MAGAZINE | WINTER 2023
Maximizing Asset Value Halliburton Multi-Chem delivers superior service and chemical application expertise to maximize asset value.
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Contents
10 2023 In The Asia Pacific
Winter 2023 Volume 16 Number 04
24 Multi-Use, High-Density Fluid Systems In
Angus Rodger, Wood Mackenzie, Singapore, reviews the past year in the Asia Pacific region’s upstream sector.
A
The North Sea
Richard Hay, TETRA Technologies, USA, explores the applications and benefits of high-density fluid systems.
28 The Golden Era Of Drill Bit Innovation Tom Roberts, Alex Benson and Jessica Stump, NOV, USA, discuss how innovations in PDC cutters and drill bits are helping to transform the drilling market.
10
14
No Mess Left Behind Mark Venables, Envorem, UK, discusses how technologies such as cavitation can help minimise the environmental impact of industry activity in the North Sea, as oil and gas companies look towards the energy transition.
18
28
A New Lubricant Design Matthew Offenbacher and Richard Toomes, AES Drilling Fluids, USA, outline how new chemistry in drilling fluid lubricant technology could help create opportunities to extend pipe life through improved wear mitigation.
32 Enhancing Well Integrity And Production Efficiency Seamus Jacobs, Dexon Technology PLC, Thailand, discusses the benefits of well casing in-line inspection systems in the oil and gas industry.
37
Ida Christiansen, ChampionX Norge AS, Norway, discusses how emulsion viscosity reducers are tackling the issue of slugging in offshore assets.
Front cover Halliburton Multi-Chem provides chemical solutions for traditional and unique oilfield challenges. The company’s value proposition is to deliver superior service and application expertise to help customers maximise asset value.
Removing The Sluggish Feeling
40 Safeguarding Subsea Cables
MAGAZINE | WINTER 2023
Viper Innovations, UK, explores the risks of unmonitored cables and copper loss in subsea electrical systems.
44 The Unsung Hero Of Subsea Systems Maximizing Asset Value Halliburton Multi-Chem delivers superior service and chemical application expertise to maximize asset value.
Alistair Mykura, Castrol, UK, discusses the role of all-electric and hydraulic systems in today’s subsea sector.
47 Find Your Flow Ken Feather, TGT Diagnostics, UAE, explains how innovative acoustic array technology for well and reservoir flow dynamics can drive major operational benefits.
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ISSN 1757-2134 Copyright © Palladian Publications Ltd 2023. 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 Emily Thomas, Deputy Editor
Winter 2023 Contact us
emily.thomas@palladianpublications.com
T
his year’s UN climate change conference, COP28, is well underway in the UAE, following a year of extreme weather patterns and broken climate records. Business leaders, government officials, and climate scientists have gathered to discuss solutions to limit the global temperature rise, as well as the future of fossil fuels. So far, the conference has seen a record number of delegates from the oil and gas industry in attendance this year, as well as the launch of an oil and gas decarbonisation charter, which has been voluntarily signed by over 50 companies. The charter is based around speeding up climate action and making an impact across the sector. Woodside Energy was one of the associations eager to show its support. Meg O’Neill, the company’s CEO, said: “Signing the charter reinforced the company’s existing commitments to reducing carbon and methane emissions and to investing in the products and services customers need, as they do the same.” O’Neill continued: “Signatories to the charter have committed to net zero operations by or before 2050, ending routine flaring by 2030, and near-zero upstream methane emissions.” Oil and gas majors are therefore agreeing to “best practices, goals of emissions reduction, and improved transparency through enhanced measurement, reporting and verification of greenhouse gas emissions,” demonstrating their role in speeding up the transition to cleaner energy.1 Whilst making efforts to clean up its act in terms of the energy crisis, the industry has also made strides to improve the health and safety of workers. According to the API, the sector is seeing a declining rate of illness and injury, and is becoming increasingly safer.2 While the oilfield, by nature, is a hazardous work place, measures have been taken to mitigate risks to workers through training, information sharing, and ongoing research into safety practices. Where the industry may be lacking, however, is in its approach to the mental health of its workers, with professionals stating that a proactive approach to safeguarding not only workers’ physical wellbeing, but also their emotional wellbeing, is vital. Kick Sterkman, Group HSEQ Director, Neptune Energy, recently observed that workers would never be without their hard hat or protective overalls to shield them from harm; why then are there not the same precautions in place to combat the mental challenges of workers, should they arise?3 In a recent report from International SOS involving thousands of oil and gas workers in the UK, poor mental health was found to be the number one reason for sickness absence.4 A study from Oxford Academic also uncovered that oil and gas industry workers appear to suffer from anxiety and depression more acutely than the rest of society, which could be due to a number of stressors within the occupation, such as isolation, intense pressure and workload, and fatigue from working long hours.5 The longstanding view of the oil and gas industry as a male-dominated and ‘macho’ sector has also done little to encourage workers to be open about their problems. The sector may, however, be starting to turn a corner. The International Association of Drilling Contractors (IADC) has created a mental health and wellbeing charter, which includes contributions from psychologists, contractors and operators, and hopes to improve support for the mental health of onshore and offshore workers. Through work such as this, frameworks are created that can be followed across the industry, offering new approaches that could bring mental health education, training and improved awareness to the fore.6 It is time that the oil and gas industry underwent a cultural makeover in order to support itself from the inside out.
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*References are available upon request.
Winter 2023 Oilfield Technology | 3
The Center for Offshore Safety (COS) supports companies in offshore natural gas and oil operations globally to develop, implement and improve their Safety and Environmental Management Systems (SEMS).
COS is now issuing SEMS Certificates for international oil and gas operations and wind operations around the world.
Join the COS mission:
www.CenterForOffshoreSafety.org
Copyright 2023 – Center for Offshore Safety, all rights reserved. Center for Offshore Safety and the COS logo are either trademarks or registered trademarks of the Center for Offshore Safety in the United States and/or other countries. API Global Marketing and Communications: 2023-134 | 08.11 | PDF
World news
Winter 2023
Wood secures two-year contract extension with Equinor Wood has secured a two-year contract extension with Equinor UK Limited to support safe and reliable energy production at the Mariner field in the UK North Sea. Wood will continue to provide operations, maintenance, modifications and offshore services on the Mariner A platform and Mariner B floating storage unit, as well as delivering front-end concept and feasibility studies, detailed design, construction and commissioning services for future project developments. In addition, Equinor continues to utilise Wood’s digital capabilities and experience to optimise efficiency across Mariner’s operations. Ellis Renforth, Wood’s President of Operations in Europe, Middle East and Africa, said: “We are proud to further strengthen our relationship with Equinor through this contract extension. As a trusted delivery partner, we will continue to provide operations, maintenance and engineering support, critical to energy security.” “The contract extension is testament to the quality of delivery by our teams both onshore and offshore, applying innovative, sustainable ways of working, utilising our enhanced digital capabilities to ensure safe, reliable and consistent operations across the Mariner field.” Wood has a longstanding partnership with Equinor, supporting global projects, including long-term contracts in Norway and Brazil, as well as Equinor’s renewable energy business in the UK. The Mariner field is located approximately 150 km east of the Shetland Islands in the northern North Sea and is expected to produce more than 300 million boe over the next 30 years, contributing towards reliable energy supply and security. The contract will continue to be delivered by Wood’s team in Aberdeen and offshore North Sea.
Aramco produces unconventional tight gas from the South Ghawar operational area Aramco has successfully produced the first unconventional tight gas from its South Ghawar operational area two months ahead of schedule. This development supports Aramco’s strategy to increase gas production by more than half, over 2021 levels, through 2030, subject to domestic demand. Commissioned facilities at South Ghawar have a 300 million ft3/d of raw gas processing capacity and 38 000 bpd of condensate processing capacity. In response to growing demand for gas, the company will continue its work to more than double the overall processing capacity in order to achieve South Ghawar’s strategic goal of delivering 750 million ft3/d of raw gas in the near future. Nasir Al-Naimi, Aramco Upstream President, said: “This first production of unconventional tight gas from South Ghawar is a milestone that demonstrates real progress on our gas expansion strategy, which we believe has a role to play in meeting the kingdom’s needs for lower-emission energy and supporting growth in the chemicals sector. The ability to commence production two months ahead of schedule and below budget is testament to the unwavering dedication of our people and their determination to continuously enhance our upstream operations.” Successful production of tight sand gas at South Ghawar represents Aramco’s second unconventional gas stream, after production commenced at the North Arabia field in 2018 with the delivery of 240 million ft3/d to customers in Wa’ad Al-Shamal. Work is simultaneously progressing at the giant Jafurah unconventional gas field, which is the largest liquid-rich shale gas play in the Middle East.
