real problems leading to positive business outcomes, while having the freedom to think broadly.” To this end, Viridien has semi-independent R&D groups located throughout the world, making up about 10% of its total employees. Each location researches a range of local problems and ideas, but they know what is going on elsewhere in the world. When working on a new product, these groups work closely with the production teams, to ensure they understand client needs.
Peter stresses the importance of recognising far-reaching technical innovation. “If a team comes up with a good idea and product, we make sure we recognise this, which could include presenting them with an award,” he adds. “The outcome must be a product that not only solves a problem for a particular client but can be sold to multiple customers. This can mean that, rather than improving the standard approach to something, we find a completely new process that is more beneficial. Our tag line is ‘See Things Differently’, and that resonates within the company, as we try to develop new ways of doing things.”
Technology, innovation and differentiation are the main thrusts of Viridien’s vision. A vital component of this is the company’s own HPC capabilities, giving scientists and technologists the freedom to test new ideas and hypotheses at no extra cost. “The misleading idea that cloud computing is cheaper and more expandable has taken over – but you have to pay every time you want to run an idea,” Peter explains. “Not being able to try out ideas and new technology on different data can impinge on innovation. By having our own supercomputing systems, we can achieve more.
“We’ve always designed our own HPC to our advantage. Our systems use only what is needed to get the job done. That might sound cheap,
Figure 1. FWI imaging (here shown co-rendered with velocity model) provides vital subsurface detail for better assessment of carbon storage risks. Image source: Viridien Earth Data.
Figure 2. Designed with efficiency and sustainability in mind, Viridien’s new UK HPC Hub sets new standards for computational power. Image source: Viridien.
For 50 years, Wild Well has been proud to stand alongside the oil and gas industry, providing unwavering support and expertise when it matters most.
Our legacy is built on trust, innovation, and a steadfast commitment to safety-values that have guided us from day one. We're honored to have earned the confidence of operators around the world, and as we celebrate this milestone, we remain dedicated to delivering the same level of excellence that has defined our work since 1975.
Our promise is to continue evolving, always upholding the high standards that make Wild Well a name the industry relies on.
but it’s actually being efficient. We customise hardware to do each job in the most cost-effective way, while software writers work with hardware experts to ensure an algorithm operates efficiently on a given machine. We like to use new technologies and options in software to minimise our overall costs.
“AI and machine learning (ML) are now coming into the picture and are other ways to increase efficiency by reducing either people hours or computer time,” he adds. “We’re using it in many different areas; a good example is our new Data Hub digital transformation business.” Many companies have vast volumes of geoscience data saved in variable formats and stored in many types of databases. Using Data Hub, these data can be ingested, curated, contextualised and enriched, with AI and ML being used extensively in this process. Clients can get the most from their updated legacy data to gain new insights for ongoing and planned geoscientific investigations.
Dual-use technology for energy transition and environmental initiatives
Peter explains that, while many of their technologies were initially developed for the oil and gas sector, they are easily transferred into other parts of the energy business. The majority of Data Hub clients, for example, are in oil and gas, but the team has recently undertaken a successful project with a mining company. “We also have a satellite mapping group and a multiphysics imaging group, both of which work with mining and geothermal companies as well as oil and gas.
“We are also actively involved in carbon storage, not just with oil companies but with other industrial players,” he adds. “The value we can offer in this area is in seismic imaging and monitoring; the subsurface must be well imaged and understood to minimise risks like compromised seal integrity and hazardous injection strategies. If we can give companies actionable information to help them plan and execute their project, they will have to drill less and there will be a lower chance of failure. It’s the same in oil and gas; more and better information means less drilling, and that means a lower carbon footprint. We believe if we can provide really good information, the world can do what it needs to do to provide energy with less negative impact.”
As a company, Viridien puts a lot of effort into reducing its own emissions. For example, its very large data centres in both the UK and the US run on fully renewable green energy. “We want to help the world get the energy it needs at a reasonable price, and with the least amount of environmental impact.”
Looking forward to the future
“I think we have a really good base with the type of company we are, the people we hire and how we organise and develop them, so we’ll continue with that as the years go on,” he says. “There is still a lot of technical innovation work to do in the oil and gas domain. The subsurface images that are being created now are phenomenal, you would not have believed them possible ten years ago – but there is still plenty of scope for improvement. We also continue to research advancements in what might be called ‘normal’ processing, like de-ghosting, de-multiple and de-noise where much progress is being made.”
