Oilfield Technology - April 2021

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Contents 03 Comment

Issue 1 2021

Volume 14 Number 01

29 More reliable production forecasting David Riffault, Toni Uwaga, Pablo Cifuentes, Adnan Khalid and Rémi Moyen, CGG, explain how multi-scale ensemble-based history matching was used to forecast production for a gas field in Asia.

05 World news 10 A brighter outlook? Manash Goswami and Artem Abramov, Rystad Energy, explain why US tight oil’s overhaul in 2020 has positioned the industry for robust future performance.

33 Amping up fracking activity Travis Bolt, NOV, USA, explains how electric fracturing will help operators usher in the next generation of performance while delivering responsible, cost-effective frac operations.

16 Maximising annulus integrity Brett Hrabovsky, Elisabeth Norheim and Andreas Fliss, Archer, Norway, examine the benefits realised from the successful application of cementing technology.

37 Keys to a stronger bottom line Caroline Linder, Weir Oil & Gas, USA, explains how longer lasting consumables are helping optimise future oil and gas operations.

20 Revitalising mature, shut-in North Sea wells

39 Innovating against the grain

Bjornar Sneeggen and Sondre Klakegg, Weatherford, Norway, outline a novel solution designed to re-establish well integrity, resume production and reduce non-productive time.

Adam Calvin, TETRA Technologies, USA, analyses sand recovery challenges and conventional methods.

25 Building data superhighways

42 Doing more with data

John O’Hara and Andrew Penno, Halliburton, explore the emergence of intelligent completions technology.

Ginger Shelfer, Ambyint, USA, outlines how advanced production optimisation technologies can deliver improved production volumes, lower operating costs and reduced greenhouse gas emissions.

45 Intelligent inspection Dr Christina Wang, ABS, USA, demonstrates how machine learning can be applied to asset coating condition assessments.

50 Refining the method

Front cover

Alan White and Robert Miller, Clariant, consider the evolution of selection methodology for heavy oil separation treatments.

Archer has developed a range of cementing technology and tools to enhance safety and well integrity.

Cflex® technology enables high-performance multistage cementing. Certified gas tight under ISO 14998 V0, and with a two-stage permanent lock system, Cflex performs to the highest integrity standards. The MCAP – Mechanical Casing Packer system improves annular seal integrity and overcomes the shortcomings of conventional cementing technology. MCAP technology is certified gas tight (V0) to ISO 14310 and performs to the highest integrity standards.


55 Tipping the scales in operators’ favour Tom Swanson, Solugen, USA, considers two scale inhibitor solutions that can positively influence the treatment of produced water from source to disposal or reuse.

OFC OT Issue1 2021 indd 1

25/03/2021 11:22

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Copyright Palladian Publications Ltd 2021. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements.

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Comment Nicholas Woodroof, Deputy Editor


Contact us

Editorial Managing Editor: James Little

recent episode of my go-to history podcast focused on the 1990s – an unlikely topic of historical enquiry perhaps, but 45 minutes’ of listening yielded a fresh appreciation for what has often been derided (at least in the West) as a shallow, celebrity culture-obsessed decade of hubris and stagnation. Along with Britpop and bucket hats, hydrogen fuel had its spot in the limelight in the 90s; various carmakers invested in research and development before running up against a lack of consumer interest and the prohibitive costs of manufacturing fuels cells and installing refuelling infrastructure. Hydrogen seems to be making a comeback however, with reams of column inches dedicated to its green credentials in a manner that’s not far off the media hysteria surrounding ‘The Battle of Britpop’ back in the 90s (Oasis for me, in case you’re wondering). Low-carbon hydrogen growth is Point 2 of the UK government’s ‘Ten Point Plan for a Green Industrial Revolution’ – a key aim is 5 GW of production capacity by 2030. In the oil and gas industry it is hydrogen’s use as a cleaner alternative to natural gas for fuelling power plants that makes it of interest. Half of respondents in Asia-Pacific, MENA and Europe to a DNV GL survey of 1000 senior oil and gas professionals in 2020 thought that hydrogen would be a significant part of the global energy mix by 2030.1 Almost a year on and across both sides of the Atlantic oil majors set on a lower-carbon business model have been ramping up their interest. BP wants a 10% market share in ‘blue hydrogen’ and ‘green hydrogen’ in its core markets by 2030, while ExxonMobil – perhaps taking heed of the Biden administration’s focus on accelerating the pace of the energy transition – has announced plans to invest US$3 billion on lower-emission technologies, including hydrogen, through to 2025. With this matching of words and deeds, hydrogen seems well-placed to bypass the ‘trough of disillusionment’ stage of Gartner’s Hype Cycle that it experienced in the 1990s and play a substantial role in the energy transition. More than any recent technological breakthrough, it is the stark realities of the climate crisis, the effect of COVID-19 on oil demand and the turning of the regulatory framework against fossil fuel-based economies that bolster the case for research and investment. Expectations still need to be tempered however; hydrogen is not a ‘moonshot’ technology that will restore the fortunes of the industry and resolve the climate crisis by itself. Questions persist about the economics of green hydrogen (the cleanest form) in the immediate future, as well as the environmental footprint of blue hydrogen production. Another market shock in the next few years that sees oil prices tumbling to below US$40/bbl and staying there could scuttle the plans of companies still recovering from last year’s downturn. As such, it’s refreshing to see that companies in the oilfield services industry are focusing on providing less glamorous but essential tools for operators, such as supplier-to-supplier collaboration and good communication. I talked about this with Duncan McAllister, from Varel Energy Solutions, and Cody Baranowski, from D-Tech Rotary Steerable, in our inaugural Spotlight. If you haven’t seen our discussion already, then it’s free to view on our website: https://www.oilfieldtechnology.com/ special-reports/23032021/oilfield-technology-spotlight-with-varel-energy-solutions-and-d-techrotary-steerable/


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Reference 1.

DNV GL, ‘Hydrogen central to oil and gas industry decarbonization as expectations for market growth surge - DNV GL research,’ https://www.dnv.com/news/hydrogen-central-to-oil-and-gas-industry-decarbonization-asexpectations-for-market-growth-surge-dnv-gl-research--174854 (14 May 2020).

Issue 1 2021 Oilfield Technology | 3

Total cost of ownership is about more than money.

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World news

Issue 1 2021

Up to 120 million bbl discovered near Fram field Equinor and partners Vår Energi, Idemitsu Petroleum and Neptune Energy have made the biggest discovery so far this year on the Norwegian continental shelf (NCS). Preliminary estimates place the size of the discovery between 12 and 19 million m3 of recoverable oil equivalent, corresponding to 75 – 120 million bbl of recoverable oil equivalent. Exploration wells 31/2-22 S and 31/2-22 A in the Blasto prospect of production licences 090, 090 I and 090 E were drilled about 3 km southwest of the Fram field, 11 km northwest of the Troll field and 120 km northwest of Bergen. Exploration well 31/2-22 S struck a total oil column of around 30 m in the upper part of the Sognefjord formation and an oil column of around 50 m in the lower part of the Sognefjord formation. The oil-water contacts were proven at 1860 and 1960 m respectively. Exploration well 31/2-22 A struck high-quality sandstone in the Sognefjord formation, but the reservoir is filled with water and the well is classified as dry. Regarding the discovery to be commercially viable, the licensees will consider tying it to other discoveries and existing infrastructure in the area. The wells were not formation tested, but extensive data acquisition and sampling have been carried out. Well 31/2-22 S was drilled to a vertical depth of 2282 m below sea level and a measured depth of 2379 m below sea level. Well 31/2-22 A was drilled to a vertical depth of 2035 m below sea level and a measured depth of 2207 m below sea level. Water depth in the area is 349 m. The wells have been permanently plugged and abandoned.

Noble Corp. and Pacific Drilling to merge

Eni and SONATRACH sign agreements

Noble Corp. and Pacific Drilling Co. LLC have entered into a definitive merger agreement under which Noble will acquire Pacific Drilling in an all-stock transaction. The definitive merger agreement was unanimously approved by each company’s Board of Directors. The transaction has also been approved by a majority of Pacific Drilling’s equity holders, and no shareholder vote is required for Noble to close the transaction. As part of the transaction, Pacific Drilling’s equity holders will receive 16.6 million shares of Noble, or approximately 24.9% of the outstanding shares of Noble at closing. Noble expects to realise annual pre-tax cost synergies of at least US$30 million, and additionally, will move to dispose of the Pacific Bora and Pacific Mistral drillships expeditiously. The transaction is expected to be completed in April 2021. Pro forma for the acquisition, Noble will own and operate a high specification fleet of 24 rigs, with 11 drillships, 1 semisubmersible, and 12 jackups.

Eni and SONATRACH have signed various agreements covering exploration and production, research and development and decarbonisation. The first agreement aims to implement a programme for the relaunch of exploration and development activities in the Berkine Basin region and provides for the creation of a gas and crude oil development hub through a synergy with existing MLE-CAFC installations. This agreement is part of the process for the finalisation of a new hydrocarbon contract in the basin, under the aegis of the new Algerian oil law which came into force in December 2019. A Memorandum of Understanding was also signed for the development of a partnership in new technologies, with a focus on renewable energy, biofuels and hydrogen. The two companies have also agreed to collaborate in staff training programmes in the upstream industry and new technologies related to the energy transition.

In brief UK Aker BP UK, a newly established subsidiary of Aker BP in Norway, has entered into an agreement with Eni UK to take over a 50% interest in licence P2511 on the UK Continental Shelf. The key objective for the partnership between Eni UK and Aker BP UK is to explore the resource potential across the UK border in the greater Alvheim area.

Norway INEOS Energy is to sell its oil and gas business in Norway to PGNiG Upstream Norway AS for a consideration of US$615 million. The deal includes all INEOS Oil & Gas interests in production, licenses, fields, facilities and pipelines on the Norwegian continental shelf. INEOS E&P Norge AS produces around 33 000 boe/d from the Norwegian Sea, and has a 93% gas ratio from three non-operated fields: Ormen Lange (14%), Alve (15%) and Marulk (30%). The business also holds 22 offshore licenses, of which six are operated.

Mexico Doris has been selected by BHP Petroleum subsidiary BHP Billiton Petróleo Operaciones de Mexico, S. De R. L. De C.V. to continue into the next phase of engineering work at the Trion field: FEED for the subsea umbilicals risers and flowlines (SURF) scope of work. The Trion field encompasses an area of 1285 km2 and is located in the Mexican waters of the Gulf of Mexico, at a water depth of approximately 2500 m. BHP is the operator, holding a 60% interest in the development, with PEMEX Exploration and Production holding the remaining 40% interest.

Issue 1 2021 Oilfield Technology | 5

World news

Issue 1 2021

Diary dates 13 – 16 September 2021 Gastech Singapore gastechevent.com

21 – 23 September 2021 Global Energy Show Calgary, Canada globalenergyshow.com

15 – 18 November 2021 ADIPEC Abu Dhabi, UAE adipec.com

05 – 09 December 2021 23rd World Petroleum Congress Houston, Texas, US 23wpchouston.com To stay informed about the status of industry events and potential postponements or cancellations of events due to COVID-19, visit Oilfield Technology’s events listing page: www.oilfieldtechnology.com/events/

Web news highlights Ì Ì Ì Ì

Rystad Energy: drilling activity set for two consecutive years of growth Grants made available to support exploration in Beetaloo Basin Petrofac given Iraq contract extension EY: UK energy sector recovery cycle has begun but new mindset needed

To read more about these articles and for more event listings go to:


6 | Oilfield Technology Issue 1 2021

Beach Energy finds gas in Otway Basin

Development concept chosen for BM-C-33

Beach Energy has discovered gas in licence VIC/P43 (Beach 60% and operator, O.G. Energy 40% interest), offshore Victoria, Australia, in the Otway Basin. The Artisan 1 exploration well was drilled to 2205 m measured depth (MD) and penetrated the primary Upper Waarre Formation at 1921 m MD, approximately 92 m high to prognosis. The well intersected a gross gas column of 69.5 m in the Upper Waarre Formation, including 62.9 m of net gas pay, with a gaswater contact intersected at 1990 m MD. A gross gas column of 20.9 m was also intersected in the secondary target of the Flaxman Formation from 1902.8 m MD, with net gas pay of 4.6 m. The well is being cased and suspended as a future producer, with an opportunity to tie into the offshore pipeline currently delivering gas from the offshore Thylacine and Geographe fields to the Otway Gas Plant at a later date.

Equinor, Repsol Sinopec Brasil and Petrobras have approved the development concept for BM-C-33, a gas/condensate field in the Campos Basin pre-salt in Brazil. The well streams will be sent to a FPSO located at the field. Gas and oil/condensate will be processed at the FPSO to sales specifications and exported. Crude will be offloaded by shuttle tankers and shipped to the international market after ship-to-ship transfer. A new-build hull has been selected to accommodate for 30 years lifetime of the field. The gas export solution is based on an integrated offshore gas pipeline from the FPSO to a new onshore gas receiving facility inside the Petrobras TECAB site at Cabiúnas, before connecting to the domestic gas transmission network. Gas export capacity is planned for 16 million m3/d with average exports expected to be 14 million m3/d.

Four subsea tree systems installed at Duva development Neptune Energy has announced the installation of four Enhanced Horizontal Subsea Tree Systems (EHXTs) for the Duva development project in the Norwegian sector of the North Sea. The installation was carried out by a vessel instead of a rig, reducing installation time, costs and operational emissions. The Duva development, on Production Licence 636, is an oil and gas subsea tie-back to the Gjøa semi-submersible facility. Neptune Energy is the operator of both the Duva project and the Gjøa facility. While conventional installation of EHXTs would be carried out with a drilling rig, Neptune, together with its partners and contractors, conducted the installation using the vessel Far Samson, operated by Solstad Offshore. The 20 days of reduced rig time is equivalent to approximately US$12 million savings for the license partners. By using a vessel instead of a rig, emissions were reduced by more than 60% during the installation activities. It was the first time Neptune Energy has installed EHXTs in a standalone operation with a vessel. They were successfully deployed on the template wellheads over an 18-hour period, with the total installation and subsea system testing completed within eight days. The operation was carried out in cooperation with TechnipFMC, Ross Offshore, Solstad Offshore, Oceaneering, Fugro, IKM and Tigmek. The drilling rig Deepsea Yantai, operated by Odfjell Drilling, will drill and complete the remaining sections of the Duva well programme during 2Q21/3Q21. The Duva oil and gas field is located 14 km northeast of the Gjøa field, at a water depth of 360 m. Gross 2P reserves are 88 million boe (gas 76%). First production from Duva is expected in 3Q21.