Eni celebrates Baleine start up The President of the Republic of Côte d’Ivoire Alassane Ouattara, and Eni CEO, Claudio Descalzi, met in Abidjan to celebrate production start-up from the Baleine field, situated off the eastern coast of Côte d’Ivoire, and to review Eni’s activities in the country. Eni and its partner, Petroci, initiated production from Baleine in August this year, achieving a time-to-market of less than two years from the discovery. Oil production from Baleine stands at 20 000 bpd, far exceeding the initial anticipated 12 000 bpd. The project is set to reach its plateau of 50 000 bpd by the end of 2024, upon completion of the second development phase; full field development is expected to enable the production of up to 150 000 bpd. Baleine’s gas production is entirely destined to the domestic market, strengthening access to energy in Côte d’Ivoire. Furthermore, the project is the first net zero (Scope 1 and 2) development in Africa.
In brief Australia
w
BiSN has opened a new manufacturing facility in Perth, Western Australia, to better serve operators in the region. The facility will increase the operational capacity for BiSN in the Asia-Pacific region, creating several local jobs.
Canada TotalEnergies has completed the sale of the entirety of the shares of TotalEnergies EP Canada Ltd. to Suncor, comprising its participation in the Fort Hills oil sands asset and associated midstream commitments. The consideration for the transaction is CAN$1.47 billion (about US$1.1 billion), with an effective date of 01 April 2023.
Nigeria Equinor and Chappal Energies have entered into an agreement for the sale of Equinor Nigeria Energy Company (ENEC), which holds a 53.85% ownership in oil and gas lease OML 128, including the unitised 20.21% stake in the Agbami oilfield, operated by Chevron. Equinor has been present in Nigeria since 1992 and has played a significant role in developing Nigeria’s largest deep-water field, Agbami. Since production started in 2008, the Agbami field has produced more than 1 billion boe, creating value for the partners and the Nigerian society.
Guyana CGX Energy Inc. and Frontera Energy Corporation have announced the discovery of a total of 114 ft (35 m) of net pay at the Wei-1 well on the Corentyne block, approximately 200 km offshore from Georgetown, Guyana. It is believed that the rock quality discovered in the Maastrichtian horizon in the Wei-1 well is analogous to that reported in the Liza discovery on Stabroek block.
Winter 2023 Oilfield Technology | 5
World news Diary dates 20 – 22 February 2024 Subsea Expo
Aberdeen, UK www.subseaexpo.com
05 – 07 March 2024 SPE/IADC International Drilling Conference & Exhibition Texas, USA www.drillingconference.org
06 – 09 May 2024 Offshore Technology Conference Texas, USA www.2024.otcnet.org
10 – 13 June 2024 85th EAGE Annual Conference & Exhibition Oslo, Norway www.eageannual.org
Web news highlights ÌÌChevron announces US$16 billion 2024 CAPEX budget
ÌÌNPD urges companies to explore proven gas resources on the Norwegian shelf
ÌÌWoodside Energy becomes signatory to oil and gas decarbonisation charter
ÌÌOutlook for investment discussed at The North Sea Transition Forum
ÌÌTotalEnergies announces the signing
of cooperation agreements to reduce methane emissions
To read more about these articles and for more event listings go to:
www.oilfieldtechnology.com
6 | Oilfield Technology Winter 2023
Winter 2023
Neptune Energy awarded ‘gold’ standard for methane reduction plans Neptune Energy has announced that it has been awarded gold standard status by the United Nation’s Environmental Programme (UNEP), recognising the company’s detailed plans to reduce methane emissions to near zero by 2030. The gold standard award was provided by the Oil and Gas Methane Partnership 2.0, a voluntary initiative launched by the UNEP, and was featured in the UN’s newly-published International Methane Emissions Observatory (IMEO) report. The report provides detailed global emissions data which is helping inform action plans to tackle methane levels, and to track progress against commitments made by companies and governments. Neptune Energy’s Director of Global HSEQ, Simon Taylor, said: “Neptune has one of the lowest methane intensities in the oil and gas sector at 0.02%, in comparison with the industry average of 0.15%, and we’re on track to achieve our target of near zero methane emissions by the end of this decade.” “We have put in place detailed plans to cut emissions from our operations and are committed to transparent reporting. That includes employing the latest technologies and best practices to identify and reduce methane emissions, eliminate routine flaring and upgrade equipment at our sites.”
AGR wins well management contract offshore Guinea Bissau AGR has secured a well management contract with Apus Energia Guinea-Bissau S.A. for a deepwater exploration well in the Sinapa license offshore Guinea-Bissau, with drilling set to commence in the summer of 2024. The Ocean BlackRhino ultra-deepwater drillship has been contracted by Apus Energia Guinea-Bissau S.A. for the upcoming drilling campaign. AGR’s scope will be executed by its well project management team based in Perth, Western Australia. In this project, AGR will provide consultancy in well construction, drilling engineering, procurement, supply chain management, and operational supervision of the drilling. Earlier this year, AGR became part of the ABL Group, the Oslo-listed global energy, marine and engineering consultancy. In the course of the acquisition, AGR joined forces with Add Energy, another well engineering company within the ABL Group. “We are pleased to be working on this exciting project in West Africa, which is a testament to our commitment to excellence... We are eager to bring our expertise to this project and further strengthen our position in the industry,” said Lynden Duthie, AGR’s Well Management MD. “We welcome AGR to join our drilling and well experts in delivering a long-awaited well in the southern part of the MSGBC basin with significant hydrocarbon potential. We hope this project will contribute to developing our future cooperation with ABL Group,” said Eyas Alhomouz, Apus Energy’s CEO.
Production begins from BP-operated Seagull field in the North Sea BP has successfully started production from the Seagull oil and gas field in the UK North Sea, boosting energy supplies, supporting the supply chain and jobs, and underpinning continued production from an offshore facility that has been operating for 25 years. Seagull has been developed by Neptune Energy as a subsea tieback to the BP-operated central processing facility (CPF) of the Eastern Trough Area Project (ETAP) in the central North Sea, around 140 miles east of Aberdeen. The project supported 800 jobs through the development phase. Seagull is the first tieback to the ETAP hub in 20 years. The field is located 10 miles south of the ETAP CPF and is a four-well development. Production is delivered via a new three-mile subsea pipeline which connects to an existing pipeline system. A new 10-mile umbilical has been installed, linking the ETAP CPF to the Seagull field, providing control, power and communications services between surface and seafloor.
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World news
Winter 2023
Malaysia records over 1 billion boe of exploration discoveries in 2023
Wood Mackenzie: President Elect, Javier Milei, to shake up Argentina’s oil industry
PETRONAS and its petroleum arrangement contractors have recorded 19 exploration discoveries and two exploration-appraisal successes, contributing over 1 billion boe of new resources for Malaysia in 2023. This achievement was the result of an intensified exploration programme pursued in the last few years, which saw the drilling of 25 wells – the highest number of exploration wells drilled in a single year since 2015. More than half of the discoveries were made in the Sarawak Basin, primarily in two clusters within the Balingian and West Luconia geological provinces. Among the notable discoveries are Gedombak-1, Sinsing-1, Machinchang-1 and Mirdanga-1 by PETRONAS Carigali Sdn Bhd (PETRONAS Carigali), along with Babadon-1 and Chenda-1 by Thailand’s PTTEP. Three discoveries were made in the Northwest Sabah Basin. Layang-Layang-1 by PETRONAS Carigali, as well as Hikmat-1 and Dermawan-1 by PTTEP proved a working petroleum system that unravels new opportunities in the ultra-deepwater and deepwater areas. Another drilling campaign is ongoing within the same proven basin in the shallow waters off the coast of Sabah. Two other discoveries were made within the Malay Basin. Hibiscus Oil & Gas Malaysia found gas in Bunga Lavatera-1 well nearby the PM3 hub, and brought it onstream with a flowrate of about 50 ft3/d within the same year. PTTEP found oil and gas in Simpoh Beludu-1, having penetrated the hydrocarbon-filled reservoir in the deeper Group K sands. PETRONAS Senior Vice President of Malaysia Petroleum Management (MPM), Mohamed Firouz Asnan, said, “This significant exploration success validates our belief that there is more potential within the so-called matured Malaysia’s basins, using new 3D seismic data and the latest software technologies to better detect deeper hydrocarbon potentials.”
Addressing the election of Javier Milei as President of Argentina, Adrian Lara, Principal Analyst at Wood Mackenzie, said, “Elected President Javier Milei and his advisors are signalling the importance the oil and gas sector has in their plans for the overall Argentinian economy, however, their success in deregulating the sector and attracting more investment is still predicated on an effective and timely correction of the macroeconomic imbalances of the country.” According to Wood Mackenzie’s analysis, Milei’s administration will focus on the importance of unlocking Vaca Muerta volumes and will approach this from a platform of slashing public spending, dollarising the economy and privatising state companies, in particular, YPF. During the last week, shares of YPF have gained about 40% in value. “For YPF, domestic operators and foreign IOCs, Milei’s market-oriented policies are likely to be a net positive,” said Raphael Portela, Principal Analyst. “Lifting of capital controls, for instance, will help with the import of rigs and related equipment, which has been a development bottleneck for some time. Removal of import-export taxes and oil price caps is also expected, potentially helping unlock sales and future investments. Other campaign promises, such as a lower tax burden, would improve the industry’s bottom line.” However, despite the business-friendly agenda, Portela notes that an outright sale of YPF is unlikely. “A parallel can be drawn with Brazil’s President, Bolsonaro, who also promised the privatisation of Petrobras,” said Portela. “In practice, many political hoops stand in the way. Instead, we expected an emphasis on disposals to be the middle ground. The sale of non-upstream assets is more likely, especially in the fertilizer, gas and power, and downstream segments. Smaller, non-core upstream assets could also be considered, though finding buyers could prove challenging.” Other challenges will persist, noted Portela, such as the loss of gas subsidies from the previous administration and continued difficulty in infrastructure debottlenecking.