Within Viridien’s core subsurface imaging business, Peter believes full-waveform inversion (FWI) has an exciting future. “The data is so much more accurate than it was in the past. Within a few years, we will be extracting detailed subsurface information directly from the data itself, so oil companies will be able to get data-driven analysis of reservoir potential, size and volumes automatically using AI,” he explains. “That’s not going to put people out of jobs; we need new experts to run and monitor the automated algorithms, and AI is just a tool that helps the interpreter do a better job. FWI outputs are also being used for rock property and fluid definition, so companies will be able to predict what is in the reservoir with greater precision before they drill.”
As Peter has explained, Viridien is now moving into other industries alongside oil and gas. He admits it is challenging to enter new business areas – but he finds it very exciting. “These new relationships take time; you have to listen to and understand a new customer so you can find beneficial ways to assist them and develop something that will be really impactful.”
“Another new sector involving the sensing and monitoring equipment part of our company is infrastructure monitoring, in which we put sensors on bridges and railways and other structures and earthworks to monitor stability,” he continues. “This is starting to grow, with contracts in Saudi Arabia, the US and France, and we are doing trials and building up trust.”
In addition to carbon storage and mining, Viridien has been developing alliances with other scientific industries including biotech, image rendering and materials science. Peter believes that the company’s HPC expertise and supercomputing power will be useful in these sectors to maximise business efficiency and support environmental and sustainability goals.
“The most exciting thing about Viridien is its strong technological base, coupled with the people and culture that we have. It’s a really good springboard for the future and that is what we will build on to serve our clients across a growing range of industries,” he concludes.
Figure 3. Geoscientists and data scientists explore geologic sources, sharing insights essential for Data Hub digital transformation solutions. Image source: Viridien.
Figure 4. Viridien HPC & Cloud Solutions drives scientific discovery, advanced simulations and transformative insights across life sciences. Image source: Viridien .
SEE THINGS DIFFERENTLY
Connor Docherty, SPM Oil & Gas, a Caterpillar company, highlights advances in durable pump consumables and how they promote greater operational efficiency.
ressure pumping operators face evolving challenges as they strive to minimise costs and optimise efficiency. Pump consumables’ longevity can have a positive impact on both operating expenses and non-productive time (NPT). Recent technological advancements have significantly extended the life of consumables compared to conventional components, particularly for valves and seats, which supports companies’ operational goals.
Pump consumables play a critical role in the hydraulic fracturing process. Conventional seats have approximately an 80 hour lifespan and require frequent maintenance. They are also prone to fatigue and potential failure under harsh site conditions involving higher pressures and extreme temperatures.
Fortunately, new materials and designs are now available that provide greater resistance to wear, cracking and washout – even in the most demanding conditions. Using more durable consumables can be an effective way to decrease maintenance frequency, lower replacement
costs and minimise NPT. Pressure pumpers can also reduce the labor costs associated with frequent seat pulling, potentially freeing up crew members to focus on higher-value tasks while enhancing safety.
High-performance pump consumables help streamline and simplify maintenance when service intervals are required, which helps reduce unplanned downtime, enhance operational efficiency and lower total cost of ownership (TCO).
Field-proven to last
The experience of an oilfield services company in Western Canada with multi-well pad operations demonstrates the positive impact long-lasting pump consumables can have on a project. The Montney and Duvernay plays in Canada subject hydraulic fracturing equipment to some of the most challenging fracing environments due to high pressures, high proppant volumes and extremely cold temperatures, which can range from - 5°C to - 30°C (23°F to - 22°F) in the winter.
Due to site characteristics and geological formations, the company routinely pumped high proppant volumes at high pressures, and 5000 t of sand per stage for offset wells – much higher than the typical range of 1200 – 1400 t. These practices led to above-average seat and valve erosion.
In an effort to increase efficiency and reduce NPT, the operator conducted a three-month field trial using advanced consumables on a pump, in this case, the SPM™ EdgeX Carbide Seat. The consumables were subjected to sub-zero temperatures (-20°C/-4°F), pressures up to 12 500 psi and produced water at 100 bpm. An engineering field assist team regularly monitored the high-performance components to compare wear and longevity to the company’s conventional pump consumables.