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World news

Issue 1 2021

Siemens Energy wins FPSO topside contract Siemens Energy has been awarded a topside EPC contract by MISC Berhad for eight complete topside modules that will provide sustainable, efficient and environmentally friendly power generation, transmission and distribution, as well as gas processing and compression aboard an FPSO that will operate offshore South America, starting in 2024. MISC Berhad is building the FPSO to expand its fleet of 14 floating production systems. The FPSO is expected to have a processing capacity of 180 000 bbl of oil and 12 million m3/d of gas. The topside modules will be designed and manufactured across Asia, with main engineering and execution activities done through Singapore. Packaging for all the rotating equipment packages will occur at Siemens Energy’s Santa Barbara d’Oeste facility in Brazil. The facility is also fully equipped to provide support and service to the FPSO’s modules once it is deployed. Siemens Energy’s scope of supply includes the EPC work for all eight modules and several key components: two electric, low-pressure centrifugal compressors; two electric, CO2 compressors; three main injection compressors driven by Siemens Energy SGT-A35-GT62X gas turbines; four Siemens Energy SGT-A35-GT30 gas turbines for power generation; an E-house; plus all electricals including an electrical control and management system (ECMS). The ECMS is being designed to provide monitoring and supervision for the power generation and distribution network for load management of the FPSO facility, including topside and marine. MISC Berhad and the FPSO operator can use the ECMS to monitor FPSO power, generate reports and plan for future sustainability.

Expro Group and FTAI Ocean form alliance Expro Group has formed an exclusive alliance with FTAI Ocean LLC for the supply of the DP3 M/V Pride well intervention vessel to provide full light well intervention services to the subsea oil and gas sector. The alliance creates a full service offering for the riserless and riser-based well intervention and P&A markets, providing all marine, ROV, well intervention, wireline, e-line, coilhose, subsea well access, hydraulic intervention, well planning, execution and offshore well management by a single supplier using one contracting entity. Both services and technologies will be deployed under the alliance, and will be supported by the introduction of FTAI Ocean’s well intervention smart tower system, to be installed on the DP3 M/V Pride Offshore Construction Vessel.

Murphy Oil sells stake in King’s Quay FPS

Chevron Australia awards maintenance contract

Halliburton provides E&P software to students

Murphy Oil Corp.’s subsidiary, Murphy Exploration & Production Company – USA, has completed the sale of its 50% interest in the King’s Quay floating production system and associated export lateral pipelines (Associated Laterals), to be located in the Gulf of Mexico. The FPS and Associated Laterals will be co-owned in a joint venture with entities managed by Ridgewood Energy Corp., including ILX Holdings III, LLC. The FPS is more than 90% built and is scheduled to go into service in mid-2022. The FPS is designed to process 80 000 bpd of oil and 100 million ft3/d of natural gas, and will handle the anticipated production from the Khaleesi/Mormont and Samurai fields. The transaction reimburses Murphy’s past capital expenditures of approximately US$270 million related to the FPS and the Associated Laterals. The company intends to use the proceeds to repay borrowings under the US$1.6 billion senior unsecured credit facility and for general corporate purposes.

AusGroup’s subsidiary AGC Industries (AGC) has been awarded a significant maintenance master contract by Chevron Australia. The contract is the longest maintenance master contract currently in the Australian oil and gas market. The 10-year master contract enables Chevron Australia to order full-service asset maintenance from AGC across Chevron’s onshore and offshore natural gas and oil production facilities located in the north-west of Australia. The contract will see AGC deliver management, planning, scheduling and supervision; painting insulation and fireproofing (PIF); scaffolding including engineering services; rope access (central trades); workshop management; asset management (hire equipment special tools); procurement and maintenance; crane operation (rigging) and maintenance. AGC confirmed a significant number of new roles would be required to service orders under the contract.

Halliburton has awarded a software grant to Universiti Teknologi PETRONAS (UTP) in Malaysia to support the education and development of students pursuing careers in the oil and gas industry. The three-year donation provides access to the company Landmark’s DecisionSpace® suite of exploration and production software so students can bridge the gap between academic coursework and practical application. The grant also facilitates the Halliburton Science and Technology for Exploration & Production Solutions (STEPS) programme, which offers students the opportunity to conduct a research project while receiving industry-relevant training and mentorship. Two UTP graduate students will be able to participate in the programme. In addition, Halliburton will deliver adjunct lectures for undergraduate and master’s degree students on a variety of topics including drilling, production, field development and data science.

8 | Oilfield Technology Issue 1 2021

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A brighter outlook? Manash Goswami and Artem Abramov, Rystad Energy, explain why US tight oil’s overhaul in 2020 has positioned the industry for robust future performance.

10 |


he US tight oil industry was hit particularly hard in 2020, a year that was one of the most disruptive for global oil and gas markets. The rig count – generally viewed as an overall barometer of US onshore activity – and horizontal oil-focused drilling in the country, the main driver of the US’s oil production growth in 2017 – 2019, collapsed by approximately 75% through 2Q20. The downturn in 2020 was unprecedented and so was the plunge in rig activity levels, which was far more severe than any of the previous corrections. As oil prices recovered towards US$40/bbl in 3Q20, the oil rig count bottomed out and many producers cautiously started to redeploy them. The gradual recovery trend has become more visible in recent months, with the horizontal oil-focused rig count surpassing 270 units as of 12 February 2021, 80% higher than the 2020 low of 149 touched in August (Figure 1). Gas-focused drilling in the Appalachia and Haynesville regions also experienced a severe decline of approximately 60% through 2H19 and 1H20. The gas rig count stabilised in 3Q20 and select Haynesville producers have marginally increased their activity in the last few months.

Fracking activity While the recovery in rig activity could at best be characterised as gradual, fracking activity – a more important indicator of short-term production potential – saw a robust rebound in 2H20 (Figure 2). Fracking activity declined faster than drilling in 2Q20 as many producers were able to

‘freeze’ or delay their pressure pumping contracts at no additional cost. That resulted in an abnormal bulge in the country’s drilled but uncompleted (DUC) well inventory, as many wells that were drilled in 4Q19 and 1Q20 were not completed on schedule in 2Q20. Hence, the cumulative DUC inventory provided the industry with ample flexibility in 2H20 and many producers were able to increase their frac activity, while maintaining a conservative rig programme. The existing anomaly in the DUC inventory will provide significant support to nationwide fracking deep into 1H21. Rystad Energy has identified 909 started frac operations in North America for January, as of the week ended 12 February. Rystad estimates that there are at least 50 frac operations that it has not yet detected through satellite imagery analysis or the FracFocus registry, for a total of 959 jobs. As for February 2021, Rystad have already identified 201 jobs, 200 of which were identified exclusively by satellite analysis. Activity in the Permian Basin was strong in January, with 438 identified fracs, a large increase from the 249 recorded in December. In other US core oil plays, however, there was a stagnation, as the frac count stayed at close to 200. There was a slight decline in South Texas’ Eagle Ford, to 70 in January from 83 in December, which was, however, offset by an addition of 10 fracs in the Niobrara and five fracs in the Bakken regions. Further to the identified frac jobs, Rystad estimate an additional 28 jobs in the Permian, eight in the Eagle Ford, and 14 in other basins for January 2021.

| 11

The weekly job count in major oil regions other than the Permian – the Eagle Ford, Bakken, Niobrara and Anadarko combined – hovered around 40 jobs per week in September and October, but the run rate of activity increased to 60 jobs per week in November, due to the unusual spike in activity in early November in the Niobrara region.

Tight oil After the period of curtailment in 2Q20, nearly all tight oil volumes were restored by the end of 3Q20 as total US tight oil production from horizontal wells returned to 7.4 million bpd,

Figure 1. US land horizontal rig count by main hydrocarbon type.

Figure 2. Permian started frac operations by week in 2020.

Figure 3. US light tight oil maintenance requirements and actual new well activity. Includes horizontal wells in Permian, Eagle, Ford, Bakken, Niobrara and Anadarko.

12 | Oilfield Technology Issue 1 2021

a 1.1 million bpd decline compared to the output recorded in March. Meanwhile, conventional production rebounded only to 1.7 million bpd and saw little incremental recovery in August and September. Given the much shallower decline rates for conventional operations, the fact that conventional oil output from the Lower 48 states, excluding the Gulf of Mexico, remained 200 000 bpd below the level in March indicated that approximately 150 000 bpd of US conventional production remained shut in at the end of 3Q20. This might present a potential upside for US supply in the short-term if oil prices justify reactivating those mature, less economic wells with high water-to-oil ratios. With an addition of approximately 2.8 million bpd expected in December from 2020 tight oil vintage wells, the industry cannot offset the record-high base decline of approximately 3.8 million bpd between December 2019 and December 2020. US tight oil production was therefore set to lose approximately 1.05 million bpd of supply through 2020, a process which is now largely completed. The base production, at the time of writing, was much more mature than it was at the start of 2020. The first-month horizontal base decline across major liquid basins – the Permian, Eagle Ford, Bakken, Niobrara and Anadarko combined – fell from approximately 630 000 bpd in 1Q20 to 410 000 bpd in 4Q20. Moreover, the average new well performance showed a misleading trend in the second and third quarters because of the curtailments, which affected even new vintages. The latest well results from the third quarter put on production (POP) activity suggested another upward shift in the average new well productivity. A typical horizontal well in major liquids basins delivers approximately 750 bpd of oil in its peak production month – an increase of 6% to 7% from the average new well productivity level recorded in 4Q19. This is the result of a continuous increase in the average lateral length and a new wave of high-grading since the start of the COVID-19 pandemic. Considering the maturation of base production and the record-high new well productivity, Rystad Energy expects the number of wells needed to keep tight oil production flat to drop rapidly. This maintenance activity requirement fell from approximately 900 horizontal wells per month in 1Q20 to 550 horizontal wells per month in 4Q20, and is likely to keep falling towards 500 wells per month by the end of 2021, if the industry stays in a maintenance mode from 4Q20. Such horizontal well activity requires 280 to 300 horizontal-focused rigs in major oil regions combined. The current rig activity level as of late November, even after the significant increase in the past few weeks, remained below the number needed to maintain production, at 210 to 220 horizontal rigs. Rystad Energy expects the industry to keep adding oil-focused rigs in 2Q21 to reach maintenance requirements by the time the existing DUC inventory is depleted. In the short-term, however, over the last three months of 2020 and 1Q21, the abnormally large DUC inventory is expected to be sufficient to meet maintenance well activity requirements. In fact, as illustrated by Figure 3, actual activity is right now about to catch up with maintenance requirements. Maintaining stable production in 2021, with a continuous focus on free cash flow generation and balance sheet improvement, was the main theme in the 3Q20 earnings of tight oil producers. Indeed, select public producers (Figure 4), who offered a broad outline for 2021, largely plan to remain disciplined, targeting to spend only the amount they need to maintain flat output for 2021 at the level of 4Q20 production.

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Against that backdrop, Rystad Energy expects 2021 full-year onshore oil production to shrink slightly by 1.9%, while D&C CAPEX will be considerably lower at 12.9%, compared to their 2020 plan, based on a group of 23 oil-focused operators. The included peer group accounts for approximately 41% of 2020’s US tight oil production. The decline may be slower, at 8 – 10%, if the estimated CAPEX of larger producers (e.g. supermajors) are added in. That comes as companies maintain an unrelenting, never-before level of focus on balancing their budgets and generating free cash flow, driven by that blurry macro backdrop. 3Q20 showed an underspending of close to US$3.6 billion by shale producers when comparing their CAPEX budgets with cash

Figure 4. 2021 outlook for US tight oil producers vs 2020.

Figure 5. Quarterly CFO vs CAPEX for peer group of 39 dedicated public US shale oil producers.

Figure 6. US land natural gas wellhead flaring by oil basin and month.

14 | Oilfield Technology Issue 1 2021

flows from operations (Figure 5). Companies managed to further reduce their CAPEX from the lows seen in 2Q20, to US$3.4 billion from US$4.5 billion, while more than doubling the cash generated from operating activities, to US$7 billion. The number of operators that balanced their budgets in 3Q20 reached 89%, a level that has never been achieved before in the shale industry’s history. The spread between CFO and CAPEX also reached an all-time high of US$3.6 billion.

Environmental performance While 2020 was a challenging year for tight oil producers’ economics, it has helped the industry achieve structural improvements in the environmental domain. Gas flaring in the Permian and Bakken basins was one of the biggest ESG challenges for operators in 2018 – 2019, especially in the context of the global energy transition and a fundamental shift in the significance of ESG within the investor community. Driven predominantly by high activity levels and a lack of integrated project planning, wellhead gas flaring across major oil basins peaked above 1.4 billion ft3/d during the summer of 2019 (Figure 6). A significant volume of gas was also flared at gas processing plants in West Texas at that time. As the downturn came in, wellhead gas flaring declined rapidly, too. In fact, wellhead gas flaring across major US oil basins remained close to the multi-year low of approximately 520 million ft3/d as of September 2020. Permian wellhead gas flaring increased from approximately 220 million ft3/d in May 2020 to 345 million ft3/d in July 2020, but declined again to 255 million ft3/d in September 2020, a level that was lower than in June 2020. Wellhead gas flaring in the Bakken Shale declined from more than 500 million ft3/d in late-2019 to around 200 million ft3/d in May 2020 and has stayed below that mark since. Flaring levels in the Eagle Ford and DJ/PRB basins usually are not as significant as the Permian and Bakken, but the Eagle Ford region has seen a less pronounced decline between 4Q19 and 2Q20 in relative terms. While some operators were already at very low flaring intensity levels in 2019, many others made significant improvements between 2H19 and 3Q20. This is a clear illustration of a structural shift in the industry’s attitude toward the environmental aspect of their operations, establishing a good foundation for responsible development in the next up cycle, in 2021 – 2022.

Conclusion Despite the many financial and operational improvements achieved by the industry since the downturn, ample headwinds still exist, including the macro uncertainty on the long-term impact the pandemic may have on the global economy. As a result, oilfield service companies are still fine tuning their budgets and outlook for 1Q21 as operators are at times changing their plans, with some companies pushing out finalising their budgets into early 2021. Service companies are working on their plans almost on a month-to-month basis due to the ongoing market uncertainty. Heading into 2021, the shale industry’s outlook will, in part, hinge on oil price expectations. Much, of course, depends on the OPEC+ meeting on 3 – 4 March 2021. Rystad estimates that OPEC+ could bring back as much as 1.3 million bpd in April 2021 and still keep the market balanced, but instead expect the group will stick to the deal it made in December 2020 to limit monthly supply increases by 500 000 bpd.


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Brett Hrabovsky, Elisabeth Norheim and Andreas Fliss, Archer, Norway, examine the benefits realised from the successful application of cementing technology.


ell integrity is defined by NORSOK D-10 as ‘application of technical, operational and organisational solutions to reduce the risk of uncontrolled release of formation fluids throughout the life cycle of a well.’1 Well integrity is concerned with the safe and reliable containment of all well fluids throughout the life of a well, including while drilling, running completion, during production and well interventions. A failure of well integrity is often related to safety and environmental aspects but also includes loss of production, reputation and asset value.