Saipem awarded two offshore contracts Saipem has been awarded two offshore contracts, one in Guyana, and the other in Brazil, worth approximately US$1.9 billion. The first contract has been awarded by ExxonMobil’s subsidiary ExxonMobil Guyana Limited, for the proposed Whiptail oilfield development located in the Stabroek block offshore Guyana, at a water depth of approximately 2000 m. Saipem’s scope of work includes the design, fabrication and installation of subsea structures, risers, flowlines, and umbilicals for a large subsea production facility. Saipem will perform operations using its art vessels FDS2, Constellation, and Castorone, and will deploy as key fabrication site for its execution model Saipem’s Guyana offshore construction facility located at the Port of Georgetown, enhancing a sustainable steady growth in the country. Subject to the necessary government approvals, the project sanction by ExxonMobil Guyana Limited and its Stabroek block coventurers and an authorisation to proceed with the final phase, the award will allow Saipem to begin some limited activities, namely detailed engineering, and procurement. The second contract has been awarded by Equinor for the Raia project, the development of a pre-salt gas and condensate field in the Campos Basin, located about 200 km offshore the state of Rio de Janeiro in Brazil.
8 | Oilfield Technology Winter 2023
Kenera secures new orders from Arabian Drilling for key drilling technologies Kenera has secured a contract to deliver five top drives and five iron roughnecks to Arabian Drilling for new build rigs to operate on a major project in Saudi Arabia. This order follows a previous contract for five top drives awarded in September and further increases the installed base in the Middle East while highlighting Kenera’s commitment to providing technology and drilling solutions to major rig operators in the region. Delivery of the contract includes the design and manufacture of top drives from Kenera’s rig equipment business, Bentec. With its proprietary software, the Bentec top drive optimises the drilling process and ultimately helps reduce well delivery times. Arabian Drilling will also benefit from remote monitoring and troubleshooting provided through Bentec’s digital service platform. The contract bolsters the long-standing relationship between Kenera, as the original equipment manufacturer (OEM), and Arabian Drilling, that enhances drilling operations performance through the application of key rig technologies.
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10 |
Angus Rodger, Wood Mackenzie, Singapore, reviews the past year in the Asia Pacific region’s upstream sector.
T
his year has been an exciting and event-laden rollercoaster for the upstream industry in the Asia Pacific region. 2023 has seen both big deals and big discoveries, plus
some key fields move closer to commercialisation. This article discusses countries around the whole region, outlining the key trends and events for each in the past year, and what to look out for in 2024.
South East Asia – coming back into the frame After a few years of less newsworthy activity, some significant stories in key producing countries have lifted sentiment and raised South East Asia’s profile. Indonesia is a good example of this, where 2023 was very much a year of two halves. By the end of the first half, upstream investments were well below the annual target of US$15.5 billion, and resource replacement ratios were only at 53% of the 2023 goal. It was looking like another year of missed opportunities. Then, some much awaited good news filtered through. In July 2023, a consortium of PERTAMINA and Petronas acquired Shell’s 35% stake in the huge INPEX-operated Abadi field for US$650 million. The same month, Eni acquired all of Chevron’s deepwater IDD assets, and then acquired Neptune’s in-country assets.
| 11
These transactions have the potential to revitalise Indonesia’s upstream sector by unlocking previously stranded resources and putting them into the hands of better-aligned joint ventures (JVs) that are keen on spending those development dollars. More big news was to follow. Eni announced the results from its Geng North exploration well in the deepwater of the Kutei basin, near to its producing assets and recent acquisitions. With initial estimates of approximately 700 million bbl of recoverable resources, the gas-condensate field is not only Indonesia’s largest find in years, but also the largest discovery of 2023 globally (as of October). Perhaps most importantly, it is in the hands of an operator with the means and know-how to bring it onstream as quickly as possible. As the year draws to a close, attention shifts to Mubadala’s high-impact Layaran well in the Andaman Sea off Northern Sumatra. A big discovery there would make 2023 a year to remember for Indonesia’s upstream sector. Malaysia was also a hotbed of upstream activity throughout the year, and in particular the province of Sarawak. New gas finds were
announced by PTTEP and PETRONAS Carigali, the latter not revealing much in the way of details, but hinting that the company might have found something significant. Shell’s Timi field started up, and bigger key fields such as Kasawari and Jerun moved closer to first production. Sarawak was also the hub of M&A activities, with PETROS buying Shell out of the Baram Delta area, and a sales process having been launched by the SapuraOMV JV, with Austrian player OMV likely to exit the country in late 2023 or early 2024. There was also some less than positive news. PETRONAS officially halted operations of the ill-fated Sabah Sarawak gas pipeline (SSGP), cutting off Sabah gas fields, such as the Kebabangan cluster, from supply into Sarawak’s Bintulu LNG plant. This, in turn, squeezed producing Sarawak fields to make up the gap. While the current pipeline of under-development gas projects looks strong (Jerun, Rosmari, and Marjoram are all coming on stream over the next few years), 2023 FID is not expected at PTTEP’s giant Lang Lebah field. There, the timeline has slipped in-part due to lack of clarity over the treatment of CCS, despite the Malaysian government granting CCS tax incentives earlier in the year. The narrative now focuses on those countries that did not make as much progress in 2023 as planned. Vietnam was poised to be a country to watch, with a new petroleum law coming into effect (which would improve the overall investment environment), a potential new licensing bid round, its first LNG regassification terminal coming online, and the possible sanction of the long-awaited Block B gas project. In reality, progress was slower than hoped. The new petroleum law has been implemented but with little initial impact, Block B did not make FID, the bid round has not yet been announced, and the country has yet to agree on any long-term LNG contracts despite commissioning the LNG regas facility. With rising power demand and a long-term goal to wean itself off coal, can Vietnam make up for lost time in 2024 and give the upstream sector some much needed positive momentum? The energy crunch was even more acute in Thailand, where the country has struggled with declining domestic supply and falling pipe imports Figure 1. Asia Pacific block awards by country/year, and total number of E&A wells drilled. from Myanmar. This has forced it to bridge the gap Source: Wood Mackenzie Lens. *Well data excludes China. with increasing imports of costly LNG. The outlook from Myanmar is not positive in the face of political instability and shrinking corporate participation. Pressure has therefore been rising on the Thai NOC, PTTEP, to raise gas output at home. It took over operatorship for the key gas assets G2/61 (Bongkot) and G1/61 (Erawan) from international oil company (IOC) partners and has set itself ambitious production targets. With significant drilling activity across 2023, the next 12 months will be a crucial indicator of where Thai gas production will go next. In more positive news, the country awarded two new blocks to PTTEP (G1/65 and G3/65) and the G2/65 acreage to Chevron, in its 24th licensing round. The Malaysia Thailand Joint Development Area (MTJDA) also offers a glimmer of hope. With two key licenses there in the process Figure 2. Upstream M&A by deal value (US$billion), Australia vs the rest of Asia Pacific. of being extended, this should unlock new gas Source: Wood Mackenzie.
12 | Oilfield Technology Winter 2023
resources for development. However, the biggest undeveloped resources sit in its overlapping claims area with Cambodia. With Thai gas demand on the rise, 2024 could see more positive news flow around government-to-government talks in order to start to resolve the dispute.
Australasia – a red hot market
Over in Australia and New Zealand, politics really came to the fore in 2023, with mixed results for the upstream sector. A case in point was Australia, which has long traded on a reputation as a low-risk and reliable investment destination. However, multiple changes and interventions to gas market regulations, fiscal terms, emissions reduction targets and environmental approvals have put the country onto a more unpredictable path. This has culminated in the current crisis in regulatory approvals, with delays and confusion around the process of consultation for federal offshore environmental plans (EPs) with the regulator NOPSEMA. This has impacted every aspect of offshore operations in the sector. As a result, big post-FID gas projects such as Barossa and Scarborough are struggling to remain on time and budget as court cases challenge already approved activities. Unfortunately, there is no clear resolution in sight. However, even the most unstable regulatory, legal and fiscal landscape seen in Australia for over a decade did not stop 2023 from delivering a record volume of upstream M&A. Over US$7billion has been spent on upstream transactions year-to-date. Private equity, TotalEnergies, ConocoPhillips, CPC and Japanese E&Ps were amongst those who showed their confidence in Australia by acquiring upstream assets. The biggest news in New Zealand’s upstream sector was OMV’s decision to divest its in-country portfolio, as part of a total Asia Pacific upstream exit. If a sale occurs, it will be the first transaction under New Zealand’s amended Crown Minerals Act, revised in 2021. The tightening of these laws was a direct consequence of the government being left to cover abandonment costs for the offshore Tui field, after its operator went into receivership. The subsequent stricter stipulations for operators, especially around abandonment liabilities, are still being assessed. The government has been vocally against oil and gas in recent years, banning new offshore exploration permits from 2019. However, the path through the energy transition is not a smooth one, and with rising electricity demand and falling domestic gas production, the country is now considering LNG imports. Following the win of the centre-right National Party over the Labour Party in the 2023 national elections, all cards are back on the table, and it will be interesting to see what political messages are sent to New Zealand’s dwindling upstream sector in 2024. In Papua New Guinea, the key event was TotalEnergies entering FEED for its Papua LNG project. Feedgas will come from the onshore Elk/Antelope field. The plant will have four electric-drive trains, with a total capacity of 4 million tpy, and FID is expected in the first half of 2024. This helped spark M&A – in September, state NOC, Kumul Petroleum, agreed to buy a 2.6% stake from Santos in the ExxonMobil-operated PNG LNG. Santos also granted Kumul a call option for a further 2.4% interest.