The advanced durability and design of the new consumables enabled the EdgeX Carbide Seat to reach a useful life of up to 515 hours, potentially increasing seat life by approximately 540% compared to the 80 hour life the company experienced with conventional seats.
Replacing valves and seats is one of the largest expenses an oilfield service operator incurs – and one of the most frustrating. Additionally, there are inherent safety risks involved with this important maintenance activity. Extending the longevity of pump consumables reduced frequent replacements and NPT, allowing the operator’s pumping rate to be maintained for much longer and considerably extending maintenance intervals compared to the consumables previously used.
Compatibility is also an important consideration when contemplating pump consumables options. The high-performance seats could be paired with any tapered fluid end and replaced in the field without special tools, which provided the pressure pumper flexibility. Additionally, the carbide-
reinforced seats protected high-wear areas while eliminating the typical installation error sensitivity encountered with other long-life seats, which can cost time and money.
The new valve’s design complemented the new seat to promote greater efficiencies. The high-performance valve optimises its performance when used with its carbide seat counterpart to wear deeper and last twice as long as standard valves without failure risk. A first-of-its-kind material provides exceptional erosion resistance and durability as well as high sand abrasion resistance with every stroke to achieve synergies that drive longer lifespan for both components. The standard 30° strike angle of the new valve maximises interchangeability, and its unique leg design ensures stability through all operating conditions, including high lift.
The extreme adverse temperature and pressure conditions oilfield companies encounter in Western Canada can cause consumables to become brittle and shatter. High-performance components specifically engineered with such harsh environments in mind can provide a competitive advantage by reducing NPT and costs.
Advancing fluid end life
Fluid end performance and longevity can be complemented by using highperformance consumables. With pressure pumping companies pushing their fleets to continuous duty standards, which can require pumps to operate for 20 hours a day for 20 days at a time or more, the consumables a company chooses can support the ability to meet such rigorous demands. The considerable cost of pump consumables causes pressure pumping operators to focus on reducing costs related to fluid end maintenance and downtime.
Previously, pressure pumping operations in the region’s extreme temperatures caused full carbide seats to shatter. Shattering typically makes the component vulnerable to particles striking and breaking the entire seat, causing a catastrophic failure that can damage the fluid end. As tungsten carbide seats are significantly more expensive than standard seats, a shattered seat is costly in more ways than one.
However, the SPM EdgeX Carbide Seat used in the field test resisted shattering as it strategically places tungsten carbide in key wear areas to provide enhanced wearability while also delivering the reliability and impact-resistance of steel. In conjunction with a broader maintenance programme, this advancement contributes to longer fluid end life and increased uptime in the field, which can positively impact a project’s economics.
New consumables support pressure pumping efficiency gains
The challenges oilfield service companies face today are leading them to re-evaluate their operations and explore new ways to streamline and reduce costs. Maintenance and unexpected NPT are known to affect pumping hours and profits, and approaches that can lower both can be worthwhile.
By doubling the life of valves and increasing seat longevity sixfold, high-performance consumables like EdgeX can significantly extend maintenance intervals to minimise pumping interruptions. Additionally, advanced materials that promote greater durability help protect fluid ends, which optimises uptime as well as OPEX and CAPEX. To maximise pressure pumping potential in today’s oilfields, high-performance pump consumables can deliver compelling advantages that support frack services companies’ objectives.
About the author
Connor Docherty is a Product Manager for fluid ends and pump consumable products. He is based in the Forth Worth, TX, US office and has worked at SPM Oil & Gas since 2018. After starting his career in the UK, he moved to the US and began working in R&D and engineering.
Figure 2. The extreme adverse temperature and pressure conditions in Western Canada can cause consumables to become brittle and shatter.
Figure 1. SMP EdgeX carbide seats can be replaced in the field with standard tooling, and feature a 30° strike angle for interchangeability.
www.worldpipelines.com
M a n a gi n g
m e r c a p t a n s
Jennifer
Knopf, Dr. Ulf W. Naatz, and Neil Lawrence Tobin, Vink Chemicals, discuss mercaptan removal strategies in the oil and gas industry and highlight a way to effectively manage and
control their presence.