Annulus integrity is a key component in the assurance of overall well integrity, and challenges may appear in many shapes and sizes. Whether it be annular pressure build-up (APB) in subsea wells, causing potential casing failures; inadequate zonal isolation, leading to less than optimised production rates; compromised barriers due to degradation or geologic events, causing costly intervention operations; or a plethora of other challenges, they all have the potential to cause significant losses for the asset owner.


As the industry recovers from the downturn, the challenges associated with improving and maintaining annulus integrity through operational efficiency, prompt results and – of the utmost importance – cost-savings will continue to remain. Archer Oiltools provides smart and robust solutions where well integrity, reliability and time-savings are of the highest importance. The company’s Cementing Solutions Product Line – GuardianTM – includes technologies that deliver better wells by extending well life, maximising well performance and minimising environmental impact (Figure 1).

Flexibility in barrier placement and verification The Cflex® is a mechanically activated downhole sleeve that provides controlled, secure and selective access to the annulus space typically used for stage or remedial cementing applications (Figure 2). The flexibility, reliability and confidence in annular access allows for use in other applications that also require this functionality.

This includes, but is not limited to, barrier verification (i.e. creeping shale) and APB mitigation as a pressure relief port. The Cflex is V0 qualified through rigorous testing, equivalent to the ISO 14998 standard, which means it provides an absolute ‘gas tight’ seal. Locking the sleeve so that it is permanently closed following a successful operation adds further security. In terms of efficiency and performance operating the Cflex is straightforward, fast and precise. The multi-function operating tool is designed to both operate the Cflex valve and inject fluids. If multiple sleeves are present, each can be accessed and controlled selectively according to the multi-stage programme. Archer has successfully installed up to five Cflex’s in a single string and up to nine in a single well. The Cflex-F takes the technology a step further and incorporates an annulus cement base that activates during the opening of the cement ports. This ‘fundament’ creates a solid base and prevents cement contamination below the tool.

Providing protection on its own or in support

Figure 1. Cflex and MCAP global footprint.

The MCAP® is a mechanically set packer designed to seal off the annulus between two casings. It is activated by a drill pipe deployed activation tool, having over pull when latched into the MCAP (Figure 3). As with the Cflex, if multiple packer devices are present each can be accessed and controlled selectively on the same trip. The packer device has been subjected to similarly rigorous validation testing protocols, and both the element section and internal seals have been qualified as a gas barrier according to ISO 14998/14310, with a pressure rating up to 10 000 psi. The MCAP can be used as a stand-alone tool for isolation of the annulus between two casings for many applications, including prevention of sustained casing pressure (SCP) and a tieback anchor/packer. It can also be installed in combination with a Cflex where the MCAP will create a fundament for placing cement above and isolate below the Cflex, preventing any influx from lower zones from contaminating the column of cement above prior to cure.

Integrated operations

Figure 2. Pumping cement through a Cflex.

Since 2015, Archer has made it possible to run operations offshore without company personnel themselves being on board the rig. Integrated operations (IOs) ensure a high standard of operational quality and safety and, through the use of advanced real-time technology, deliver a significant reduction in personnel-on-board (POB) to operators, as well as a substantial decrease in carbon footprint globally. In 2020, Archer performed more than 300 IOs worldwide, from Canada and the Gulf of Mexico to the North Sea and the Caspian Sea. The company has increased the scope of products and solutions delivered with IOs over recent years, with a 100% success rate. In 2020, the company’s IOs saved approximately 20 000 t of CO2 emissions.

Case study 1 Challenge

Figure 3. Activation of MCAP.

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During drilling of the 17.5 in. section the operator experienced heavy losses, followed by significant gains from a suspected drilling-induced fracture. Although the well was somewhat stabilised for casing installation, it was

suspected that conventional cementation of the casing would prove problematic.

Solution The operator decided to install one Cflex approximately 5500 ft above the shoe at approximately 6500 ft as a contingency cementing option if the primary was unsatisfactory. A second Cflex was installed approximately 140 ft above the 18 5/8 in. casing shoe at approximately 2300 ft, directly above the MCAP, to isolate the problematic zones deeper in the well. This upper Cflex and MCAP contingency would help the customer ensure isolation in the uppermost section of the 13 5/8 in. casing.

Results The primary cement job was performed conventionally through the shoe and, as expected, did not achieve the required cement coverage due to losses encountered when pumping cement. As a result, the Cflex cementing tool and MCAP activation tool were run in hole past the upper Cflex and MCAP and down to the lower Cflex. The Cflex was then opened successfully and a second stage job was performed through it in an attempt to achieve better cement coverage. Due to extremely challenging loss conditions it was not possible to achieve the column of cement required via the lower Cflex. The MCAP was then successfully set and tested to 500 psi and the Cflex opened using the activation tools in the drill string. This isolated the problematic formations and allowed a controlled third stage to be performed, ensuring competent cement throughout the 13 5/8 in. x 18 5/8 in. casing annulus. The execution of the job from start to finish was successful, with all Archer equipment performing as expected. Subsequent logging of the casing showed very good cement coverage inside the 13 5/8 in. x 18 5/8 in. casing annulus (Figure 4).

stage cement. After packer inflation the Cflex directly above it was opened with an inner string cementing tool and excess cement was circulated out from the first job. A second stage cement job was then performed through the Cflex above the openhole packer.

Results The execution of the job from start to finish was successful, with all equipment performing as expected (Figure 5). Subsequent logging of the casing showed significant improvements in cement coverage across the target zones. The solution allowed the NOC the option to change well design and save 7 – 10 days in rig time per well, equating to approximately US$700 000 in cost.

Summary In the cost-conscious market of today’s oil and gas industry, remedial and intervention work to repair or put in place annular barriers can be costly and delay or postpone production. Archer’s Guardian product family of annular integrity solutions provide operators with greater confidence that they can secure wells the first time, as well as providing flexibility in contingency measures and barrier verification. Further benefits include minimising cost and potential environmental impact, extending well life and maximising well performance throughout the life of the well.

Reference 1.

NORSOK D-010 Well integrity in drilling and well operations, Rev.4 (June 2013), https://www.standard.no/en/sectors/energi-og-klima/ petroleum/norsok-standard-categories/d-drilling/d-0104/

Case study 2 Challenge A national oil company (NOC) in the Gulf Cooperation Council (GCC) region has historically been unable to consistently achieve competent cement above a loss zone approximately 2000 – 2500 ft above the 9 5/8 in. casing shoe at approximately 7500 ft. This challenge often leaves 5000 ft or more of inadequately cemented casing, leading to corrosion issues and resulting in compromised well integrity over time. The current solution utilises top down cement squeeze jobs from surface that are mildly effective and often leave areas un-cemented, leading to multiple issues in the future, including sustained annulus pressure and casing corrosion.

Figure 4. Case study 1: well schematic illustrating placement of the Archer equipment.

Solution The solution proposed was a two-stage cement job utilising an inner string that would allow efficient, accurate and effective placement of cement around all target zones. The primary job was performed through a tag in float system supplied by Archer that allowed the packer to be set and Cflex opened before the first stage cement set-up. The openhole packer, situated just above the loss zone, was then inflated to isolate the losses and provide a fundament for the column of second

Figure 5. Case study 2: cost, time and equipment savings for Cflex and OH packer


Issue 1 2021 Oilfield Technology | 19

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Bjornar Sneeggen and Sondre Klakegg, Weatherford, Norway, outline a novel solution designed to re-establish well integrity, resume production and reduce non-productive time.

REVITALISING MATURE, SHUT-IN NORTH SEA WELLS major North Sea operator recently approached Weatherford with a challenge: devise a solution to revitalise non-producing wells that have been taken off-line due to casing integrity issues, a not-uncommon fate befalling many North Sea wells. In search of the best alternative for bringing these wells back to life and, at the same time, providing means to enhance productivity and regain full wellbore functionalities, Weatherford worked with the operator to develop and advance the alternative gas lift system (AGLS) completion concept. AGLS enables operators to restore the primary and secondary well barriers while regaining gas lift capabilities. Together, Weatherford and the operator identified viable technologies and solutions to re-establish well integrity and resume production in compliance with the well barrier envelope policies and philosophies. Also critical was the challenge of successfully expanding reservoir possibilities. The project was coordinated from concept through to execution, effectively deploying two wells while recording no incidents and zero non-productive time. Across the North Sea, many mature fields face challenges in which the casing can no longer be utilised as a secondary barrier for gas lift injection. As these wells enter the late stage of their lifecycle, there is simply not enough pressure to continue production, even though plentiful reserves remain in place. In addition, gas lift is widely used across the North Sea portfolio of liquid-producing wells. Often, this is done by utilising the A-annulus to transport natural gas down to the required depth in the well. The gas is injected deep into the production tubing through side pocket mandrels, effectively using artificial lift to extract liquids from the reservoir. Under normal circumstances, i.e. no well integrity concerns, the production casing is the primary barrier against gas injection system leaks into the surrounding and secondary barriers towards the reservoir.

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Preparing for artificial lift To re-establish the well barrier philosophy for gas lift production and to equip the wellbore so that flow assurance and wellbore access concerns are addressed, an enhanced AGLS concept was further reassessed and engineered, culminating in a robust and cost-effective solution to this challenge. First, it was necessary to re-establish the barriers for injection of lift gas, which was accomplished by moving the secondary barrier against gas lift inwards, creating an extra annulus between the existing 9 5/8 in. casing and a new 7 5/8 in. casing. The existing 13 3/8 in. casing could not be used as a barrier for gas lift as its integrity would have been compromised. By retrieving the existing upper completion and installing a new 7 5/8 in. casing with gas tight rated production packer inside the existing 9 5/8 in. casing, full casing integrity could be restored. The next step was to find a solution for installing new upper completion inside 7 5/8 in. casing, while maintaining the capability of injecting lift gas at required rates as well as satisfying all other requirements for the completion design. This was a key challenge presented to Weatherford engineering as standard completion technologies were not currently available in the market, and the quick turnaround was crucial to the ultimate success of the project. In response to the challenge, the company implemented a combination of existing and new technologies, drawing on previous success within gas lift completions across the globe.

Meeting safety standards in the North Sea

Figure 1. The Weatherford alternative gas lift system (AGLS) enables operators to restore primary and secondary well barriers while regaining gas lift capabilities.

Earlier in 2020, the company successfully concluded the expansion of the large bore annular safety system portfolio with a subsequent installation of the 10 ¾ in. annular safety valve (ASV) system in the North Sea and had anticipated the 7 5/8 in. slim design system booked for an enhanced recovery project in the region. The challenge of this project further accelerated the timeline while complying with one of the industry’s most stringent technical standards on a tailor-made design. The project took on increased complexity from a portfolio suitability and value-added solution. The ASV system itself, considered the backbone of the design, incorporated the API14A V1-validated Optimax™ safety valve. In addition to the launch of 7 5/8 in. ASV, the AGLS demanded a series of high-end components in order to make it robust enough to withstand the challenges anticipated over the life of the well. To that end, systematic technical due diligence was conducted with key subject matter experts. From the combined load analysis that was carried out, the Weatherford OptiPkrTM production packer was recommended as the means to deliver the robust performance of a permanent packer with the flexibility of a retrievable packer all in one tool. In addition, with the nodal analysis having been completed, an Optimax tubing retrievable safety valve was incorporated to ensure the well would be safely maintained in the unlikely event of uncontrolled pressures into the wellbore.

Optimising chemical injection

Figure 2. The customised solution incorporated the API 14A V1-validated Optimax safety valve to enhance life-of-well safe operations in the unlikely event of uncontrolled pressure into the wellbore.

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Another critical challenge posed by the anticipated well lifecycle was the need for precise wellbore chemical management with the aim to optimise flow assurance and production performance while reducing the potential for expensive intervention. Weatherford assessed the reservoir and wellbore conditions and deployed its RCI-2QS chemical injection system, enabling pressure fluctuations to be absorbed and controlled while still delivering gas tight metal-to-metal (MTM) sealing, even after high circulation rates. The chemical injection system deployed to meet this challenge was

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Figure 3. The final step in enhancing production is determining reservoir behaviour and recovery potential. This solution incorporated quartz reservoir monitoring sensors that provide real-time pressure and temperature data. proven effective in rigorous qualification testing that addressed multiple well scenarios. For the gas lift system itself, decisions regarding the optimum number and setting depths of valves in gas lifted wells are traditionally made considering only a small number of operating scenarios. As a result, wells often do not perform as expected. Weatherford’s turnkey gas lift solutions include gas lift design, monitoring and analysis to maximise the performance and profitability of operators’ wells. With this in mind, a project was initiated to enhance the completion design and enable future accessibility for remedial services that could deliver optimal production performance over the life of the well.

Determining reservoir behaviour Finally, the company sought to ensure that each originally planned outcome assessed during the initial phase was being achieved.

Knowing reservoir behaviour determines recovery potential, production efficiency and the cost of asset ownership, the company deployed a reservoir monitoring solution to deliver continuous and actionable intelligence on the well, effectively delivering real-time data to diagnose production problems and enhance recovery. ForeSite Sense™ quartz technology was also incorporated into the solution. With the service delivery plan reviewed and agreed upon by the stakeholders and key technologies integrated into a coherent interfaced system, the technologies were deployed using a multidisciplinary crew that reduced personnel onboard by 45%. This streamlined communications and operational efficiency leverages workflows established in the Weatherford CompleteTM post-TD solution, which integrates all post-drilling services, including liner hangers, wellbore clean-up, tubular running, completions, fishing, slickline and well services. During 2Q20, the first two AGLS completions were successfully installed, returning the mature wells to life with production numbers meeting and exceeding operator expectations. In comparison to a conventional 13 3/8 in. sidetrack, the approach provided total savings in excess of 40% while expanding its application to slot recovery wells, given its plugging and abandonment (P&A) friendly design and the associated operational savings.

Conclusion As the industry continues to lock down capital spending, stakeholders must make the most of their current resources to remain viable. Rather than placing profitability on hold, the chief challenge, of course, is doing more with less capital and fewer people. Using proven, integrated technology systems – such as an end-to-end alternative gas lift solution – to economically revive non-producing wells is critical to keeping oilfield ventures in the black.

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BUILDING DATA SUPERHIGHWAYS John O’Hara and Andrew Penno, Halliburton, explore the emergence of intelligent completions technology.


he oil and gas industry remains a cornerstone of the world’s economy and continues to adjust and adapt to market conditions. Extraordinary changes this past year have forced the oil and gas industry to shift from relying on mobile operational support and central technology development to a remote model focused on a solid in-country infrastructure and digital communications to support ongoing operations. These significant challenges – the substantial decrease in oil and gas demand caused by COVID-19, focused efforts to reduce carbon footprints, organisational and operational downsizing and asset rationalisation – heighten demand for collaboration between Halliburton and E&P operators. Halliburton Completion Tools has designed The Future of Completions™, an embodiment of solutions that will introduce an end-to-end digital ecosystem, advances in new materials, innovations with increased autonomous reservoir controls and all-electric completion systems.