The Indian sub-continent – interest rising
India’s vast energy market holds many attractions – not just scale and growth, but also a compelling decarbonisation narrative, as gas
is required to displace coal. However, for this switch to work, more domestic production is required to reduce reliance on expensive LNG imports. In recent licensing rounds, there has been limited interest from large IOCs in Indian exploration. However, this began to change in December 2022, when the government opened vast swathes of offshore acreage for exploration that were previously no-go areas. Several other fiscal incentives were also introduced. This seemed to be working – state ONGC signed MOUs with ExxonMobil, TotalEnergies and Chevron to jointly investigate deepwater opportunities. However, in 2023, license rounds were launched and to date, no big new country entrants have been announced, with many citing ongoing concerns over above-ground legal/fiscal risks. However, this could change in 2024, as the terms are further refined and strengthened. It is a similar story in neighbouring Bangladesh. Demand for gas has grown much faster than domestic supply, leaving the country with an energy shortfall. In 2018, Bangladesh began importing higher cost LNG. Like India, the country has been working hard to improve its fiscal terms. In July 2023, the Cabinet signed off on a new offshore PSC with higher gas pricing (linked to Brent) and improved terms. In H2, TGS and SLB began acquiring multiclient offshore 2D seismic data, and state NOC Petrobangla is expected to launch an offshore licensing round in late 2023/early 2024. With one supermajor, ExxonMobil, reportedly already showing some interest in direct negotiation for open deepwater blocks, this could be another licensing round to watch in 2024. Switching focus to Pakistan, there is an exploration scene that gets few airwaves, but is still actively looking for new gas resources. As with India and Bangladesh, the government is keen to edge out as much expensive imported LNG with cheaper domestic gas as it can. It launched a bidding round for 18 onshore blocks in 2023, but only three were awarded. Undeterred, in H2 the authorities offered up another 10 onshore blocks, and, unusually, 12 offshore blocks. Another 12 offshore blocks in the Indus basin will be released in June 2024. There has been limited offshore exploration activity in Pakistan, with only four wells been drilled in the Indus since 2004. The last wildcat, Kekra-1 drilled by Eni in 2019, was dry. With the country’s gas production forecast to decline at an annual average of 10% over the next decade, and onshore exploration having little impact in denting that trajectory, Pakistan may need to think what other levers it can pull to attract more exploration investment.
China – going deeper
In China, the domestic NOCs are focusing on drilling in search of new resources. The year saw two wells spudded that aimed to go down beyond the 10 000 m mark. With the low-hanging fruit now exhausted, Chinese companies are fully committed to finding and developing deeper resources. In recognition of these increasingly challenged reservoirs, national and state governments are offering bespoke fiscal incentives. In 2023, the Xinjiang provincial government offered subsidies for incremental gas output within the province, rising higher if firms exploited CBM, tight and shale gas. The central government also extended a shale gas resource tax reduction through to the end of 2027. This has helped accelerate the development of deep shale in the Sichuan Basin. As volumes of Chinese shale gas continue to rise, the associated infrastructure continues to grow. PipeChina has started to build a second Sichuan-East pipeline, running from the gas fields in the Sichuan basin all the way to the cities of the east coast.
Winter 2023 Oilfield Technology | 13
Mark Venables, Envorem, UK, discusses how technologies such as cavitation can help minimise the environmental impact of industry activity in the North Sea, as oil and gas companies look towards the energy transition.
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T
he North Sea oil boom of the 1980s created huge revenues for both the United Kingdom and Norway, but now that the successful era is over, the decommissioning and clean-up operation is commencing. Owners of the offshore oil and gas infrastructure, including wells, are starting out on the road to decommission assets in accordance with statutory requirements and remediate the marine environment consistent
with government policy. Decommissioning is costly and will span several decades. It requires careful financial planning from infrastructure owners. The Brent Field facilities, installed in the early 1970s and operated by Shell on behalf of Shell and Esso Exploration and Production UK (Esso), lies off the north-east coast of Scotland, mid-way between the Shetland Islands and Norway. It was
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one of the largest fields in the North Sea and was served by four large platforms – Alpha, Bravo, Charlie, and Delta. Each platform has a topside which is visible above the waterline and houses the accommodation block, helipad, as well as drilling and other operational areas. The topsides sit on much taller supporting structures, or legs, which stand in 140 m of water, and serve to anchor the topsides to the seabed. For Brent Alpha, the ‘legs’ are a steel structure or jacket, while for the other platforms, the legs are concrete structures with a complex of storage cells at the base. The four installations support topsides that house the accommodation block, helipad, drilling and other operational areas. The support structure at Alpha is a steel jacket weighing 31 500 t. The support structures at Bravo, Charlie and Delta are concrete gravity base structures (GBS) weighing more than 300 000 t each. The Bravo and Delta GBS comprise 16 reinforced concrete tanks, called cells, that were used to store and separate crude oil before export. On Charlie, the GBS comprises 32 cells; 10 were used to store and separate oil and the other 22 were used to provide additional ballast. The field is served by 103 km of pipeline and four small seabed structures which are part of the pipelines system. The cells of the GBS are made of concrete just under 1 m thick, reinforced with steel bars. On Bravo and Delta, the cells are circular and approximately 60 m tall and 20 m in diameter, and on Charlie, the cells are rectangular and approximately 60 m tall, and 13 m by 13 m. Of the total of 74 cells in the GBSs, ten serve as the bases of the legs, 42 were specifically designed for safe oil storage, two contain conductors and 20 contain circulating cooling water. The cells formerly used for oil storage typically now contain a layer of crude oil (called attic oil) at the top of the oil storage cells, a layer of interphase material, a large intermediate layer of water, a layer of sediment comprising a mixture of oil, sand particles and water, a 22 m thick concrete diaphragm covering the sand ballast, and finally a 14 m thick layer of sand ballast.
An end of life plan
In 2006, as the platforms in the Brent Field approached cessation of production, Shell invited Professor John Shepherd to establish a group of specialists to review the various studies that Shell would undertake to enable the company to prepare for the responsible decommissioning of the Brent Field. Professor Shepherd invited a number of experts to become members of an independent review group (IRG), which started its work on 30 January 2007. The final report from the IRG was released in February 2017. In the final report, the IRG recommended lifting the platforms off the legs and returning them back to shore. The legs and undersea tanks were left in place with a GPS transmitter on top to warn ships not to get too close. Six years ago, the first of the platforms to be removed was the 24 200 t Brent Delta. The operation was conducted by Allsea’s Pioneering Spirit, the largest construction vessel ever created, and the platform was transported 700 km to Able Seaton Port facility in Hartlepool. Two years later, the Brent Bravo platform underwent a similar process. Finally, Brent Alpha, the only one of the platforms which featured a steel jacket standing in a depth of 140 m below sea level, was successfully removed through a two-stage operation across 2020.
Leaving an environmental blight as a legacy
Since 2017, when the IRG published its report, environmental concerns have been of great concern both at a governmental and societal level. In this light, some of those earlier decommissioning decisions could be subject to review. Leaving the Brent field leg and
16 | Oilfield Technology Winter 2023
subsea tank structures in place which contain 49 000 m3 of sludge in the legs and tanks, and 61 000 m3 of drill cuttings on the seabed below the three platforms, would today be questioned. According to the report, “leaving the drill cuttings and cell contents in place means that about 22 000 m3 of hydrocarbons would remain after decommissioning. However, although it is uncertain, the risk of environmental impacts of these should be local and are not likely to extend beyond about 2 – 3 km from the platforms.” Note that 22 000 m3 of hydrocarbons equates to 136 000 boe. The recent spill of just 200 bbl in March 2023 in Poole was declared a “major incident”.1 However there are a further 184 platforms in the North Sea that will eventually need to be decommissioned. Adopting a similar strategy would seem ill-advised if environmental damage is to be kept to a minimum.