N
umerous sulfur-containing compounds are present in oil and gas streams. Besides the most common and problematic contaminant, hydrogen sulfide (H2S), mercaptans (also known as thiols) are a significant issue in the oil and gas industry due to their toxicity and foul odour. These compounds cause hazards for workers and environmental pollution, as well as severe corrosion in pipelines and storage facilities. Mercaptans pose a particular risk in refineries, as they poison and deactivate the catalysts, which leads to significantly higher replacement and maintenance costs. Regulatory restrictions have been imposed on oil producers to decrease mercaptan emissions and allay air quality and the public health concerns. Mercaptans levels are closely monitored along the oil value chain process: with new climate disclosure regulations taking effect in various regions, the industry has been compelled to improve its emissions management strategies. This requires the adoption of advanced monitoring technologies and practices to minimise mercaptan emissions.
What are mercaptans?
Mercaptans are forms of hydrogen sulfide where one hydrogen atom is replaced by a hydrocarbon group, resulting in the general formula RSH. Their properties are defined by the length of the hydrocarbon chain, R. Similar to H2S, mercaptans exhibit acidic properties, but the presence of the hydrocarbon group makes them much weaker acids. As the length of the hydrocarbon chain increases, mercaptans exhibit properties closer to its hydrocarbon chain, R, than to those of acids. In the workplace, mercaptans expose a severe health risk: they can be rapidly absorbed
through inhalation but to a lesser extent through skin and eye contact. Low-level exposure can lead to irritation of the eye, skin, and upper respiratory tract, as well as symptoms like headaches, vomiting, and dizziness can occur. Higher levels of exposure can rapidly result in more severe respiratory paralysis. From an engineering point of view, mercaptans pose a severe corrosion threat: these chemicals interact with metals and form metal sulfides that lead to corrosion, especially in the presence of moisture. The consequences of corrosion can include damage to production equipment, leaks, spills, pump blockages and loss of productivity. If not properly controlled, mercaptans can cause severe economic problems in many operations in the oil and gas industry.
General properties of mercaptans
Mercaptans display different properties, which are dependent on the chain length of the hydrocarbon. They are known for a really strong unpleasant smell of rotten eggs. They are highly reactive due to the -SH group and form disulfides on oxidation and react with metals to form mercaptides. Boiling points of the mercaptans are very low, particularly the short-chain methyl mercaptan (CH3SH) displays a very low boiling point of 6°C, which results in serious health, safety and environmental problems. Short-chain mercaptans are more soluble in water than longer-chain mercaptans.
Current treatment technologies
The choice of treatment technology depends on various factors, including the concentration of mercaptans, the nature of the hydrocarbon stream, economic considerations, and environmental regulations. Often, a combination of methods
is employed to achieve the desired level of mercaptan removal. This article focuses on organic chemical scavengers. It discusses both the advantages of this treatment technique and its limitations. The use of a well-known H2S scavenger for mercaptan reduction is analysed and substantiated by various laboratory tests and field trials.
Organic scavengers – limitations and benefits in scavenging mercaptans
Organic mercaptan scavengers are used in natural gas and oil processing and wastewater systems, for example, to meet pipeline specifications, reduce unwanted odours and avoid corrosion. They are also used in refining to protect catalyst and ensure good fuel quality. In petrochemical production, they are applied to improve the quality of raw materials and end products. Organic scavengers are chemicals that are used to remove mercaptans from environments or processes. With specific technologies, scavengers react irreversibly with the mercaptans to form less harmful or more manageable products. The advantages and limitations of using organic scavengers to remove mercaptans are explained below.
Common organic mercaptan scavengers are triazines and oxazolidines, which are often used in the oil and gas industry for gas sweetening and the removal of H2S and mercaptans.
Other scavengers like amines react with mercaptans to form reversible salts and formaldehyde-based scavengers that react with mercaptans to form thioacetals.
These types of scavengers show several advantages over other treatment technologies: they can effectively remove low concentrations of mercaptans from gas and liquid streams, resulting in improved product quality and safety. They are designed to react selectively with mercaptans, minimising interference with other compounds in the process stream. Depending on application type and mercaptans to be treated, scavenger can be a viable and relatively inexpensive alternative to mechanical processes.