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Completion System (ESTMZ TM ) delivers capital efficiency during The company collaborates with customers to clearly understand drilling and completion operations. The system is part of the their value drivers in areas ranging from wellbore equipment advanced completions suite of solutions, which comprise a design to digital reservoir management. Halliburton Completion broader capability and include advanced lower completions, Tools comprises a technical structure of advisors and subject intelligent completions and multilateral completion solutions. matter experts to facilitate the continued remote support The application of such technologies is the linchpin of how of global operations. A global network of operational bases purposed technologies are implemented to provide value to (with extensive local expertise) provides in-country support operators across global basins. and maintains a strong global technical support organisation. By way of example, in the Gulf of Mexico more than 30 ESTMZ This structure has been instrumental in responding in a timely systems have been deployed and reduced the completion manner to shifts in operational needs during global travel duration by 18 days per well. This helped the operator save restrictions. The shift to a more diverse global technology pool, US$12 million and reduce the CO 2 footprint by more than 800 t per completion. Additionally, Halliburton has released and coupled with greater focus on in-country resources and new deployed the Xtreme Single-Trip Multizone Completion System digital processes, has enabled continuity in delivery of services. (XSTMZ TM). This second generation of the system enables Purposed technologies realisation of further cost and emission reductions in deeper Unexpected disruptions to global operations, as well as a frontier completions. For another operator in Indonesia, competitive low-price environment, have amplified the need SmartWell® completion systems were integrated with the to provide operators with purposed technologies that deliver ESTMZ system, which helped reduce CAPEX and CO 2 emissions during the completion phase. Full zonal control continued to the lowest cost per barrel of oil equivalent (boe). Completions be provided during the life of the well, increasing asset value by technologies, such as the DataSphere® permanent monitoring managing production of each individual producing zone.1 suite of sensors, help optimise reservoir treatments and In Norway, a 20-year collaboration in the advancement and production efficiency. The Enhanced Single-Trip Multizone development of purposed technology has helped operators maximise ultimate hydrocarbon recovery and reduce surface footprint. The company has implemented intelligent completions, multilateral technology (MLT) and passive flow control devices such as inflow control devices (ICDs) and autonomous inflow control devices (AICDs). Of these technologies, MLT systems integrating SmartWell systems have delivered a significant impact for operators. The modification and development of MLT junctions culminated with the current FlexRite® Multibranch Inflow Control (MIC) System, which allows for three and four lateral leg designs that incorporate SmartWell system production control at each lateral leg.2 The successful Figure 1. The DataSphere permanent monitoring suite is modular and versatile, helping to optimise deployment of these systems in new and production and validate reservoir models. existing wells in several Norway fields has led to adoption across large growth markets, including the Middle East, Eastern Russia and Asia-Pacific. Sensors continue to be value drivers in the advanced completions space. Encompassing advanced downhole pressure, temperature, flow and density sensing technology, the DataSphere permanent monitoring suite is designed for versatility and modularity, providing operators with customised solutions to help increase reservoir contact and hydrocarbon recovery for the life of the well. In unconventional basins across North America and Argentina, the monitoring suite provides distributed pressure sensors for reservoir and Figure 2. Multilateral systems with three and four lateral leg designs enable individual production advanced fracture interference insights. control.

26 | Oilfield Technology Issue 1 2021

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Critical insights are received during both the completion phase to help quickly identify fracture interference and the production phase to understand production forecasting, artificial lift performance and depletion. 3 An equally rapid adoption is behind-casing monitoring utilising casing inductive coupling technology. In Norway and the Caspian Sea, the DataSphere LinX® system leverages wireless through-casing data and power transmission to allow for behind-casing monitoring. This provides real-time life-of-well pressure and temperature insights, monitoring caprock integrity on injectors, as well as pressure in the B and C-Annulus. The technology optimises and helps remove the need for observation wells.4

Digital capabilities Purposed technology will be complemented by the company’s transition into the digital oilfield. Halliburton Completion Tools has created eCompletionsTM; a digital ecosystem that advances completions by improving service quality, accelerating continuous improvement and leveraging autonomous capabilities that will exponentially improve how customers manage their reservoirs. Integral to the the company’s 4.0 digital oilfield strategy, the eCompletions system comprises multiple platforms – business development, operations, manufacturing, technology and ClaritiTM digital reservoir management – interconnected to share data seamlessly and deliver real-time solutions from ideation through to reservoir management. The customer-facing platform consists of five applications: Clariti View provides remote well data visualisation and parameter alarm setting while Clariti Flow delivers zonal flow allocation with fluid fractions. Clariti React, Manage and Predict

will provide full asset and production optimisation by leveraging the company’s petro-technical capabilities with the functionality provided by the SmartWell completion systems.

Data superhighways The company is rapidly moving towards further digital integration and expanding connectivity and communication across its intelligent completions technologies. The symbiotic relationship between sensor and telemetry technologies provides a focus for a multitude of solutions. In a forward-looking form, this combination creates the potential to fully automate the controls and management of reservoirs across wells, fields and entire assets. This focused application of advancements in downhole technologies will provide the capability of turning wells into data superhighways. These superhighways will allow operators greater access to information and control of their reservoirs, all connected back and tied into broader digital oilfield capabilities.

References 1.




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BURTON, R. C., GILBERT, W. W., NOZAKI, M., et al., ‘Multi-Zone Cased Hole Frac-Packs and Intelligent Well Systems Improve Recovery in Subsea Gas Fields,’ paper presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, US, SPE-187075-MS (2017). LILAND, G., PREBEAU-MENEZES, L., and MJOLHUS, S. J., ‘World’s First TAML Level 5 Multi-lateral Well with Individual Remote Inflow Control of Three Branches on Troll Oil Field,’ paper presented at OTC Brasil, Rio de Janeiro, Brazil, OTC-24427-MS (2013). GARCIA, E., STUTES, G., NÅDEN, C., et al., ‘Monitoring Dynamic Reservoir Pressure Responses Through Cement,’ paper presented at the SPE Annual Technical Conference and Exhibition, SPE-196168-MS (2019). BRECHAN, B., SANGESLAND, S., DALE, S. I., NAADEN, C., and BORGERSEN, K., ‘Well Integrity – Next Developments’, SPE-189403-MS (2018).

David Riffault, Toni Uwaga, Pablo Cifuentes, Adnan Khalid and Rémi Moyen, CGG, explain how multi-scale ensemble-based history matching was used to forecast production for a gas field in Asia.



roduction forecasting is a basic requirement for planning the future development of a field, optimising reserve recovery and selecting the optimum location for new wells. However, the task can be challenging owing to the complexity of the reservoir and the scarcity of available data. Understanding uncertainty in the reservoir model is key, so stochastic methods that generate a range of model realisations are preferred for uncertainty assessment. However, this approach leads to a large number of models that can be cumbersome

to handle in a conventional workflow. As a result, CGG has developed a new technology that can help to optimise an existing reservoir model by maintaining a fine balance between all the elements being considered during the model building process and a field’s production history data. Multi-scale ensemble-based history matching is an efficient, automated approach that is designed to update a large set of model realisations in order to assimilate production data and hence provide a high-quality set of models tuned for production forecasting.

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Multi-scale ensemble-based history matching

the information contained in this ensemble due to spurious correlations and may create geologically implausible scenarios. To better preserve the information contained in the prior ensemble, CGG’s new EBMatch software applies the multi-scale ensemble-based optimisation method (MS-EnOpt). It breaks down the spatial properties of the prior ensemble (using a second-generation wavelet transform) into coefficients that are both localised in space and frequency and represent the information in the model at different scales, i.e. degrees of coarseness.4,5 Instead of updating the full prior ensemble frequency content, as EnOpt does, the first iterations of the multi-scale approach only update the subset of the coarse-scale parameters. Owing to the sparse representation property of the wavelet transform, the spatial properties are well represented using only this coarse subset (Figure 1). The simulated flow response of the model is greatly affected by changes at this scale without corrupting the ensemble (limiting the impact of the spurious correlations).6 Coarse-scale coefficients characterise large geological features, such as channels and depositional structures, while fine-scale coefficients characterise smaller structures often located around the wells, such as flow barriers and high-permeability layers. As the iterations progress, the parameterisation is gradually refined by introducing finer-scale coefficients to further reduce the mismatch. Only a few iterations are needed to integrate the model detail Figure 1. Second-generation wavelet decomposition and reconstruction of a grid porosity model provided by the fine-scale coefficients so using only the chosen-scale parameters. Top: the reconstruction of the porosity model using only the that the introduction of high-frequency coarsest-scale parameters. Owing to the sparse representation of the transform, geological features content, often associated with noise, are still clearly identified. Bottom: the full reconstruction of the model using all-scale parameters (equivalent to the original porosity model before decomposition). remains limited. Due to its simplicity and flexibility, ensemble-based optimisation, known as EnOpt, is a widely used method for history matching.1,2,3 It assimilates production history data into a set of model realisations, called a prior ensemble, which reflects the uncertainties and correlations between spatial properties (e.g. porosity, permeability and net-to-gross ratio) and can integrate many sources of information, such as well logs, geological knowledge and seismic data. Although EnOpt provides satisfactory history matches of the production data by updating the prior ensemble, it can corrupt

Assimilating geological, petrophysical and geophysical data

Figure 2. Generation of a seismic-constrained ensemble of models. First, a well-based model of porosity and Vshale is built from well logs and a conceptual model. Then, a petrophysical inversion is performed to assimilate impedances from a seismic stochastic inversion using a calibrated petroelastic model. The resulting ensemble is a set of porosity and Vshale realisations constrained by the seismic attributes and consistent with the petrophysics and the geology.

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The following case study discusses a gas field in Asia with over 20 years of production history. The reservoir is composed of variable-quality sands where porosity-preserving chlorite is present, which greatly affects the fluid flow. A static model of porosity and shale volume (Vshale), called a well-based model, was created from well log data. A depositional conceptual model was also used as a background trend to ensure the geological observations in wells were respected. To integrate the seismic data into the reservoir modelling workflow, stochastic acoustic inversion was run to generate 100 realisations of high-resolution impedance models. All wells were used for the stochastic inversion, with missing elastic logs estimated from the available

petrophysical logs using petroelastic models (PEMs). The PEMs were calibrated at well locations with a full suite of logs and using data from laboratory rock sample experiments. This set of 100 grid models of P-wave impedances (Ip), generated from the geostatistical inversion, matched both the acquired seismic and the well logs. The well-based geostatistical models and the stochastic inversion results were then reconciled using ensemble-based petrophysical inversion (Figure 2).7 Using the porosities from the petrophysical inversion as a background trend, 100 permeability models were modelled from a sequential Gaussian simulation (SGS). The petrophysical inversion generated models with a lower average porosity value when compared with the well-based model (Figure 3). Wells are mostly drilled in high-quality reservoir zones and are therefore not always representative of the entire reservoir. The assimilation of seismic data suggests the porosity is overestimated away from the wells in the well-based model.

Figure 3. Left: average porosity maps of the well-based model before petrophysical inversion, top, and

of one realisation (#13) of the petrophysical inversion, bottom. The circle highlights a decrease in the porosity away from the wells based on the information in the seismic data. Top right: the histogram of the porosity values around the wells shows the same distribution for wells and models before and after the petrophysical inversion. Bottom right: the histogram of the porosity for the entire grid shows a decrease in porosity for all models after petrophysical inversion.

Validity of the ensemble In order to quantify the quality of the resulting ensemble a flow simulation was performed (without any history matching) on the well-based model and on the 100 seismic-constrained models generated by the petrophysical inversion. When compared with observed bottomhole pressure measurements, the simulated pressures obtained by these flow simulations showed much better accuracy for the seismic-constrained models than the well-based model (green and grey curves in Figure 4). This is the result of the integration of the seismic attributes and rock physics studies during the petrophysical inversion, reducing the inter-well porosity values and improving the quality of the ensemble.

Assimilating production data After the prior ensemble of static porosity, Vshale and permeability models were carefully created from all available geological, petrophysical and geophysical data, a multi-scale ensemble-based history matching workflow was used. This ensured that the information in the model was not corrupted during the history matching.

Figure 4. Top: field gas production rate for the first 18 years of production. Red dots are the actual

production history. Bottom: W12 well bottomhole pressure is represented for the first 18 years of production. Red dots are actual pressure history. The green curve is the simulated result of the static model before the petrophysical inversion. Grey curves represent the 100 simulated models after the petrophysical inversion but before the history matching, showing that the match was improved by integrating the seismic data. The blue curves are the 100 simulated models after multi-scale history matching. History-matched gas production curves are a perfect match and are therefore stacked on top of each other.

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The production data used for the history matching were the gas production rate (GPR), as the primary data to be matched, and the well bottomhole pressure (WBHP), as the secondary data to be matched. Of the 22 years of production history available, only the first 18 years were used for history matching. This meant that the remaining four years could be used to quality control a pseudo-forecast from the models. A localisation area was defined around each of the eight producer wells to restrict property changes around them and hence further reduce the risk of spurious correlations. These areas followed a structural trend of 45˚(north east – south west) to honour the geological depositional model. A north/south sealing fault was used to divide the areas into two groups and assign each well to either the eastern or western part of the reservoir. This ensured wells located on the western part were not used to update the models on the eastern part. The size of the localisation changed according to the iteration scale: areas were larger for the coarsest scales and smaller for the finest scales. EBMatch iterations were run from scale 1 (coarsest) to scale 7 (finest). A perfect match with the GPR was achieved, and the bottomhole pressure match was also greatly improved (Figure 4).

Figure 5. Porosity map (layer 30 of 43) from realisation 8. On the right, the porosity is the final result from the multi-scale history matching, and it remains very close to the prior model on the left. Changes are only visible around the wells highlighted by the circles and are due to the last fine-scale iterations. Large-scale changes in the first iterations can only be seen when looking at the low-frequency content.

Quality control of the changes in the grid properties during the multi-scale history matching showed changes were mostly made in the coarse-scale content. The prior ensemble had therefore been well preserved with very little editing of the fine-scale content (Figure 5).

Forecasting To quantify the quality of the ensemble generated by the multi-scale ensemble-based history matching, a pseudo-forecast of the GPR for four years was made on both the prior ensemble and the multi-scale history-matched ensemble of models. The four years of production history that was excluded from the history match was used as quality criteria to evaluate the forecast results. The results of the pseudo-forecast test show the prior ensemble overestimated the bottomhole pressure (Figure 6), while a more accurate prediction of the pressure was achieved by the multi-scale history-matched ensemble.