Searching for a viable solution
The problems facing decommissioning in the North Sea are not unique and also affect the Middle East where there are a large number of sludge lagoons, many of which are an unfortunate legacy from the Gulf War where a number of oil wells were destroyed and left to spew oil out over the desert. The UN gave the national oil company of Kuwait US$2 billion to clear it up, but to date they have only cleared around 10% as they cannot find a suitable technology. Addressing the treatment of oil-contaminated sand is of huge interest to oil companies worldwide. A British company has developed an innovative new ‘green’ technology that uses a little-known property of water to process production sludges, cleaning the solids and recovering the entrained oil, all without generating emissions. The technology combines established techniques with hydraulic shock and cavitation, where bubbles are created by the vaporisation of water, a phenomenon copied from the natural world. Cavitation can be generated ultrasonically, electrically, or physically, and is widely known as a parasitic effect that destroys propellers on ships and the impellers of pumps. The collapse of cavitation bubbles is so powerful that it liberates fragments of metal from the surfaces. These forces are harnessed to drive oil contamination out of sludges and solids using less than 10% of the energy required for thermal treatment techniques. The technology was proven in Oman by the National Oil Company (PDO) to treat sludge and oil-contaminated soil. The technology generates a fraction of the emissions of thermal treatment and is both cheaper and faster. 99% of the oil was removed from sludge as crude of usable quality, reducing the need for extraction and its associated carbon footprint.
Conclusion
The North Sea has been a powerhouse for oil and gas production for 50 years, but as the focus moves on to its environment impact, it is critical that the legacy from those years of production is not an environmental inheritance. As the oil and gas companies themselves transition towards a fossil free future, the legacy of their operations must be of the benefits it has delivered, rather than the waste it has left behind. The technologies, such as cavitation, are available to ensure that these companies leave the North Sea in the condition they found it, and it is beholden on them to ensure that their words on caring for the environment are turned into action.
References 1.
www.bournemouthecho.co.uk/news/23663807.poole-harbour-oil-spillinvestigation-leak-continues/
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Matthew Offenbacher and Richard Toomes, AES Drilling Fluids, USA, outline how new chemistry in drilling fluid lubricant technology could help create opportunities to extend pipe life through improved wear mitigation.
D
rilling fluid lubricant technology focuses on the coefficient of friction reduction to maximise power at the drill bit. This is a critical function for drilling performance, but new chemistry is creating new opportunities to extend pipe life through improved wear mitigation. Lubricants lower the coefficient of friction between two surfaces by creating a film that limits their interaction. In a drill string, this reduces energy lost due to rotation and transfers it to the drill bit. Drilling at lower torque reduces pipe stress, but in many cases, the torque reduction from a lubricant allows for more weight on the bit to increase the rate of penetration, while remaining within drilling rig system limitations. Torque remains constant while energy to the bit improves the rate of penetration. Lubricants operate in the boundary between two moving parts to prevent contact that leads to an increase in friction (Figure 1). As the conditions under which metal-to-metal interactions become more severe, due to higher temperatures and pressures, the boundary lubricant becomes more stressed. The distance between the metal surfaces decreases to the point where rubbing and damage occurs. Traditional boundary lubricants do not remain on the metal surfaces and cannot prevent the increasing friction, wear, and damage to the metal surface seen under these conditions. Special additives can be used to provide film strength to reduce pipe wear and maintenance. Additives that perform this function are referred to as extreme pressure additives (Figure 2).
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There are many lubricant offerings that claim extreme pressure benefits. Measurement of lubricant performance, particularly extreme pressure performance, is poorly defined throughout the drilling fluid industry. Capturing performance characteristics is again in the spotlight as drill pipe costs remain elevated and more operators choose water-based drilling fluids for longer laterals. Figure 1. A lubricant creates a film to limit interaction between two
surfaces.
Figure 2. An extreme pressure lubricant limits wear by creating a film to limit interaction between rough surfaces.
Figure 3. The modified extreme pressure lubricity tester includes a larger motor and stirring assembly to ensure proper lubricant dispersion during testing.
Measurement challenges
Lubricity is measured as the coefficient of friction between two surfaces at an applied torque. A traditional lubricity meter features a rotating ring pressed against a block immersed in the test fluid. Torque is applied to generate a coefficient of friction reading from the current on the motor required to rotate the ring. This equipment is found in most drilling fluid laboratories, but it has several shortcomings. Data sets are inconsistent, and coefficients of friction values are difficult to compare across instruments. The sample cup remains static, preventing dispersion of insoluble lubricant components when testing with a drilling fluid sample. Consistent and reliable data depends heavily on proper practices and behaviours outside of the test procedure. A lubricity evaluation monitor uses a torque sensor for coefficient of friction readings and features a circulating pump to blend fluid as the knurled bob is pressed against test media at different readings. Low circulation rates limit the blending effects. To screen for torque reduction, the lubricity evaluation monitor was modified to increase mixing power for full dispersion. A syringe pump was added to the cell to inject lubricant in set increments over time. As the computer acquires data, it is possible to view an untreated drilling fluid against gradually increasing lubricant volumes until the torque reduction stops. Extreme pressure testing uses applied pressure between two surfaces to measure film strength calculated from the force applied and the scar dimensions as the film fails. Dedicated extreme pressure testers have their own limitations. The Timken OK tester determines the presence of extreme pressure additives but fails to consistently quantify the film strength. A four-ball tester can only test neat samples and there are comparative data sets using drilling fluid additives. A traditional lubricity meter using a grooved ring and flat block for the test surface provides a practical option because it is already present in many drilling fluids laboratories. The sample remains static and test procedures vary, creating inconsistent results. The stock ½ horsepower motor stalls at high torque and excess friction can heat the samples beyond 149°C/300°F where critical components may degrade. For extreme pressure measurement, the motor was upgraded to 1 horsepower to eliminate stalling. The stock sample cup was replaced with a stirring assembly for sustained dispersion and cooling (Figure 3). Methods were compared and optimised, confirming the procedure no longer demonstrated variability between technicians performing the test.
Lubricity screening
Figure 4. Coefficient of friction reduction comparison of a lubricant vs lubricant containing extreme pressure properties on the LEM.
20 | Oilfield Technology Winter 2023
General lubricant screening begins with operating environment factors. Many lubricant chemistries offer excellent performance but have higher risk of incompatibilities. Cheesing (emulsification) or greasing (oil-wet solids) are incompatibilities which can wreak havoc on drilling fluids and the drilling process. Stress testing identifies compatible materials for subsequent performance testing. After compatibility testing, lubricant blends are tested for coefficient of friction reduction. Samples were tested on
the lubricity evaluation monitor at increasing concentrations up to 6% v/v (percent by volume). The torque reduction relative to the baseline (untreated) field brine in Figure 4 should be noted.
Figure 5. Extreme pressure testing results – formulation 19 was selected due to repeatability of desired results.
Figure 6. Image of the block and ring as part of the EP testing assembly (left) and an image of the block and ring as part of the standard lubricity tester (right). A torque wrench is utilised to apply pressure, forcing the block against the ring as it rotates, while immersed in a test solution.
Figure 7. Scar image on block using neat lubricant without EP, resulting in 5166 psi film strength (left). Scar image on block using extreme pressure lubricant blend 19, resulting in 61 713 psi film strength (right).
22 | Oilfield Technology Winter 2023
The standard lubricant without extreme pressure additives resulted in a coefficient of friction reduction of 70 – 75% at 1.5 – 2% lubricant treatment volume. The same lubricant with the addition of extreme pressure additives resulted in a slightly improved reduction at the same treatment volume – a 75 – 80% coefficient of friction reduction. A continued reduction was observed as treatment levels increased to 6%, but not at a rate to justify such elevated concentrations at given costs. Extreme pressure testing of conventional materials demonstrated film strengths of 4000 – 8000 psi. These lubricant blends featured no extreme pressure additive materials and provided a baseline for new materials. The historically high cost of materials with extreme pressure properties limits practical utilisation. New additives were evaluated that could meet the demand for performance for economic cost. New blends were prepared, and testing was repeated for compatibility and coefficient of friction reduction. Lubricity reduction remained consistent with the original lubricant blends. Film strength was tested using the EP testing feature following the new procedure, and testing was repeated multiple times to confirm results. For each test, the groove ring and block were replaced even when no visible damage was apparent. Film strength calculations rely on accurate scar measurements as the maximum applied torque is divided by the area of the scar to calculate an equivalent pressure. The equation is shown below:
To minimise error, a computerised optical microscope was used to precisely measure scar dimensions. The film strength was calculated to compare materials, blends of materials, and different concentrations (Figure 5). Initial tests utilised neat lubricant blends with extreme pressure properties, and results in the form of film strength varied as candidate chemistries were evaluated. Lubricant blend 19 demonstrated repeatable results, confirmed with multiple tests among varied technicians. Further extreme pressure testing with 3% v/v extreme pressure lubricant blend 19 + 97% v/v field brine was performed using a modified fluid reservoir to ensure proper lubricant dispersion – successful results validated the initial trend. Extreme pressure lubricant blend 19 resulted in a complete lubricant: good coefficient of friction reduction and film strength exceeding 60 000 psi on average. Scarring resulting from the lubricant without extreme pressure properties is significantly larger, resulting in a much lower film strength of 5166 psi (Figure 5). During this test, the torque applied reached a maximum value of 200 in-lbs when the machine began to seize, typically an audible grind/whistle sound accompanied by a rapid torque increase. Comparatively, extreme pressure lubricant blend 19 resulted in a much smaller scar after applying the maximum torque limit of 600 in-lbs, resulting in a much-improved film strength of 61 713 psi (Figure 6). The new lubricant blend extends drilling performance beyond simple torque reduction to potential savings in drill pipe maintenance and wear. Trials are planned using baseline drilling performance data and historical pipe inspection reports to evaluate the practical savings, which may include less hard banding replacement (Figure 7), less pipe rejection, and lower inspection frequency – all while improving rate of penetration.