However, organic scavengers do have their limitations. The success of mercaptan removal can vary significantly depending on the concentration, the carbon chain length, the type of hydrocarbon medium and ultimately, kinetics. Light ends (C1C4) are known to be easier to treat than heavier chains but there is difficulty in the success of
scavengers in particular crudes across the globe even when mercaptan levels are known. In some cases, multiple treatments or higher doses of chemical than necessary may be required to meet customer specs, which can be uneconomical. With large-scale applications, costs of treatment can easily inflate: this includes the cost of the scavenger itself and the associated operating expenses, like transport, handling and storage. Also, formed reaction by-products may require further treatment or disposal, making the process even more complex. Additionally, most organic scavengers can be hazardous, requiring careful handling, storage, and disposal. This can increase operational complexity and costs.
The use of organic scavengers for mercaptan removal is an effective method with numerous advantages, such as a generally simple and quick-to-implement treatment/injection with low capital investment costs. However, there are also limitations such as chemical cost, potentially complicated handling and environmental impact factors. Careful selection and handling of scavengers is crucial to maximise their benefits while minimising the drawbacks.
Stabicor® S 100 (MBO) is an oxazolidinebased scavenger that consists of nearly 100% active ingredient. It contains no water or solvent. It is completely soluble in both water and oil and offers high chemical capacity and fast reaction kinetics. The excellent low-temperature properties of MBO ensure that it remains pumpable even at very low temperatures without the need for external heating. In addition, it is thermally stable up to 160˚C and readily biodegradable, resulting in a favourable environmental profile. MBO does not need to be used in high dosages and excess: this significantly reduces storage and transport costs and this is particularly important in environments where space is limited, such as oil platforms. However, MBO is an alkaline product and can be incompatible with certain brines leading to the precipitation of inorganic salts. MBO does introduce nitrogen into the system, but at a significantly smaller amount than the industry standard MEA triazine.
Proven mercaptans scavenging performance
Customer lab testing 1
A customer was storing condensate in their commercial vessels that had unsatisfactory levels of mercaptans. They extracted six samples
containing ethyl mercaptan and simulated the conditions of the condensate in tanks (static, without constant agitation) and analysed using a chromatographic method. Performance of stabicor S 100 was determined at the following dosages: 125/250/500/1000/1250 ppm. The mercaptans were analysed after 8 and 24 hours. Stabicor S 100
Treatment technology Process
Caustic washing
Extraction of mercaptans by using aqueous caustic solution
Oxidation
Sweetening
Absorption
Biofiltration
Hydrogenation
Extraction
Membrane separation
Claus process
Organic chemical scavengers
Oxidise mercaptans to disulfides
Merox process: a catalytic process where mercaptans are converted to disulfides using caustic and a catalyst
Absorption onto a solid medium
Biological exidation of mercaptans by microorganism
Form hydrocarbons and H2S by hydrogenation of mercaptans
Solvent extraction
Use membranes to separate mercaptans from hydrocarbons
Used primarily for sulfur recovery, but also effective in treating gas streams containing mercaptans
Chemical scavenging due to non-regenerative reaction
Advantages
Easy and cost effective
Effective to treat mercaptans to very low levels
Less waste produced compared to simple caustic washing
Effective for low concentrations
Environmentally friendly ande cost effective
Integrates well with existing hydrodesulfurisation units
Effective for specific applications
Efficient and continuous
Recovers sulfur
Effective for low concentration of mercaptans
Disadvantages
Regenerative process, creates spent caustic, special disposal required
was able to significantly reduce the mercaptan load after 8 hours (a very low dosage of 2 ppm scavenger to 1 ppm mercaptan) showing a 64% reduction of the ethyl mercaptan content. Higher dosages returned better performance. At a dosage of 11 ppm scavenger : 1 ppm mercaptan, stabicor S 100 showed excellent performance with 89% mercaptan reduction. Mercaptan scavenging is known to be more difficult than H2S removal, so higher dosages and/or longer residence times are required. Scavenging performance is dosage and time related: shorter retention time, higher dosage of stabicor S 100 required and vice versa.