Conclusion For this case study, the integration of multiple sources of reservoir information brought a significant benefit for production forecasting. First, an ensemble-based petrophysical inversion made it possible to create multiple reservoir property scenarios that were all consistent with the rock physics study, the geological model building and the geophysical data. Then, a proprietary multi-scale ensemble-based history matching workflow tool was used to integrate production data while preserving all previously assimilated information. This approach ensured that the models chosen as being the most representative of the actual reservoir were not only the ones with the best history match, but also the ones that respected all the available information with an effective integration of the seismic data into the dynamic workflows. This will produce a group of accurate forecasts going forward. Furthermore, this means that multi-scale ensemble-based history matching can be used to provide a range of forecast scenarios from an ensemble of models that incorporates the key uncertainties of the reservoir, effectively integrating different data sources – such as seismic, log and core data – and providing engineers with a deeper insight for field development planning and production management.

Acknowledgments The authors wish to thank KOC for permission to show the field data from this case study. Field data images courtesy of KOC.

References 1.




Figure 6. W12 well bottomhole pressure forecast (purple) over four years. Red and purple dots are well pressure measurement data. Top: the forecast is obtained using the ensemble before history matching, in grey, and before the petrophysical inversion, in green. Bottom: the forecast is obtained from the multi-scale history-matched ensemble. Only red values are used as a constraint for the history matching. This pseudo forecast presents a more accurate match of the last two purple values used for quality control.

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EVENSEN, G., ‘The ensemble Kalman filter: theoretical formulation and practical implementation’, Ocean Dynamics, Vol. 53, No. 4 (November 2003), pp. 343 – 367. AANONSEN, S.I., NAEVDAL, G., OLIVER, D.S., REYNOLDS, A.C., and VALLES, B., ‘The ensemble Kalman filter in reservoir engineering – a review’, SPE Journal, Vol. 14, No. 3 (September 2009), pp. 393 – 412. OLIVER, D.S., and CHEN, Y., ‘Recent progress on reservoir history matching: a review’, Computational Geosciences, Vol. 15, No. 1 (January 2011), pp. 185 – 221. GENTILHOMME, T., OLIVER, D. S., MANNSETH, T., CAUMON, G., MOYEN, R., and DOYEN, P., ‘Ensemble-based multi-scale history-matching using second-generation wavelet transform’, Computational Geosciences, Vol. 19, No.5 (August 2015), pp. 999 – 1025. DE LIMA, A., GENTILHOMME, T., RIFFAULT, D., ANYZEWSKI, S. A., and EMERICK, A. A., ‘Multi-Scale Ensemble-based Data Assimilation for Reservoir Characterization and Production Forecast: Application to a Real Field’, paper presented at OTC Brasil, Rio de Janeiro, Brazil, (October 2017). CHEN, Y. and OLIVER, D.S., ‘Multiscale parameterization with adaptive regularization for improved assimilation of nonlocal observation’, Water Resources Research, Vol. 48, No. 4 (April 2012). MOYEN, R. and GENTILHOMME, T., ‘Adaptive Ensemble-Based Optimisation for Petrophysical Inversion’, Mathematical Geosciences (October 2020).



Travis Bolt, NOV, USA, explains how electric fracturing will help operators usher in the next generation of performance while delivering responsible, cost-effective frac operations.


he oil and gas industry has undergone a significant transition over the past few years, as institutional investors which once viewed financial growth as the key to oil and gas investing are now focused on financial return and the way it is achieved. In order to attract today’s investors, operators have prioritised developing best practices that deliver on efficiency and lowering operational cost to increase profitability. In addition, these same investors are analysing oil and gas companies by their ability to implement environmental, social and corporate governance (ESG) business practices into their daily routine. This combination of market and social drivers has resulted in the evaluation of all operational aspects of energy extraction, and fracturing has not been exempt from that assessment, as it plays a significant part in the total cost of a well’s completion. As a result, service companies are seeing more pressure being exerted to evaluate new frac technologies.

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One such technology is electric fracturing (eFrac). eFrac systems remove the traditional diesel engine and transmission drivetrain that powers a frac pump and replaces them with an electric motor, similar to the transition that took place with drilling rigs years ago. As with any new technology, there are challenges that sometimes come with it. eFrac system operators are now identifying a preferred method of converting a fuel into an electric energy to drive their fleet, since electric motors do not consume fuel directly. While the eFrac systems may not be the best fit for all situations, under the right conditions they deliver both cost savings and ESG performance. With a nod towards the future of frac operations, NOV has launched its new Ideal™ eFrac fleet, designed to reduce greenhouse gases and lower the total cost of ownership for operators. The fleet provides an environmentally and socially responsible frac option that minimises sound and carbon emissions, offers a clean and simple rig up and significantly increases power density while maintaining the redundancy that efficient frac operations require. As an original equipment manufacturer (OEM), NOV focused on the equipment as an empowering technology that delivers on improvements for operations, health, safety and environment (HSE) and control. As part of the development process, the company applied expertise from its electric AC Ideal rig technology, as well as industry best practices to address issues such as electromagnetic interference and air conditioning, among others. This approach allowed the team to simplify the electrification process, reduce HSE risks through engineered solutions and deliver the full value of electrification.

Using intelligent electrical architecture and simplified drivetrains, developers built the Ideal eFrac technology on the foundation of several key components:

Pumps From electricity through high-pressure frac fluid, the Ideal pressure pumping unit is a fully integrated pump platform that withstands the rigours of frac operations. The system’s 5000 hp pumps deliver a higher power density that can reduce the frac fleet footprint by as much as 47% versus conventional frac equipment. Additionally, the simplified electrical architecture allows the system to be serviced much like traditional frac equipment, providing easier connect and disconnect features for service and maintenance without disrupting adjacent equipment.

Manifold The manifold system was designed to optimise the electric pressure pumping operation and reduce the complexity of rigging up and operating an eFrac system. The Ideal manifold provides 10 positions for 5000 hp eFrac trailers and two positions for conventional diesel frac trailers, offering operational flexibility and reducing potential non-productive time (NPT). The manifold uses intelligent connections such as interlocks, digital feedback and monitoring systems to ensure that electrical and mechanical rig-up is safe and efficient. The system requires the fewest electrical connections of any eFrac fleet in the industry while still supporting up to 50 000 hp for the toughest frac jobs.

Process plant A benefit of eFrac systems is that they are not strictly limited to high-horsepower pumps. Designed as a new perspective on the processing of frac fluids, the Ideal processing plant brings the value of electrification to frac operations through greater reliability, feedback and control. The process plant is a fully redundant system, both mechanically and electrically. The system replaces two conventional blenders on a single platform, feeding the most challenging frac jobs up to 150 bbl/min. As a fully integrated processing system, the fleet complies with the most stringent of silica regulations and is capable of conventional, slip-steam and simultaneous-frac operations.

Substation Figure 1. Ideal eFrac fleet is a fully electric fracturing system that offers a

new level of control, reduces total cost of ownership and lowers greenhouse emissions without sacrificing safety or performance.

The substation acts as the primary connection point between the electrical fleet and the power source. The company recognised that operators and service companies vary in their approach to power, ranging from electric power transmission (grid power), infield power, large turbines or multiple reciprocating generators. Focused on providing value in whichever power format the customer chooses, the system was designed to be power-source agnostic and IEEE519-compliant, allowing the fleet to be flexible in an emerging market with varying business models.

Building an advanced system

Figure 2. The Ideal fleet features SPM® QEM 5000, which is a 5000 hp pump that provides higher power density and contributes to the frac fleet’s smaller footprint.

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When considering disruptive technologies, the solution’s technical implications need to be evaluated and weighed against competing technologies. When examining conventional frac operations, companies are often confronted with the challenges of the high rate and high pressure of sand-ladened fluids, which drive a majority of the operational costs. These costs primarily fall within two areas – drivetrain and pump. From a drivetrain perspective, the Ideal eFrac system removes the need for reciprocating engines and transmissions by replacing them with a direct-drive electric motor. With minimal parts and


maintenance, the electric motor allows operators to move away from a 500 to 1500 hr maintenance cycle to a 20 000 hr cycle that significantly reduces maintenance costs and NPT. Additionally, a conventional fleet’s drivetrain, coupled with the mobility requirement of frac equipment, has historically limited the systems to 2500 to 3000 hp per trailer. Leveraging the high power density of electric motors, NOV developed the Ideal system with a 5000 hp road-legal frac trailer that reduces the number of bores on location by 50% and reduces high-pressure joints by as much as 89% when used with flexible connections. When looking at the unit’s overall weight-to-power ratio, the system supports a pump technology that meets the performance of the single electric motor’s higher power density. The system’s design depends on the motor and pump working together, and as a result it has evolved into an optimised solution that offers high levels of performance, mobility and reliability. Since a conventional gear ratio would require a much larger motor, the eFrac pump system’s gear ratio and lower torque translates to a lower overall weight, minimising the impact on the roads and community. As a net result of harnessing both pump and drivetrain technology, the Ideal eFrac system can positively impact the total cost of ownership. When implementing the fleet technology versus conventional frac fleets, an estimated 38% reduction in total cost of ownership can be achieved after six years of operation, and the savings continue to increase after 10 years and beyond.

Figure 3. Featuring a modular auger skid and onboard chemical system, the

Ideal eFrac processing plant replaces two conventional blenders on a single platform and delivers greater feedback and control.

When looking at other facets of costs related to a frac operation, they are not strictly limited to the drivetrain’s parts and maintenance. The system’s consumption of wellhead gas is a good example of measurable performance savings. When compared to conventional operations, the Ideal system’s use of wellhead gas versus diesel can reduce fuel costs from ~US$14.12 per 100 hp/hr to US$1.38 per 100 hp/hr, resulting in fuel savings of up to US$1 million per month for a 50 000 hp fleet at 79% uptime. The system burns wellhead gas to power the electric equipment, while conventional systems require diesel fuel to be trucked to the frac location to power equipment, during which operators flare gas. When consuming clean-burning wellhead gas, the gas can be piped directly to the location and consumed in its current form with minimal processing or filtering to power the equipment, making efficient use of gas that may have otherwise been flared. When conventional systems run on diesel, the oil must be produced, piped to a refinery, processed and then transported back to the location, with each step increasing the carbon footprint. In conjunction with diesel processing, transportation and burning, the action of flaring excess natural gas creates additional emissions. Considering these examples, the Ideal system can reduce carbon dioxide (CO2) by up to 71% based on a 24 hour operating period at 70% uptime while running at 10 000 psi and 90 bbl/min. In addition to decreased CO2 emissions, the system reduces the presence of nitrogen oxides (NOX), methane (CH4) and other major pollutants that are contributors to smog and the carbon footprint. Safety is always a high priority, and the Ideal eFrac system was designed to decrease risks and complexity in all areas. The company focused on minimising the number of fluid and electrical connections as well as eliminating complex cable routing to reduce the risks associated with electrical systems. A multilevel approach to electrical connections, including physical layout, hardware protections, control interlocks and HMI feedback, ensures that electricity is only provided when both hardware and operators are ready to receive power. These protections are essential during the rig-up process and operation. The electrical system uses monitored cable shielding and technology such as last-to make/first-to-break to ensure that it defaults to a safe state if something unplanned occurs during a frac job. The Ideal system’s safety features not only focus on the electrical platform, but personnel risks are also reduced through a fleet design that addresses fall hazards, silica exposure and lifting strains, to name a few. As a full-remote-operated fleet, the control system is not limited to pump-rate control. The system can also change flow paths, isolate units and provide all the functionality of boots on the ground from a safe, remote location. The remote operation capabilities are enhanced by intelligent machine monitoring and analytics that provide accurate information on the health of the equipment and allow for live feedback, as well as post-job analysis, providing advanced tools to reduce NPT and increase asset utilisation.


Figure 4. The Ideal mobile 5000-hp frac trailer delivers the power needed for challenging frac operations while reducing road traffic and carbon emissions.

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Fracturing is a costly and mechanically intensive operation, and the introduction of a technology platform that is both innovative and environmentally conscious is a significant step towards reducing total cost of ownership and simplifying the fracturing process. A comprehensive, streamlined solution gives operators an upper hand in a fast-changing pressure pumping industry. By reducing carbon emissions, decreasing disruption to the community and minimising trucking requirements related to equipment needs, systems such as the Ideal eFrac system will help those same operators usher in the next generation of performance while delivering responsible, cost-effective frac operations.



Caroline Linder, Weir Oil & Gas, USA, explains how longer lasting consumables are helping optimise future oil and gas operations.


he oil and gas industry is coming off of one of the most challenging years in history. The market has witnessed unprecedented disruption from every angle imaginable – companies experiencing declining revenues, renewable energy, an increase in sustainability governance and lower oil prices. The COVID-19 pandemic added a new, unanticipated obstacle to those existing difficulties, challenging operators and oilfield service companies to navigate the field while adhering to social distancing and face mask safety measures. Minimising operating costs is always at the front of the mind in the oil and gas industry. However, while the ‘new normal’ upends regular pumping schedules and jobs, it is even more critical to find new ways to contain operating costs.

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Working harder for longer Oilfield service providers and operators are pushing frac fleets harder than ever. As pumping hours have increased, with equipment regularly being pushed to run 18 – 22 hr/d, the increased challenges as well as expenditures necessary to perform a job have also multiplied. Today’s frac fleets can consist of as many as 20 pumps – that is 20 sets of consumables to support and replace. Operators and oilfield service providers simply cannot afford to lose any pumping hours to unplanned downtime. In today’s market, even scheduled routine maintenance can prove to have a negative impact on the bottom line. The relentless, hard-driving reality on-site today is steering operators to focus intensely on improving two key factors: pump utilisation and minimising pump maintenance downtime. Managing these two important variables continues to be an ongoing challenge for operators and oilfield service companies. However, it is possible to increase pumping hours while reducing downtime thanks to technological improvements. The continual evolution of equipment and key components helps companies carve out a competitive advantage, even during unparalleled times. Embracing and employing technological advances helps companies continue to drive down costs and non-productive time (NPT). Reliability is especially crucial when trying to reduce NPT and expenses because the current norm of continuous duty requirements, coupled with extremely harsh operating conditions, take a toll on equipment. When it comes to reducing expenses, the first area to re-evaluate is the one creating the greatest source of downtime and costs. Valves, seats and packing are one of the largest maintenance expenses on a frac site, and companies are naturally focused on reducing costs related to fluid end maintenance and downtime. These consumables impact the efficiency and reliability of frac fleets, as well as a company’s profit margin. Conventional seats can put operators at a disadvantage, due to their inherent sensitivity and fragility as well as short life expectancy. Stainless steel seat life can be shortened with washing and tungsten carbide seats easily shatter in the field, making in-field replacement virtually impossible. If there is one maintenance protocol crews would like to eliminate, it is pulling seats. Replacing seats and valves is one of the costliest expenses an oilfield service company can incur – and also one of the most frustrating.