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Richard Hay, TETRA Technologies, USA, explores the applications and benefits of high-density fluid systems.
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W
hen it comes to drilling and completing hydrocarbon wells, one way to maximise asset value and return on investment is to work more efficiently and simplify the toolkit. This can often be achieved by using one product as the reservoir drill-in fluid, the completion fluid, the barrier fluid, and the packer fluid, as well as in the composition of slugs and the brine phase of nonaqueous fluids. This article examines high-density fluid systems and their advantages, such as their protection of reservoirs, ability to be customised for use in different applications, their low cost compared to formates, and low carbon footprint.
Safeguarding the reservoir
A major priority when developing an oil or gas well is safeguarding the reservoir. Problems such as introducing any unnecessary solids that will clog fractures or reservoir pores, or chemistry that is incompatible with the formation water and causes the creation of damaging interstitial precipitates, should be avoided. TETRA Neptune Fluid is a clear brine which, because it can be engineered with lower crystallisation temperatures than some brines at the same temperature and pressure, enables formulation of higher density brines for use as reservoir drill-in fluid. The fluid offers low solids loading that yields improved rate of penetration whilst protecting the reservoir payzone.
Demanding densities
As wells go deeper and encounter higher pressures, denser fluids are needed to counteract those pressure regimes and prevent any unplanned influx of reservoir fluids into the well during drilling and completion. The fluid can be formulated at densities ranging from 11.6 lb/gal to 17.5 lb/gal, helping to accommodate the challenges of deep drilling, higher temperatures, and higher pressures. Table 1 shows the chemistry, valency, and density ranges available for both monovalent and divalent formulations.
Lower crystallisation temperature
Oilfield completion fluids are solutions of water and salts, typically halides or formates. At lowered temperatures or increased pressures, these fluids can crystallise, causing severe operational problems. The new high-density fluid system is engineered for high-pressure operations, with crystallisation suppression agents (CSA) that enable the formulation of brines with higher densities and lower operating temperatures than standard brines that would crystallise. The true crystallisation temperature (TCT) and pressurised crystallisation temperature (PCT) profiles of the technology have been demonstrated in both laboratory testing and field use.
The alternative to formates
Since the 1990s, formate brines of sodium, potassium, or cesium have become a popular choice in the North Sea to confront the higher temperatures of deeper wells. As advantageous as they are, formates also have drawbacks and pose risks. Firstly, from a cost perspective, formate fluids can be very expensive, especially
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Chemistry
Valency
Density (lb/gal)
CaBr2
Divalent
14.5 – 14.9
High-density CaCl2
Divalent
11.6 – 12.0
The fluid was formulated at a density of 14.7 lb/gal and proved versatile as a clear brine fluid, a suspension fluid, a base for wellbore displacement and viscosified pills, and a base for a viscosified suspension fluid. The operation was completed without any nonproductive time or incidents, marking the first use of the fluid in an abandonment in the North Sea.
High-density NaBr
Monovalent
12.5 – 13.1
Reservoir drill-in fluid
High-density CaBr2
Divalent
14.5 – 15.4
Extra-high-density NaBr
Monovalent
12.5 – 15.4
Extra-high-density CaBr2
Divalent
14.5 – 17.5
The new fluid technology is well-suited for use as a high-density, reservoir drill-in fluid. Both divalent and monovalent engineered systems are available, and either system can be used in a reservoir drill-in fluid. Another benefit is the option to reuse the high-density drill-in fluid by converting it to a clear brine for use in the completion phase, thus adding value in terms of reduced cost, time, and logistical needs. A reservoir drill-in fluid must be capable of drilling the reservoir section, yet cause minimal damage. Although invasion of reservoir pores by fluid solids is generally considered acceptable, best practice is to use high-density base brines to minimise the concentration of inert solids added to achieve the desired density. Divalent brines can be used in drill-in fluids, but they have limitations. First, the reaction between divalent cations in the brine and anions in the formation water can sometimes create insoluble solids capable of clogging reservoir pores. Second, the chemistries used to increase viscosity and fluid loss control, like xanthan gum and modified starches, tend to perform more effectively in monovalent brines. As such, a monovalent brine is usually preferred as the base brine of a reservoir drill-in fluid. Sodium bromide and potassium formate are frequently used as base brines but their densities are constrained. Sodium bromide is limited to approximately 12.3 ppg (1.48 g/ml) and potassium formate to 13.1 ppg (1.57 g/ml). When a reservoir drill-in fluid is formulated with an optimal 50 lb/bbl of ground marble as a weighting/bridging agent, an overall density of 13 ppg can be achieved with sodium bromide as the base brine. A slightly higher density of 13.7 ppg can be achieved with potassium formate. However, when higher densities are required, more solids must be added to the fluid, increasing the risk of formation damage. The higher density 15.7 ppg, monovalent TETRA Neptune Fluid used with the optimal 50 lb/bbl of ground marble enables the formulation of a reservoir drill-in fluid with a density of over 15.8 ppg.
Table 1. The variants of high-density fluid systems and their valency and density.
cesium-based brines. Secondly, formate fluids require meticulous pH control, which if too acidic, will result in highly corrosive formic acid that damages tubing and tools. Finally, when formates come into contact with formation waters containing halides, there can be significant precipitation, which could then damage the reservoir and diminish production yields. New fluid technologies such as TETRA’s could help overcome these drawbacks and risks. Costing less than formates, with a neutral-to-alkaline pH that poses no risk of forming corrosive formic acid, the fluid can be formulated to be compatible with formation waters, including those containing halides – a primary step in designing non-damaging fluids. The new fluid technology also offers sustainability benefits, with a small carbon footprint, as it is regionally sourced and made with environmentally safe ingredients. It can also help lower operating costs and simplify logistics, requiring no special mixing, handling, or storage at the rig site or aboard a marine vessel. Moreover, it requires no zero-discharge equipment, and can be reclaimed for later reuse. The technology has environmental approval for use in the North Sea.
Versatile applications Completion fluid, packer fluid and base for pills Development of the new fluid technology began in 2014. The following year, it was trialled and evaluated in two ultra-deepwater wells in the Gulf of Mexico. In this trial, water depth exceeded 7000 ft, mudline temperatures hovered around 40°F, bottomhole temperatures were about 265°F, and formation pressures exceeded 21 000 psi. The fluid was used as the completion brine, the base for wellbore treatment pills, and packer fluid. It performed as designed, yielding an effective bottomhole density of about 14.5 lb/gal. Both true and pressurised-crystallisation temperatures remained stable, with a TCT between 6°F and 9°F and a PCT of 3°F at 15 000 psi. The fluid experienced no significant incompatibility issues with the formation fluids, and it caused no scaling, pitting, or stress-cracking corrosion on the Q125, 13 Cr, and 15 Cr materials at bottomhole temperatures of 250 – 265°F. Moreover, the fluid showed no signs of thermal decomposition at bottomhole temperatures or at elevated temperatures during perforation. Ultimately, the job incurred no operational or HSE issues, and the operator also used the fluid in four subsequent wells, one temporary abandonment, and one well intervention.
North Sea intervention and abandonment The new drilling fluid was recently used in an intervention and abandonment operation in the North Sea with excellent results. Water depth was 80 m, true vertical depth was over 4000 m, mudline depth was about 103 m, and the bottomhole temperature was 79°C. The work included a blowout-preventer test at 10 000 psi with a true crystallisation temperature below –30.5°C.
26 | Oilfield Technology Winter 2023
Use in solids-free invert emulsions
Solids-free invert emulsions are used in situations where a non-aqueous fluid is required and the presence of solid weighting agents is undesirable, such as when running sand screens into the hole. To achieve sufficient density in these fluids, it is necessary to formulate them at a very low oil/water ratios – typically 40/60 or below. Achieving acceptable fluid stability at such low oil/water ratios is notoriously difficult. Formulating a 40/60 fluid with commercial 14.2 ppg (1.7 g/ml) calcium bromide provides a density of 11.2 ppg (1.34 g/ml), which may not be sufficiently dense. However, if the calcium bromide can be replaced with this fluid of 17.5 ppg (2.10 g/ml), then a solids-free invert emulsion with a much higher density of 12.9 ppg (1.54 g/ml) can be obtained.