Eventually complex and costly due to handling of oxidisers and possible deactivation
Continuous catalyst managing and maintenance
Periodic regeneration or replacement of the absorbent
Slow process, monitoring needed for microbial activity
Requires highpressure hydrogen and catalysts
Recovery and handling of the solvent can be complex
High investment
Complex, large-scale operations
Higher dosages, longer retention times, costly
Field data 1
Customer lab testing 2
A second customer with a cargo of sour oil required mercaptan mitigation to meet sales specifications. Samples of the material where taken from the dehydrator from the storage tank and analysed using gas chromatography. The following test set up was created: samples were shaken for 30 seconds to simulate mixing at the injection point, stabicor S 100 was used as the H2S/mercaptan scavenger at a dosage of 4 ppm scavenger to 1 ppm to remove H2S and mercaptan. The retention times were 2/4/6/12 hours. The oil sample contained 44 ppm H2S and 38 ppm methyl mercaptan. Stabicor S 100 was able to remove H2S fully from the system, and 60% of the methyl mercaptan removed under the test conditions.
External lab testing
An external laboratory tested the reduction of propyl mercaptan dissolved in a hydrocarbon solvent Exxsol D 80. Dräger Tubes were used as the detection method. The test was carried out at 60°C with stirring. Stabicor S 100 was used as a scavenger: propyl mercaptan has a higher chain mercaptan, hence a high dosage of 15 ppm scavenger : 1 ppm mercaptan was used.
As expected there was a limited reduction, the longer the hydrocarbon chain of the mercaptan the more difficult to scavenge it. However, stabicor S 100 showed an elimination up to 50%.
A major operator in Kazakhstan requested help to reduce H2S and mercaptans in the produced gas condensate containing ethyl mercaptans & propyl mercaptans stored in commercial storage tanks. Changes in operation meant that an increase in production of condensate occurred during the trial. Selection of robust mercaptan scavenger that can cope with unpredictable scenarios was critical. Initial GC analysis demonstrated that stabicor S 100 reduced almost 90% of ethyl mercaptans after 5ppm scavenger : 1ppm mercaptan dose.
During the initial operation, the condensate production increased from 350 m3/d to 450 m3/d meaning that the mercaptans increased from 125 to 300 ppm. Another important change was H2S has increased from 1ppm to 20 ppm (0 ppm H2S was required
Table 1. Current mercaptan treatment methods
Table 2. Customer lab testing 1. Ethyl mercaptan scavenging, dosage and time
Figure 2. Customer lab testing 2. Test on methyl mercaptan reduction. 100% H2S elimination and additional mercaptan reduction up to 60% with a low dosage of 4 ppm stabicor S 100 : 1 ppm H2S/mercaptan.
for spec). A field trial was launched, and a different approach was required.
Vink Chemicals recommended an improved process solution. An optimised injection location was selected and stabicor S 100 was injected into the run down from the dehydrator to the storage tank. This optimisation lead to successful results:
Ì Mercaptan reduction: Significant reduction in mercaptan content was observed during the tests, from a maximum of 123 ppm to a range of 20 – 27 ppm. This indicates the high efficiency of stabicor S 100 in the production treatment process.
Ì Hydrogen sulfide elimination: The maximum level of H2S content decreased from 30 ppm to zero.
Ì Stabicor S 100 successfully handled the H2S at the newly connected field: it demonstrated high efficiency and stability in the most challenging conditions, associated with a twofold increase in production from the new field.
Field data 2
A major end user in the North African region requested the removal of H2S from a shut-in oilfield. The removal of mercaptans was not
Figure 3. Propyl mercaptan reduction with 15:1 stabicor S 100 dosage. A limited reduction up to 50% was achieved.
Figure 4. Field data 2. Field trial in North Africa – Main goal was H2S reduction, which was 100% successful (300 ppm to 0 ppm). Additional mercaptan reduction of 73% (244 ppm to 66 ppm) was achieved. Methodology: UOP 163.
the original goal, but a very well recognised side effect. A single, very low dosage rate of stabicor S 100 was injected into a dry crude oil, after separator, into the pipeline. As the distance to the terminal is considerable, the total residence time was 3 days. The main KPI of H2S reduction below 50 ppm was successfully completed, an additional mercaptan reduction of 73% was achieved on top of that.
Conclusion
Overall, the above laboratory and field data show promising performance data for stabicor S 100 in removing lighter mercaptans. However, it does not yet appear to be the ideal solution. Higher dosage rates and longer retention times, especially in context with higher-chain mercaptans, are required. As a chemical manufacturer focused on research and development, Vink Chemicals is constantly striving to develop new innovative solutions to help the industry maximise its production and efficiency.