New valve and seat design The new SPM® EdgeXTM valve and carbide seat represents a technological advance that enables oilfield service companies to significantly reduce maintenance and operating costs for this category of consumables. Its design utilises carbide inserts in key wear areas to increase average seat life by up to six times as compared to conventional seats. This means companies can experience a substantial reduction in seat replacement while minimising NPT and safety risks associated with replacing seats in the field. It is completely compatible with any fluid end and the seats are compatible with any valve. Installation sensitivity is reduced as a result of a strategic combination of carbide and stainless steel, meaning that companies gain the flexibility to replace parts in the field with standard tooling.

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Additionally, the valves last twice as long as conventional valves due to a novel design that increases the contact area of the strike face by 300% when compared to conventional designs. The use of proprietary urethane heads that increase resistance to sand abrasion, as compared to conventional valves, gives added longevity and cost-reduction benefits. The EdgeX has been proven in multiple basins, including the extremes of the Haynesville. With treating pressures as high as 12 500 psi, the Haynesville subjects frac equipment to some of the most extreme conditions of any play in North America. As such, pumping operations in the Haynesville often cause companies to experience shorter maintenance cycles and greater consumable expenses. One oilfield services provider operating in the Haynesville Basin wanted to reduce the costs and NPT of its multi-well pad operations. Pumping up to 650 000 lb/stage of highly abrasive 40/140 mesh proppant at pressures up to 12 500 psi was causing its steel valve seats to fail prematurely. The operator had to implement a 60 hour maintenance cycle to address the issue, resulting in significant materials and labour costs. SPM EdgeX carbide seats were installed to address these challenges. With the tungsten carbide insert technology, the carbide seats resist wear, cracking and washout while eliminating the risk of the seat shattering, which could damage the fluid ends – or worse, cause a catastrophic pump failure. The carbide seats allowed the oilfield services company to use its existing tapered fluid ends and valves, providing maximum operational flexibility. Despite the 12 500-psi treating pressure and highly abrasive sand, the carbide seats lasted nearly nine times longer than the previous seats. The pumping provider ran the carbide seats an average of 538 hours – the longest life of any seat ever used by the company in the Haynesville Shale. Compared to the typical 60 hours of seat life the oilfield service company previously experienced with conventional seats, the carbide seats provided 797% longer life, signficantly reducing maintenance touches, NPT and risk of injury on-site.

Conclusion Longer lasting consumables, especially seats and valves which comprise a large share of a company’s operating expenses, help oilfield service companies to build a better bottom line in many ways. This longevity effectively reduces downtime for maintenance, planned or unplanned, to increase pumping hours. Reduced maintenance helps companies also navigate the challenge of having reduced personnel on-site available to perform maintenance routines. This also reduces operating expenditures by minimising the cost of consumables. Today’s environment is placing a greater strain on oilfield service companies, impacting workforces and profits. Especially in turbulent times, operators and oilfield service providers must always look for ways to reduce NPT and operating costs. Technological advances are worthwhile investments, even in a downturn, if they increase longevity that ultimately improves the bottom line, profit margins and competitiveness.

Note Weir Oil & Gas was acquired by Caterpillar Inc. on 2 February 2021 and operates as SPM® Oil & Gas.

INNOVATING AGAINST THE GRAIN Adam Calvin, TETRA Technologies, USA, analyses sand recovery challenges and conventional methods.


oday, one of the toughest challenges in operating wells, whether oil or natural gas, is recovering the sand proppant and other particles from the flowback. Hard particulates cause costly damage to flowback equipment and downstream production facilities, which inevitably leads to production halts to make repairs or swap out components, not to mention the environmental impact of unplanned fluid releases. Further compounding the challenge of solids recovery is the ever-decreasing size of sand particles now widely used in frac operations; smaller particles are harder to separate from the flowstream but are just as damaging to downstream equipment – in many cases smaller particles can be more invasive and destructive.

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Even before sand nudged out the more costly ceramic and resin-coated materials as the preferred proppant in frac operations, cyclonic traps have been the most common method of sand management. Most of these cyclonic traps, however, are unable to generate the requisite level of centrifugal force to separate the finer particles. To redress the problem of fine particle removal has often meant adding filtration systems to compensate for inefficient cyclonic traps. But filter systems introduce unwanted pressure differentials that inhibit flow and production levels. Moreover, their screens must be constantly removed and cleaned out or replaced, and the denser the screen – to capture finer particles – the greater the pressure differential. Another common method of sand management is the static, gravity-based sand separator, which functions much like similar devices for separating oil, gas and water. Unfortunately, it too is inefficient, especially when the flowback contains oil emulsion. Achieving the necessary degree of sand recovery and flowstream purity often entails staging multiple sand separators and even pairing them with a filtration system. All this adds up to more equipment, more personnel, expanded logistics, a bigger footprint and higher costs.

Developing a new system

Figure 1. New 15 000 psi SandStorm advanced hydrocyclone technology ready to ship to Haynesville region, US.

A new development in hydrocyclones is the TETRA SandStormTM advanced cyclone technology, which is engineered to generate calculated centrifugal forces that separate the targeted particle sizes from the flowstream. The cyclone uses a proprietary design that maximises centrifugal forces, capturing the smallest of particles while remaining below the excessive velocities that can damage equipment. It has no moving parts, imposes no flow restrictions on the flowstream, has a smaller footprint than competing systems and is more efficient than conventional sand separators and other cyclonic traps, achieving up to 99% sand recovery.

Case study 1 – an oil well in the Permian Basin

Figure 2. The diagram of the side-by-side comparison of the SandStorm advanced cyclone technology and an alternative system in the Marcellus Shale highlights the significantly smaller footprint of the former.

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In West Texas, US, the SandStorm advanced cyclone technology was trialled in a 30-day, side-by-side comparison with a competing sand recovery system. One well was outfitted with the technology and another well was outfitted with another system. Downstream, both wellstreams were equipped with secondary stage filter systems to capture any residual sands and thereby gauge the effectiveness of the first stage of sand recovery. The difference between the two systems was significant. As the downstream filters revealed, the

competing system captured an average of only 45.55% of the sand from a total of 126 472 bbl of fluids, with a one-day peak of 60%. By contrast, the SandStorm technology captured an average of 96.63% of the sand from 132 889 bbl of fluid, with a one-day peak of 100% and multiple days at 98% and 99%.

Case study 2 – a gas well in the Marcellus Shale In Pennsylvania, US, another side-by-side trial was conducted comparing the cyclone technology with a different sand recovery system. Due to the high flowrate of the wells (up to 45 000 ft3/d) and the especially fine particulate, the first well was outfitted with two SandStorm units, each of dual configuration, with the flowback split between the two units. Downstream from the primary stage was another unit operating as a second stage to capture any residual sands. Additionally, each stage had a separate flush line, and the sand was weighed after each flush to gauge the operation’s efficiency. A second well on the same pad site was outfitted with three of a competitor’s large sand management units. The similarity in the two wells’ flowrate, sand volume and fine particle size allowed for an accurate comparison of sand recovery efficiency, impact on flowrate and time to flush the recovered sands (flushrate). As in the Permian trial, the SandStorm technology outperformed the competing system, recovering on average 99.4% of the sand from the flowback with a peak flowrate of 42 000 ft3/d and thus no constraint on production. So efficient was the primary stage that the second stage proved to be unnecessary and the downstream flowback experienced zero wash, thereby preventing abrasive damage to equipment and saving the operator as much as US$10 000 per well. Moreover, the flushtime of the cyclone

technology units was less than five minutes, considerably less than the 45 minutes required to flush the competing sand separation system.

Next steps In both trials, the operators were impressed with not only the near-100% efficiency of the cyclone technology, but also its considerably smaller footprint which, crucially, does not come at the cost of reduced capacity. In fact, a single unit in the Permian Basin successfully removed more than 34 000 lb of sand from a single well’s flowstream in a 24-hour period. Furthermore, the smaller size of the unit simplifies logistics, as a single truck can hold four SandStorm units but only one competitor unit – and reducing the number of truck trips lowers transportation costs and exposure to health, safety and environmental (HSE) risks. Additionally, with no moving parts, the simpler design and operation of the cyclone minimises hands-on maintenance, the potential for component failure and the associated risk and downtime.

Conclusion Today’s economic climate demands that operators and service providers intensify efforts for greater efficiency, more so than the downturn five years ago spurred. In fact, with the pandemic and consequent decline in demand for fuels weighing heavily on the price of crude oil and natural gas, the need for cost control and maximum efficiency in the industry has never been greater. In this climate, advanced cyclone technology can play an integral part in the quest for maximum efficiency, in terms of both operations and costs.

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xploration and production (E&P) operators often say that it is not a lack of data related to well performance that is the problem, but rather the lack of sufficient, actionable insights. In order to continue to drive margin improvement at the wellhead, finding ways to interpret data meaningfully and implement impactful changes based on those interpretations is key. Operations teams are running lean and struggle to find the time during their already busy days of data analysis and fighting fires to focus on production optimisation. So, the question for operators remains: how can they get more with their existing workforce? This is where digital oilfield technologies utilising artificial intelligence (AI) can make a difference. Leveraging over 250 million hours of labelled operations data, Ambyint delivers improvements to E&P outcomes and margins by combining physics and subject matter expertise with AI to automate and optimise production operations and engineering workflows across all well types. These solutions help operations teams scale their processes across large well populations by automating repetitive, manual tasks. AI can increase an operator’s workforce efficiency by at least 25% through actionable real-time information, early detection of well anomalies and autonomous setpoint changes, resulting in more wells being managed and optimised daily. Ultimately, E&P companies see production levels increase as high as 7% and operating costs drop as much as 30%, improving bottom line performance and answering the question of how to get more with their existing workforces. Additionally, when production optimisation solutions are implemented and operations become more efficient, other benefits come online, such as reductions in failure rates on rod lift wells and reduced greenhouse gas emissions on plunger lift wells. Ambyint has demonstrated these outcomes across major North American basins, providing proof points to other E&P companies wanting to achieve similar results. This article takes a closer look at these proof points.

Increased production An E&P operator in the Marcellus Shale, US, utilising legacy production optimisation tools to manage a field of horizontal, plunger lift gas wells had plateaued in driving further operational improvements. Many of the wells experienced production-impacting anomalies, well instability and unoptimised controller setpoints. The operator searched for technological solutions to optimise these wells further and increase production volumes. Ambyint deployed its plunger lift optimisation solution, InfinityPLTM, across the operator’s approximately 300-well asset, enabling enhanced analytics, physics-based insights and improved management of plunger open/close triggers and setpoints. By implementing the recommendations made by the software, the operator realised a 7% increase in production volumes as well as improved operational scalability (Figure 1).

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Ginger Shelfer, Ambyint, USA, outlines how advanced production optimisation technologies can deliver improved production volumes, lower operating costs and reduced greenhouse gas emissions.

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In another case study, an E&P operator in the Marcellus had over 30% of flowing and plunger lift wells producing below plan. With a field of more than 200 horizontal wells, the company saw lower production primarily due to wellsite anomalies. The company looked for capabilities to improve the scalability of their engineering and operations team, including alerts for when wells go off-plan, predictive maintenance and more centralised operational event tracking. Ambyint deployed its production assurance solution, SmartStreamTM, across the company’s wells, generating a decline curve based on historical production data, monitoring for off-plan conditions and utilising AI to detect anomalies impacting well performance. Engineers gained greater operational scalability with an early warning system for anomalies and better visibility into the production impacts of well interventions. The solution detected anomalies with an accuracy greater than 90%, resulting in quicker well interventions and higher production outcomes.

Reduced operating expenses Two-thirds of an E&P operator’s rod lift wells in the Eagle Ford, US, were overpumping, causing higher failure rates and excessive power consumption. Limitations on engineers’ time meant daily optimisation opportunities went unrecognised, leading the company to search for a technology solution to bridge the gap. Ambyint deployed InfinityRL across the company’s asset, establishing connectivity at remote well locations, providing high-resolution

dynamometer cards, delivering AI-based setpoint recommendations and automating controller updates. Engineers gained time back in their day by avoiding time-consuming data gathering and analysis. With automated well optimisation and greater span of control, engineers shifted their focus to other high value activities. Optimised production translated into a 6% increase in production volumes for underpumping wells, a 17% reduction in strokes per minute (SPM) and an 11% decrease in power consumption. In the Bakken, an E&P operator found that a significant percentage of their rod lift wells were underpumping, leaving revenue in the ground, while a majority of wells were overpumping, causing high failure rates and consequently deferred revenue. To gain optimisation scale across its wells, the company recognised the need for improved real-time operational visibility with anomaly detection, recommended optimisation opportunities and automated setpoint management. After deployment of rod lift production optimisation, engineers gained immediate access to well performance data spotlighting intervention needs and optimisation opportunities. After gaining confidence in the AI-driven setpoint recommendations over an initial period, the customer allowed the software to update setpoints automatically, ensuring an ongoing, full-field optimisation state. In addition to enhanced operational efficiencies, the operator realised a 6% increase in production volumes, 14% improvement in pump efficiency, an 11% reduction in rod strokes and 20% improvement in mean time between failures (MTBF) (Figure 2).

Reduced greenhouse gas emissions

Figure 1. Ambyint InfinityPL increased gas production volumes with improved management of plunger open/close triggers and setpoints.

An operator in Texas, US, had a field of 200 rod lift wells that were operating sub-optimally. Ambyint technology classified 65% of the wells as overpumping. This led to high electricity consumption, increased failure rates and inflated operating costs. The high electricity consumption also meant excess greenhouse gas emissions, which if lowered would align with the company’s corporate sustainability goals. Deploying a rod lift production optimisation solution into the field enabled the operator to make data-driven decisions with real-time performance data, receive AI-based setpoint recommendations and automate controller setpoint changes. Over a one-year deployment, approximately 1400 automated setpoint changes were implemented, allowing for closed-loop optimisation of existing control systems. With improved optimisation, the operator realised an 11% reduction in power consumption, a resulting 13% reduction in greenhouse gas emissions and improved engineers’ efficiencies, leaving more time to focus on additional, high value activities (Figure 3).

Delivering value in challenging times As history has shown, the oil and gas industry is highly volatile. This volatility challenges companies to explore advanced technologies costs and increased revenue, with the operations team exerting greater to enhance their oilfield operations with the focus on getting the most management control over more wells on a daily basis. out of producing wells for less. Operators that have embraced digital oilfield technologies utilising AI gain the additional opportunity to yield reduced greenhouse gas emissions that have broader environmental and even public relations benefits. AI-powered production and artificial lift optimisation solutions deliver sophisticated technology, automation and data science that help drive improved production volumes, generate increased cash flow, achieve greater returns, reduce greenhouse gas emissions and boost workforce efficiency and Figure 3. Ambyint’s technologies lower greenhouse gas emissions with production optimisation and setpoint management. productivity. Figure 2. Optimised production translated into less energy expended, lower

44 | Oilfield Technology Issue 1 2021


Dr Christina Wang, ABS, USA, demonstrates how machine learning can be applied to asset coating condition assessments.


sset management has been a core part of the safety and inspection practices of the oil and gas industry for decades. One of the major steps in the asset management process is inspection and asset condition assessment, which can be supported and improved by using digital technology. There is a new digital transition underway for condition assessments of material coatings. As the name suggests, asset management is a process that addresses the efficient management of an asset throughout its lifecycle. It includes creating a plan that helps operators reduce costs while increasing the asset’s operational efficiency, safety and reliability. This plan also helps create awareness about the health of an asset, and further supports a shared understanding of what decisions need to be made by management, and when.