Conclusion
High-density fluid systems can be used as a clean and versatile solution, ideal for North Sea and deepwater applications. These can be formulated at the necessary densities and maintain thermal stability to prevent crystallisation, even during high-pressure blowout-preventer tests. They are formulated with minimal or no solids, are environmentally friendly, offer low corrosion potential, and can be custom engineered to be compatible with elastomers and formation fluids.
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Tom Roberts, Alex Benson and Jessica Stump, NOV, USA, discuss how innovations in PDC cutters and drill bits are helping to transform the drilling market.
O
ver the past 50 years, innovations in PDC cutters and drill bits have helped transform the drilling market, from increasing efficiency and reducing costs, to enabling geothermal and horizontal directional drilling. In 2024, NOV’s ReedHycalog business unit will celebrate the 50th anniversary of the initial field trial of its first polycrystalline diamond compact (PDC) drill bit. The Compax Bit Design No. 2 (C2) bit was designed in 1974 by John Fuller and was manufactured in three weeks. It drilled 19 ft (5.8 m) in 3.65 hr for a rate of penetration (ROP) of 5.2 ft/hr (1.6 m/hr) at Arreton on the Isle of Wight, off the southern coast of England. Though the run was hardly a brilliant performance, it demonstrated the bit’s ability to drill and encouraged further PDC cutter and drill bit innovation.
PDC cutter development
Three other PDC drill bits were tested in the years of 1973 and 1974, at King Ranch, Texas, in Hudson, Colorado, and in San Juan County, Utah. All four of these early bits used the recently developed Compax™ PDC cutters from General Electric (GE) – 8 mm diameter cutters with 0.5 mm diamond tables. These cutters proved an ability to drill, but also highlighted through cutter loss and post-breakage, the braze joint’s weakness and the post’s vulnerability when used in the porcupine arrangement.
After a two-year lull in bit development, GE introduced a 13 mm diameter cutter in 1976. Although the increased braze area improved braze strength, failures still occurred. In 1979, the company introduced a high-strength bond brazing system. Bit companies implemented this technology in their own PDC bit designs, leading to commercial success. Innovation efforts in the 1980s and 1990s focused on enhancing abrasion and impact resistance. Multimodal PDC, with a mix of diamond grit sizes, produced a much denser diamond table, improving the abrasion resistance. Bonding the diamond table to a nonplanar interface substrate boosted the cutter’s toughness by reducing the stress concentrations on the polycrystalline diamond.
Breakthroughs
Drilling efficiency strongly relies on rock failure efficiency, which demands optimal rock cutting technology. ReedHycalog is committed to developing PDC cutter advancements and performance. Extensive research has been dedicated to enhancing cutter grades, shapes, and placements to deliver fast and efficient PDC drill bits. In 1994, the company built and installed the first cubic press in Stonehouse, England. A PDC cutter is made by fusing micro-sized synthetic diamond particles (diamond grit) at 1 million psi and 2500°F (1371°C)
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onto a tungsten carbide substrate. Cobalt from the carbide substrate melts and infiltrates the diamond powders. At these high temperatures and high pressures, cobalt acts as a catalyst to promote diamond-to-diamond bonding. Monocrystalline diamond
particles sinter into a polycrystalline diamond table, which promotes high abrasion and impact toughness. Although cobalt is essential for PDC cutters, it has certain drawbacks. The presence of cobalt creates a thermal stability limit for PDC that is much lower than natural monocrystalline diamonds. As PDC is heated, cobalt expands faster than the surrounding diamond particles. At about 1292°F (700°C), the cobalt has expanded enough to start forcing the diamond-to-diamond bonds apart, causing the compact to break down. This process occurs rapidly once initiated; therefore, the PDC must be maintained below the critical threshold temperature to avoid the risk of catastrophic failure. In addition, at an elevated temperature but comparatively low pressure, cobalt reverse-catalyses the grain-to-grain bonding, leading to further deterioration of the diamond table. The invention of leaching techniques by ReedHycalog in the late 1990s was a PDC breakthrough. Removing cobalt only from the cutter’s face enhances the face’s and edge’s abrasion resistance, but leaves enough cobalt to bind the diamond table to the substrate. After manufacturing the cutter in the diamond press, the face is exposed to hot acid for a period. This treatment leaches the cobalt out of the surface layer. Varying the amount of time exposed to the acid changes the depth to which the cutter is leached. In 2001, ReedHycalog introduced TReX™ cutter technology. The leached diamond layer enhanced the thermal properties of the PDC cutter, making it more heat-resistant and abrasion-resistant. The combination of these improvements in thermal and abrasion resistance helped extend the cutter’s life and ROP by around 40%. PDC drill bits could now be used in drilling applications previously only feasible with roller cone bits, such as harsh rock environments.
Figure 1. NOV’s first PDC drill bit, the 8.5 in. Compax bit No. 2, had its first field trial in May of 1974 and drilled a total of 19 ft in 3.65 hr. John Fuller (left), the designer of the C2 bit, and John Barr (right), the Technical Director, examine the dull C2 drill bit.
Shaped cutters and grades
Shaped cutter technology has been pursued by companies such as ReedHycalog to improve rock failure efficiency in today’s applications, which consist of different rock types in varying lithologies. By investing in advanced single cutter testing equipment at its Pressurised Drilling Lab in Conroe, Texas, ReedHycalog has worked on developing shaped cutters that deliver maximum ROP without sacrificing durability. The company developed the ION™ PDC cutter technology to overcome specific drilling challenges, from thermal damage caused by abrasive sands, to impact damage related to chert or other hard formations. Its engineers developed a process that Figure 2. The C2 bit being manufactured. enables a complete understanding of PDC cutter failure modes. An extensive, in-depth cutter-dull analysis for each application and interval allows the right cutter grade to be quickly deployed in specific applications, providing critical data that helps improve the quality and speed at which cutter grades ION 3D and ION ION+ Alpha 1-inch TReX DuraForce Cutters Helios Inferno ION+ 5DX Shaped ION+ Armor Shaped Cutters Cutters Premium Cutter Series Cutters PDC Cutter Technology Cutter Technology are engineered, while improving drilling economics. ION 3D cutters are designed for ION+ Advanced Raptor Reflektor Low ION 4DX Shaped Helios Cutters ION+ Fortis PDC Cutter Technology Cutters Cutter Series Friction Cutters Premium Shaped Cutter Series fracturing and shearing, increasing their effectiveness in brittle formations such as carbonates and clastic rock. The chisel profile produces point loading in the axial (weight nov.com/reedhycalog on bit/WOB) direction, improving fracture propagation and depth of Figure 3. The evolution of PDC cutter technology. cut efficiency and further lowering TM
TM
TM
TM
TM
TM
TM
TM
TM
TM
TM
TM
TM
TM
TM
30 | Oilfield Technology Winter 2023
specific energy through torque reduction while achieving higher ROP. By creating cracks that propagate to the surface, these shaped cutters require less energy to fail the rock, while generating thin and uncondensed cuttings. ION+TM PDC cutter technology design consists of various application-specific cutter grades that incorporate refined diamond feeds, higher manufacturing pressures, nonplanar interfaces, thicker diamond tables, and enhanced thermal stability. ION+ 4DX shaped cutters have a multifaceted geometry to bring about effective cutter-rock interaction. The cutting face creates a plough effect that increases point loading in the shearing direction while reducing drag and making smaller cuttings. ION+ 5DX shaped cutters have a multifaceted geometry that helps improve mechanical toughness by around 60% compared with conventional cutters. This durability makes them ideal for drilling challenging interbedded lithologies. The working ridge has been optimised to withstand sudden impacts while applying higher compressive loads to the formation, resulting in more effective and efficient rock failure. These cutters are strategically positioned in a cutter layout to provide faster ROP while resisting impact damage in tougher applications.
Case studies
By combining PDC cutter technology with cutting-edge drill bit design, advanced materials, and manufacturing processes and capabilities, operators can achieve the best performance in the most challenging drilling environments. A Tektonic™ Fuego™ drill bit equipped with ION cutters set the Acordionero field ROP record in Colombia. The 12.25 in. TK59 bit was run on a downhole motor assembly for a total of 2446 ft (745.5 m) in 2.25 hr for an ROP
of 1087.1 ft/hr (331.3 m/hr). The previous field ROP record was 983.2 ft/hr (299.7 m/hr). In Oman, the 8.5 in. TKC66-I1E Tektonic Falcon drill bit featuring ION+ 3D and cylindrical cutting structure drilled 1969 ft (600.2 m), the longest interval in the hardest area of the field, at an average ROP of 10.17 ft/hr (3.1 m/hr). In China, a Pegasus™ drill bit with ION+ 4DXC and 5DX shaped cutters set the footage record in Sichuan. The 12.25 in. bit drilled 1581 ft (481.9 m) in one run, 9.3% longer than the best offset.
Geothermal
As the geothermal market garners momentum worldwide, PDC drill bit and cutter technologies are being developed to handle the igneous and volcanic rocks that result in hard and abrasive formations. When drilling in these formations, high WOB requirements generate frictional energy that can lead to cutting element damage and inhibit drill bit performance. In Japan, an 8.5 in. TKC73-A1 drill bit equipped with ION 4DX and 3D cutters reached total depth in one run with no shock and vibration recorded. The bit replaced seven roller cone bit runs, resulting in savings of around US$250 000, representing a 49% lower cost per foot.