So, how can machine learning (ML) support this process? To apply digital technology in inspection, offshore industries are benefiting from an expansion of the availability and use of remote inspection technologies (RITs). Their advantages, including safer, more efficient and lower cost procedures, have seen RITs – such as unmanned aerial vehicles, remotely operated underwater vehicles and robotic crawlers – used widely for inspection of offshore risers, mooring chains, cargo tanks and confined spaces. However, ABS is taking this one step further by looking at how artificial intelligence (AI) modelling can be improved through ML as a way of gaining a complete view of an asset’s health – for example, taking 3D image data sets from laser scans or creating 360˚imaging by stitch processing 2D images together.

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A critical task during any inspection is the coating condition assessment. The application of protective coatings to steel surfaces to prevent structures from corroding is well-understood, and the benefits clear in terms of reducing risks during operation. Proper maintenance of the coating leads to improved asset life extension, as well as reduced lifecycle cost, but the scale of the task is considerable when it comes to maintenance. The ABS Corrosion Detection application is a digital tool powered by ML for analysis of visual data. Already in service with clients for tank inspections, the tool amply demonstrates the potential of ML in the identification, analysis and detection of corrosion and coating breakdowns as well as quantification of the resulting structural deterioration. The company believes that there is significant potential for further applications of the technology and is actively exploring the next stage in its development, which includes 3D image assessments. This will enable safer, efficient and comprehensive remote visual inspections of the complete asset. The next phase of product development is being planned to increase the role of ML for expanded types of structural condition assessments to help address a new set of asset management challenges.

Gaining value from data-driven insight ML consumes large, complex data sets containing more variables than humans can process. Its data-driven methodology overcomes human limitations such as subjectivity and biases, and provides more consistent results that help operators make better maintenance and replacement decisions.

While visual inspections by properly trained and highly experienced surveyors continue to make up the majority of maintenance surveys, the growing use of RITs provides an opportunity to augment human skills with computing power. While it is true RITs can provide more convenient access for inspectors evaluating the condition of coatings on more flexible schedules, there are two major issues with the current scope of RITs.

Challenges RITs are potentially transformational in their approach to offshore inspection but can be challenging for inspectors when identifying potential coating failures, due to the large amount of data that these technologies generate. The second issue concerns the objectivity of the inspector during the decision-making process. Generally, for coating condition assessments, inspectors need to estimate the size and severity of each coating failure area, some of which are separated sparsely or with complex shapes in the structure, which are difficult to evaluate accurately through visual inspection. In addition, the accuracy of these assessments is often dependent on the inspector’s previous experience, as well as their familiarity with the different types of structures being inspected. While inspections demand a high level of experience from surveyors, these factors can potentially cause inconsistency during coating inspections. To overcome these challenges, ABS applies AI in an image recognition tool designed to aid inspectors in reviewing data of coatings applied to marine and offshore assets, and in making coating condition assessments. Phase One of this work focused on ballast tank corrosion and was completed in 2019, while a further development phase of the initiative was completed in 2020, which included the expansion and scope of the data used to train the ML tool. Where the pilot phase, Phase One, delivered a reasonably positive result using only a few hundred images, Phase Two, the development phase, included the processing of more than 30 000 images for enhanced accuracy.

Improving the development of machine learning Figure 1. Home screen of the ABS Corrosion Detection application.

Figure 2. Users create a project for a specific vessel and compartment.

46 | Oilfield Technology Issue 1 2021

ABS’s ML-based image recognition corrosion detection tool can automatically analyse input data, identify coating failure areas and grade the coating condition of the structure. Inspectors can use these results as references, just like the assessment scales from a coating guidance, to improve the validity of coating assessments. The tool can also be used during screening inspection processes, where it can be applied as a filter to identify and review areas of corrosion criticality and concern. The ML algorithm program utilises images taken from various types of marine and offshore assets and it can deal with various kinds of structural components, coating failures, lighting conditions, environment issues and rust. The problems to be addressed through the use of the image recognition tool, such as

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Figure 3. Original image and processed image with corrosion mask overlay. automatically identifying coating failures or evaluating the coating failure conditions in images or videos, can be considered as computer vision issues. Recently, many applications based on ML technologies have been widely used to deal with computer vision issues such as human face recognition, self-driving cars, medical image analysis and autonomous quality inspection in manufacturing. Unlike these applications, which have the task of discerning the differences between distinct shapes and forms, the challenge when using ML to assess corrosion on marine and offshore structures is that the targets in the images have complex shapes and colour differences. To achieve the best possible results, applications such as autonomy and facial recognition use ML algorithms called convolutional neural networks (CNNs), which exhibit strong performance in analysing images and videos. Throughout the development of the Corrosion Detection application, ABS used existing CNN models to evaluate the best models to use.

Interpreting quality data Besides model selection, another key action to help improve the performance of the CNN was to prepare a large dataset with high-quality data which needed to be properly labelled by subject matter experts. The CNN models used this data in the algorithm training process, applying the decision of subject matter experts to learn the labelled patterns and features, in what is known as a supervised learning approach. The database used in this part of the study consisted of approximately 32 000 images, taken from different types of structures, most of which are internal tank structures such as water ballast tanks, cargo tanks and oil tanks. The model was trained with a training dataset and was repeatedly tested until an acceptable performance was achieved.

Spatial intelligence The early development stages of the tool used inputs for image recognition with a single image. This provided a good assessment for the severity of localised coating failures, but ABS is looking to develop a solution with ‘spatial intelligence’ to evaluate the average coating condition of the entire area, such as a whole tank, or eventually an entire asset. The company is exploring how panoramic 3D modelling and 360˚ imaging technology might provide a solution for survey and inspection work. The tool in planning is a major improvement on the current offering where AI can only process 2D images. This will allow fast processing of a combination of multiple photographic images with overlapping fields of view that can produce a complete picture of large structures, from tanks to

48 | Oilfield Technology Issue 1 2021

topsides, to generate a 3D model. Once the 3D model of the entire structure is created, both the total coating condition and local coating condition can be more easily assessed. Moreover, this model can be combined with the structure of a digital twin and conditioned-based inspection concepts, where a change in coating conditions can be recorded and monitored over time.

Future vision Various development phases of this project have proven the value of using AI technology in the marine and offshore industry to support trained inspectors with a fast and reliable means to aid their decision-making processes during coating assessment tasks. Through data tests and case studies, it is proven that the ABS tool can provide reliable reference data and information to inspectors and surveyors in the field. It provides a ‘holistic’ scanning inspection process with RITs, and acts as an electronic coating evaluation guideline to aid inspectors. These tools and capabilities will continue to be improved. New data can be fed continuously into the training process to improve the capability of the tool and make it even more accurate and reliable. The company is now looking at how the scope of the tool can be advanced from tank corrosion assessments to other areas of structures, and also to improve coating assessments of other types of structures, including superstructures. The company is applying the technology to help evaluate defects such as fractures, tripping, indentations or other large structural deformations.

Eyeing the benefits A common question from clients is whether the algorithm is of sufficient quality to accurately assess the problem of coating failure. The accuracy of the ML algorithm for the grading task is exceeding 90% for test data used at the development stage. Comparison studies show the tool can match human judgment in general for the purpose it is developed for. The ML tool will mark areas of corrosion with colour and give a rating of the coating’s condition, based on which the client can make decisions. Work continues to make the tool more accurate for assessment of coatings, and conversations with clients are ongoing to customise the tool for their particular applications using images specific to their assets and structures. In the offshore industry, the ability to avoid unplanned downtime, repair costs and potential environmental damage is critical to success. ML application can offer operators enhanced safety, reduced operating costs and improved uptime. Faced with tougher operating regimes and cost sensitivities, ML application represents an opportunity to stay competitive as the need for companies to take more responsibility for the societies around them and the environment intensifies.

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here is always an element of risk when selecting chemistries to facilitate oil, water and gas separation, particularly if the test work is conducted using synthetic emulsions and foams created from dead oils and/or assumed brines, rather than freshly sampled, live, produced fluids. In some cases, such as a new field start-up, this is the only option for product selection testing. It is therefore imperative to ensure the test methodology is correct in order to maximise the likelihood of selecting separation products – such as demulsifiers and antifoams – that will provide effective separation performance for the produced fluids not just in the laboratory but in the live process itself. This article summarises the demulsifier and antifoam selection test work for a unique heavy oil start-up in the North Sea. The major focus is on the early selection work and field testing (using pre-production drilling samples), then the subsequent changes to approach and methodology used for further product selection work in order to improve upon the original recommended chemistries, with a particular focus on demulsifier and antifoam applications.

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Alan White and Robert Miller, Clariant, consider the evolution of selection methodology for heavy oil separation treatments.

Case study: North Sea Demulsifiers and antifoam chemicals are essential for separation of the oil, water and gas phases of emulsions and foams formed during the extraction of fluids from an oil reservoir. All oils, and subsequent emulsions, are uniquely different. The components and natural surfactants vary greatly, as do the conditions of extraction and processing, such as temperatures, pressures and production facilities. It is therefore standard practice, certainly in the case of demulsifiers, to conduct formulation and selection work on-site using freshly sampled fluids, in order to get as representative an emulsion as possible and therefore representative separation trends. In some cases this is just not possible, either due to lack of access to the field or, more often, because the field is new and has not started producing yet. In these situations there is often no choice but to conduct tests using a man-made emulsion from dead oil and synthetic field brine. This is far from perfect, as the emulsion is unlikely to be analogous to the true field emulsion and any chemical recommended as a result of this sort of testing is hardly likely to be the best possible demulsifier for the process.

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A good illustration of this issue is test work conducted for a new heavy oil development in the North Sea. As previously alluded to, new, yet to be produced developments require chemical recommendations, but it is impossible to test live fluids on-site. In this case, the initial recommendation had to be made without any test work at all as no fluids were available, but the operator needed to run a well test project. An initial set of ‘off-the-shelf’ products for a number of applications was recommended for the project, including demulsifier and antifoam chemicals. The result was a fairly successful well test programme. The demulsifier was found to separate fluids satisfactorily, although the performance of the original antifoam was below that expected while foam was found to be a major challenge. Samples of chemical-free crude oil were taken during the well test for further laboratory work and product development onshore. Demulsifier tests began with simple bottle testing, where the oil and water were shaken together to create an emulsion which was then treated with various demulsifier chemistries. Table 1. Water droplet size estimated distribution results Droplet size range (μm)

Estimated distribution (%)









8 – 10


10 – 20


> 20


Figure 1. Droplet size distribution (x 200 magnification).

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The results from this were fairly unsatisfactory, with many chemistries giving the same performance and untreated ‘blank’ samples also separating fairly easily. The emulsion created was not particularly stable and therefore unrepresentative.

Experimental In order to try to better simulate the true-life situation, the condition of the produced fluids during the well test was reviewed again. The dead oil being used for the onshore emulsion was different to the live oil, as all the co-produced gases had been lost as well as some of the lighter hydrocarbon components. The testing facilities available for the bottle testing did not allow for any artificial re-conditioning of the oil to try to more truly mimic the field composition; this was therefore not a viable route for improving the demulsifier test. Instead, focus shifted to the size and distribution of the water droplets within the oil phase. These parameters had been measured during the well test phase and therefore a reasonable composition of the emulsion in terms of water distribution was available. Using a submersible high shear mixer it was possible, after some trial and error, to create an emulsion with a similar water droplet size distribution as had been observed during the well test. This distribution is summarised in Table 1 and illustrated by the microscopy image in Figure 1. This emulsion was found to be very stable, showing only trace separation over a 48-hour period at the process temperature. Bottle testing was repeated using this new, more stable, emulsion. Separation trends, illustrated in Figures 2 and 3, were markedly different for the same products under the same test conditions. Demulsifier A, used for the well test project and therefore considered to be the benchmark product, was now found to be significantly slower at separating water than some of the other demulsifiers that had previously been found to perform as well as Demulsifier A at best. The tests using the emulsion created using droplet size matching identified a new product, Demulsifier G, as the most effective for resolving this particular emulsion. Demulsifier G was seen to separate the water from the crude oil more quickly and more completely than the original Demulsifier A, which was only able to remove approximately 75% of the water present. The antifoam application was more problematic than the demulsifier during the well test project. The original chemical recommended was a ‘best-in-class’ fluorosilicone product. This chemistry is typically the highest performing oil antifoam; however, throughout the well test this particular product was found to be ineffective across a wide range of doses. Standard foam collapse tests were conducted using sampled fluids at atmospheric pressure in a glass measuring cylinder sparged with CO2. The maximum foam height and time taken for the foam to collapse were measured for both untreated and treated samples. The results were fairly ambiguous, with little difference found between doses or different chemicals. It was suspected that the primary reason for the fluorosilicone chemistry being ineffective as an antifoam on this particular crude was due to the chemical not being suitably dispersed in the oil, and therefore not being able to reach the surface of the bubbles to destabilise the foam. This lack of dispersion may have been due to the large viscosity differential between the antifoam (5 cP) and the oil (approximately 1000 cP). Theories suggest that with viscosity differentials of greater than a factor of 10, the lower viscosity fluid will be encapsulated by the higher viscosity fluid and very little dispersion can occur, even in turbulent systems. One way

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to overcome this phenomenon would be to use a higher viscosity antifoam to address the problem as a physical issue, rather than a chemical one. This theory was not proven in the standard foam collapse test; however, when the opportunity to try another antifoam product at the new field arose it was decided to go with a much higher viscosity polydimethylsiloxane product (350 cP) despite conventional wisdom suggesting that this type of antifoam is less effective than the fluorosilicones. The result of the trial was very different; the polydimethylsiloxane was found to be much more effective at knocking down the foam produced in the process and, therefore, was selected for use at the field. A successful recommendation is of course always welcome, but if the successful result could not be replicated using the standard antifoam test procedures then there was clearly

something not optimal with the procedure commonly used. It was this question that then led to a test method development project being undertaken in order to find a method to assess foaming characteristics and antifoam performance more in line with real-life conditions. The most obvious difference between the standard test method and the real-life situation is that the tests are usually conducted using ‘dead’ crude at atmospheric pressure. In the process, the crude is ‘live’ and under pressure – it is indeed the depressurisation of the crude that causes the gases to break out of the crude and create the foam. In the laboratory test, gas is merely sparged through the crude to try to create a foam which, with heavier crudes, can be very difficult. The solution to these differences was therefore to try to bring the crude oil ‘back to life’ and to try to create the foam in the same way as in the process, through depressurisation. Recreating ‘live’ crude can be achieved fairly simply by sparging gas through the oil under pressure in order to saturate the crude. The pressurised ‘live’ crude was then depressurised rapidly and it was found that significant quantities of foam were created. Using this method, it was possible to then test the efficacy of different types of antifoam chemistries at reducing the foam created when the live crude samples were depressurised. With these tests it was possible to better differentiate performance between chemicals on the heavy crude and, more significantly, it was demonstrated that the higher viscosity polydimethylsiloxane was more effective than the low viscosity fluorosilicone product. This gave some validation to the test method, as it reproduced the result observed in the field trials.


Figure 2. Comparison of water separation trends at 60˚C with 20% water


Figure 3. Separation trends for droplet size matched emulsion treated with different demulsifiers after 2 hours at 60˚C.

54 | Oilfield Technology Issue 1 2021

Clear variances in performance of demulsifiers were found between test methodologies. Simple, basic bottle tests using dead oil were not able to demonstrate significant performance differences between several demulsifier types, with all candidates showing similar performance to an ‘off-the-shelf’ product previously used during a well test exercise. Matching the emulsion more closely with that produced during the well test did, however, yield different trends to the original tests, highlighting significant performance differences between demulsifiers and identifying a better performing product for the next stage of the field development. Likewise, with the antifoam application, the initial recommendation of the ‘best-in-class’ chemistry was found to be ineffective in the field and the standard laboratory test was again unable to differentiate performance between other chemistry types, even though an alternative product had been subsequently seen to be effective in the field. Retrospective test development was able to demonstrate that saturating the dead crude with gas then rapidly depressurising was a far more realistic way of creating foam and therefore of testing the efficacy of antifoam chemistries; the new test was able to replicate the performance differential seen in the field between the original recommended product and the product tested more successfully later on. This all leads to the fairly unsurprising, yet all too often ignored, conclusion that test methodology and conditions are crucial when selecting production chemicals such as demulsifiers and antifoams. It is not enough to merely have the ‘best’ chemistries; it is also essential to know how to test them in a representative manner. Performance trends observed in tests using dead oil can be wholly unreliable if no efforts have been made to re-condition the fluids to be more truly representative of the fluids actually produced in the oilfield.

g t n h i e p p Ti n i s e l a sc operators' favour

Tom Swanson, Solugen, USA, considers two scale inhibitor solutions that can positively influence the treatment of produced water from source to disposal or reuse.


any midstream operators in the major oil basins have traditionally been relying on acid-based solutions to prevent scale in produced water handling systems. The use of these measures presents challenges that include high corrosion rates and presence of hydrogen sulfide (which can lead to equipment failure), hazards to employees (corrosive acids and sulfide gas) and environmental exposure (spills).

Solugen is deploying a different strategy for produced water: oxidation with corrosion and scale control with BioPeroxideTM and BioChelateTM technology. This methodology removes sulfide gas, reduces corrosion, reduces environmental hazards and improves the overall operation of the produced water facility. Previously, operators using oxidative technology faced challenges in terms of scale, which was detrimental to flow assurance even with benefits.

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To address the operators’ challenges in product selection and efficacy, the company has created a field methodology and process that allows operators to identify the risks in the field and apply the right technology with a means to monitoring results. The key in this produced water strategy relies on the use of oxidiser-compatible scale inhibitors. BioChelates and BioPeroxide solutions are being deployed in key basins to reduce operational costs, reduce the environmental risks and improve the overall health, safety and environmental (HSE) aspect of produced water handling.

corrosion and impurities that may adversely affect the transport or final use for the water from disposal to repurposing.

The problem

Disposal water in the US shale plays can contain high concentrations of precipitating ions, which are known for contributing to oilfield scales. Calcite, barite, gypsum and iron sulfide are common scales shared among many basins, but waters containing strontium and other metals can also contribute to other scales in produced water handling. Scale formation in salt-water disposal (SWD) systems can be Objective detrimental to efficient operations, from pipeline transfer to tank Typical produced water handling can involve a settling process storage and final injection in disposal wells. followed by microfiltration to remove insoluble and soluble A common methodology in midstream water handling is components prior to injection or water reuse. Chemicals and to introduce acids to reduce the effects of scale formation electrochemical processes may also be deployed to enhance and maintain dissolution of the scale-contributing cations in the mechanical purification process. In oil and gas operations the aqueous phase. The benefits of a low pH system in water the objective is to condition produced water to reduce scale, disposal systems are the reduced risk of scale blockages, filtration requirements and lower overall injection pressures. This low pH strategy does pose drawbacks in terms of metallic wetted parts, which can be affected by corrosion in both the liquid and vapour phases of process equipment. For example, when inhibited hydrogen-based acids are used the liquid phase can be protected, but vapour phases become challenging unless vapour phase inhibitors can successfully be deployed, which adds additional costs to the overall operation. The corrosive nature of the acid bearing water can reduce the lifetime of injection pumps, metallic tankage, pipelines, valves and other critical parts. When these critical parts fail there is downtime to the operator, exposure to the environment and the cost to repair, remediate and recommission. Figure 1. Transition process from oxidation to advanced oxidative stable chelation. Another challenge to water operators in low pH acid systems is when these solutions are employed Table 1. Test water analysis via inductively coupled plasma atomic emission spectroscopy in the presence of pre-existing iron sulfide scales, (ICP-AES) which can result in the liberation of hydrogen Test Sample A Sample B Sample C sulfide gas. Iron sulfide can form upstream of the pH 6 6.47 6.11 treatment regime and require the addition of acids Bicarbonate as to remove the deposits prior to injection to prevent mg/L 95 171 268 HCO3 plugging. The net result of iron sulfide dissolution Carbonate with acids is the formation of hydrogen sulfide gas. mg/L 0 0 0 alkalinity Hydrogen sulfide gas is heavier than air and poses TDS (calculated) mg/L 33 580.80 55 623.50 91 867.30 health risks at low concentrations. In separation Density g/cm3 1.025 1.040 1.065 and settling tanks, low concentrations of hydrogen sulfide gas that diffuse from the aqueous phase can mg/L 0 0 0 H2S accumulate in the head space of a tank, resulting in Carbon dioxide mg/L 150 110 130 concentrations well above the inlet stream over time. Chloride (Cl) mg/L 19 778.10 33 546.20 55 759.60 To reduce the potential for scale, corrosion Sulfate (SO4) mg/L 20 0 80 and hydrogen sulfide, produced water handlers Borate (B) mg/L 722.40 480.30 487.30 are looking to the use of oxidation chemistry. The oxidation process removes hydrogen sulfide gas Sodium (Na) mg/L 8786 16 490 27 130 and forces the precipitation of metals, which in turn Potassium (K) mg/L 118.60 282.50 580.90 purifies the water for processing. The drawback Magnesium (Mg) mg/L 143.10 368.10 890.30 to oxidation chemistry is the solids handling. In Calcium (Ca) mg/L 3052 3791 6076 open pits and settling tanks designed for dredging, Strontium (Sr) mg/L 745.50 460.40 556.20 oxidation can be very effective and economical. Many of the produced water handling systems and Barium (Ba) mg/L 73 23.10 15.70 SWD systems do not have this capability to handle Total iron (Fe) mg/L 46.40 9.30 22.40 solids; a solution is therefore needed to prevent the Manganese (Mn) mg/L 0.742 1.601 0.913 onset of scale.

56 | Oilfield Technology Issue 1 2021

The approach of this study and historical case history was the application and utilised in the formulation phase to prevent to deploy an oxidiser-compatible chelant to bind metals and the onset of precipitation when utilising an oxidiser, so as to create a water soluble non-oxidising complex. Chelants are neutralise hydrogen sulfide as a precautionary operational known for their function of forming multiple bonds with metals measure. that enhance the stability of the complex. The complex formed Based on scale index modelling, and confirmation that scale is based on a water-soluble backbone (chelant), which prevents would precipitate in the presence of oxidation, BioPeroxide the metal from forming insoluble structures known as scale. and BioChelate formulations were prepared to evaluate the net Chelants are wide in terms of description, and many are not effect on filtration as a predictive tool for injection in this SWD oxidiser stable and can dissociate upon contact with oxidisers, system. The selection process chosen was a modified filtration changes in pH and, in some cases, atmospheric conditions. method to allow for field deployment and monitoring. A 0.45 μm When deploying a chelant, there are additional criteria microfiltration filter was chosen to enhance the selection process that may be required by the operator. Chelants in general and identify potential scale-liquid bridging, which can adversely have an affinity for specific metal ions based on the chelants’ affect an operator’s filtration and injection. The portable unit structure and composition. In many cases chelants are combined with corrosion inhibitors, surfactants Table 2. Test water scale prediction via ScaleSoftPitzer and threshold inhibitors to address numerous Sample A Sample B Sample C challenges with one product. The second part of Scale prediction this study involved developing a method that could Initial Final Initial Final Initial Final be deployed in the field to design, compound and Temperature 100˚F 100˚F 100˚F 75˚F 100˚F 75˚F monitor performance from processing to injection. Pressure 15 psi 800 psi 15 psi 800 psi 15 psi 800 psi In the case presented, a BioChelate was chosen based on its effectiveness on calcium and iron-based 1.07 1.23 0 0 0.58 0.72 Barite (BaSO4) SI scales, which are known to be problematic for Barite (mgL) 42.33 44.16 0 0 18.90 21.05 the salt-water operator. The BioChelate is based on an oxidised sugar and is co-produced with Calcite (CaCO3) SI (0.31) (0.71) 0.50 0.09 0.60 0.19 hydrogen peroxide in a manufacturing process which inherently provides an oxidiser stable molecule. Calcite (mgL) 0 0 55.79 12.38 105.68 40.54 The produced water utilised in this study was based Gypsum (CaSO4) on a Delaware Basin water known for challenges in (1.83) (1.87) 0 0 (1.28) (1.32) SI handling and injection, due to scale and the presence of iron scales. Gypsum (mgL) 0 0 0 0 0 0 In Figure 1, an analogous water depicts the Anhydrite effects of oxidation in the presence of scale-forming (1.98) (2.13) 0 0 (1.40) (1.56) (CaSO4) SI cations. On the left is a sample of untreated water with biomass and hydrogen sulfide present. After Anhydrite (mgL) 0 0 0 0 0 0 treatment with BioPeroxide (middle) the sample Celestite (SrSO4) becomes cloudy and the onset of precipitation is (0.74) (0.79) 0 0 (0.61) (0.66) SI initiated. When BioPeroxide is combined with the BioChelate a stabile colloidal suspension is formed Celestite (mgL) 0 0 0 0 0 0 in the presence of oxidation, which is noted in Halite (NaCl) SI (2.61) (2.59) (2.12) (2.10) (1.66) (1.64) the far-right bottle.


Halite (mgL)







Test waters supplied were indicative of acidification, as noted in the lower pH ranges. Sample C did not reflect dissolved hydrogen sulfide due to sample ageing, but operations noted ranges above 10 ppm in the tank headspace and in the surrounding area. Barite and calcite were noted in the scale modelling and required chelation and threshold inhibition to prevent precipitation (Table 1). Post inductively coupled plasma atomic emission spectroscopy (ICP-AES) analysis, the data was modelled via ScaleSoftPitzerTM to quantify which prevailing scales would be expected to influence filtration (Table 2). Based on the output, barite and calcite were noted to be the prevailing scales. Strontium levels were elevated and can be common in SWD operations; non-sulfate bearing chelants were therefore utilised in the BioChelate to prevent the onset of strontium sulfate scales. System temperatures and pressures were varied to expand

Iron sulfide (FeS) SI







Iron sulfide (mgL)







Iron carbonate (FeCO3) SI







Iron carbonate (mgL)







Table 3. Filtration tests (0.45 μm filter with time at 3 minutes based on 100 mls) Sample

Acidified regime (mls/min)

BioChelate and BioPeroxide – 25 and 50 ppm

Sample A inlet

70 (3:00)

100 (1:04)

Sample B inlet

85 (3:00)

100 (0:50)

Sample C inlet

40 (3:00)

70 (3:00)

Issue 1 2021 Oilfield Technology | 57

utilises a vacuum pump, and the aliquot sample size is reduced to 100 mL with a filtration time of 3 minutes. The objective of this method is to reduce testing time (pre-oxidation of samples) and benchmark volume and time. This rapid test methodology was effective when comparing produced water samples on-site to minimise the effects of oxidation in atmospheric sampling processes.

Discussion The results of the microfiltration testing indicated that converting from an acidified water treatment regime to an oxidative cation-controlled regime would improve the injectivity performance in some cases by over 50% (Table 3). In samples A and B, the maximum throughput was achieved in less than half the time of the acidified counterpart. The use of BioPeroxide also prevents the potential exposure to hydrogen sulfide, and the prevailing elemental sulfur from the oxidation process did not overshadow the improved filtration at 0.45 μm. The BioPeroxide and BioChelate were co-applied at 25 and 50 ppm respectively to the samples without acidification to compare the results.

Application The work from the study is a case model for applications where traditional acid programmes are utilised. This methodology was deployed with an oil and gas producer in the Delaware Basin that was experiencing excessive filtration costs, iron scale deposition and black water in the SWDs. The operator was managing multiple SWD facilities that were handling over 360 000 bpd of water.

Post-validation of the laboratory simulation, microfiltration and scale modelling, the operator was assured oxidative induced scales would not affect injection and could be maintained at required concentrations with the use of a combined oxidiser and scale inhibitor. The BioPeroxide and BioChelate were applied on the SWD system, replacing high-cost traditional acid treatment programmes. The application was shown to control hydrogen sulfide and black water, and reduced filtration while maintaining differential pressure across the system with monitoring via the microfiltration method. The results in 5 – 7 days returned each facility to optimum operational performance, with an estimated annual OPEX saving to the customer of over US$3.5 million/yr on a 15 000 bbl average for each of the disposal sites. Annual treatment per facility resulted in a projected US$175 000 annual saving or reduction in costs of US$0.03/bbl of water, which includes chemicals, manpower and material charges. Based on the results of the study, application data and economics, there is optimism for reducing the chemical demand for water treatment when considering acidification to prevent scale. BioPeroxide and oxidatively stabile BioChelates are two solutions that can positively influence the treatment of produced water from source to disposal or reuse. The former allows operators to remove hydrogen sulfide gas, which is unsafe and corrosive to equipment, and deploy an oxidiser stable scale control solution to prevent reduced injectivity challenges. The latter affords produced water operators the assurance of maintaining and improving injection performance in harsh scaling regimes.

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