Conclusion
Operators are drilling faster and farther in ever-increasingly complex, hard, abrasive, and interbedded formations. PDC drill bits have surpassed roller cone bits, becoming the industry standard over the past decade due to advancements in impact and thermal resistance and enhanced manufacturing techniques and processes.
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32 |
Seamus Jacobs, Dexon Technology PLC, Thailand, discusses the benefits of well casing in-line inspection systems in the oil and gas industry.
I
n late 2020, a gas producer contacted Dexon Technology searching for a solution to a specific well casing inspection problem. Well casings are subjected to harsh environmental conditions, high pressures, extreme temperatures, corrosive chemicals such as H2S, and continuous operations threatening asset integrity. These conditions can lead to possible environmental contamination, compromised safety, and production downtime. A fast, accurate, and definitive inspection solution was required for the assessment of production well casings, necessitated by the supply of a detailed analysis of the well casing to determine maintenance and repair requirements. Specifically, the inspection was required to both reliably and accurately fulfil the identified criteria. These criteria included extremely thin remaining wall thickness verification and pinhole corrosion detection with immediate on-site assessment and reporting. These requirements were taken to the engineering drawing board and a tailored toolset was designed to address the issue, resulting in a well casing in-line inspection (ILI) programme offering 360° corrosion mapping while minimising asset downtime.
The need for well casing inspection
There are several critical points that highlight the necessity of proactive asset integrity management:
ÌÌHarsh environmental conditions: oil and gas wells operate
under extreme conditions. This can include high pressures and temperatures which can lead to accelerated wear and tear on the casing and eventually potential integrity issues. Groundwater contamination risks: undetected defects can lead to leakage and contamination of groundwater, leading to environmental fines and costly cleanup efforts. Well casing inspection allows operators to take a proactive approach to environmental protection. Hidden defects: defects are not visible from the surface, making it crucial to implement advanced inspection methods to accurately assess well integrity. Lost production and revenue due to asset downtime: rapid inspection speeds and reporting times minimise asset downtime, clearing the asset for continued operation and ensuring maximum production.
ÌÌ ÌÌ ÌÌ
Well casing ILI solutions
New well casing ILI programmes such as Dexon Technology’s combine recent technology with data analysis and reporting capabilities. In Dexon’s case, the fleet’s lightweight design allows for hand loading on wirelines and slicklines with planned logging runs limiting disruption to production. Additionally, high-speed
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inspection and reporting allow for the inspection of multiple wells per day.
The benefits of well casing ILI programmes
ÌÌ
Well casing ILI programmes such as this offer several key benefits, providing operators with rapid reporting, extreme data resolution, and accurate defect detection: Rapid reporting: Dexon’s programme offers a two-tiered reporting structure. Initial field reporting is provided within as little as
ÌÌ
two hours, highlighting all critical defects for assessment and immediate review. Final reporting is issued within 24 – 72 hours, providing in-depth analysis of all anomalies. High-resolution inspection data: advanced ultrasonic (UT) technology and high sampling densities provide over 400 000 direct measurements per square metre with multiple data sets per inspection. These detailed data collection abilities allow for the precise detection, sizing, and analysis of a range of defects, such as metal loss, geometric anomalies, and cracks and crack-like defects. High-speed inspection capabilities: the fleet’s inspection capabilities within the programme allow for the same-day assessment of multiple assets, minimising downtime and maximising production uptime and efficiency.
ÌÌ
Tool specifications and features
Figure 1. Simulated internal metal loss defects in test yard inspection data.
The new well casing inspection fleet utilises pulse-echo and angle beam tip diffraction ultrasound to accurately detect and size a variety of defects. Pulse-echo ultrasound provides inside diameter (ID) and outside diameter (OD) measurements, allowing for the accurate detection and sizing of metal loss and geometric defects. Angle beam tip diffraction and high-density sensor arrays are used to detect cracking and crack-like defects down to less than 1 mm of through-wall height.
Ensuring reliability and accuracy
The fleet has been designed to withstand the extreme pressures and temperatures present in production wells, providing consistent and reliable inspection results. High sampling densities of over 400 000 direct measurements per square metre ensure 1 mm axial and circumferential sampling resolution (-3db) and ± 0.3 mm wall thickness accuracy. Rapid reporting times of as little as two hours for onsite reporting and 24 – 72 hours for final reporting, allow for informed decision-making and prompt repair actions, minimising potential asset failure and downtime.
Rapid agile inspection operations Figure 2. Metal loss depth unity plotting compares actual defect depth vs measured
defect depth during smart pigging verification testing.
The onshore upstream oil and gas industry demands agile inspection capabilities with minimal disruption to operations maximising production. New well casing fleets have been specifically designed to be operated by small inspection crews of two people, capable of performing multiple inspections per day. Lightweight designs allow tools to be hand-loaded on wirelines and slicklines, further increasing the agility of inspection operations and removing the need for large lifting equipment onsite. Inspection tool speeds of up to 80 m/m, while maintaining high-resolution inspection data collection, allow for the inspection of 1000 m of well casing in just over 33 min. Inspections can also be performed in line with planned logging runs, without disrupting operations.
Inspection data verification
Figure 3. In-field metal loss inspection data shows general corrosion detected in a production well at a depth of 827 m.
34 | Oilfield Technology Winter 2023
Accompanying Dexon’s 1228 m2 R&D facility is a 7 acre test yard featuring pump-through, pull-through, and infinity test loops. The onsite testing facility allows for inspection data verification and rigorous tool testing. Pulsed echo and angle beam tip diffraction ultrasound allow for the detection and sizing of a range of defect types including
metal loss, through wall holes, geometric deformations, and cracks and crack-like defects. Inspection data verification is performed, demonstrating the fleet’s defect detection and sizing capabilities. A range of simulated internal and external defects have been added to pipe spools at the onsite test yard. Actual defect dimensions are compared to measured defect dimensions using unity plotting, generating in-field probability of detection (POD) and probability of identification (POI) figures.
Metal loss detection and sizing
Pulse-echo ultrasound wall thickness inspection data is used to detect and quantify internal and external metal loss defects, including general and acute corrosion such as pinholes. Probability of detection (POD) is determined by the level of sampling resolution achieved vs defect size. Ultrasonic inspection reporting contains all wall loss information with accurate remaining wall thickness measurements. The direct measurement assessment method enables exact measurement inputs to be provided for FFS assessments including ASME FFS-1, and API 579.
Simulated test yard metal loss inspection data
An arrangement of internal metal loss defects of varying depths and lengths can be seen in the inspection data in Figure 1 from Dexon’s onsite test yard. Both internal and external man-made defects are used to verify inspection data and tool capabilities prior to an inspection. Six simulated defects can be seen in the ultrasonic C-scan and B-scan inspection data. A-scan data in Figure 1 shows the amplitude of individual ultrasonic signals chosen from the centre of the first defect from the left, displaying a highly precise remaining wall thickness measurement of 2.54 mm to within ± 0.3 mm. A unity plot can be seen in Figure 2 comparing actual defect depth vs measured defect depth during smart pigging verification testing. Artificial defects were manufactured, ranging from 1 – 9 mm in depth. Measurements can be seen to be within tolerance of ± 0.3 mm in greater than 90% of indications.
in the casing string. Casing ovality deformation can be caused by multi-directional forces present within the earth’s surface. The inspection data in Figure 5 shows an in-field geometric defect (a dent), most likely created prior to or during the installation of the well detected in a well casing string at a depth of 523 m.
Crack detection and sizing
The well casing crack detection and sizing fleet utilises angle beam tip diffraction and a high-density sensor array to accurately detect and size Table 1. Key tool specifications. Depth sizing accuracy
± 0.3 mm (0.011 in.)
Axial sampling resolution @ 50 m/min (3db)
1 mm (0.039 in.)
Circumferential sampling resolution (-3db)
1 mm (0.039 in.)
Maximum operating pressure
200 bar (2900.75 psi)
Maximum operating temperature
75°C (167°F)
Maximum inspection speed
80 m/m (262 ft/m)
Recommended inspection speed
50 m/m (164 ft/m)
In-field metal loss inspection data
In-field wall thickness inspection data in Figure 3 shows general corrosion detected on the external surface of the production casing at a depth of 827 m. Maximum defect depth was recorded at 78% of nominal wall thickness with a remaining wall thickness of 1.54 mm. Defect length, width, and depth were measured at 192 mm, 149 mm, and 5.50 mm.
Figure 4. In-field inspection data shows the detection of a through-wall hole in a well-casing.
In-field through wall hole inspection data
The inspection data in Figure 4 shows a through-wall hole in a well casing. Corrosion can be seen around the circumference of the pipe with a white area in the centre of the defect. This white area signifies a hole in the pipe wall due to a loss of ultrasonic signal as the sound waves dissipate out of the pipe not returning an ultrasonic signal from the internal pipe wall surface.
The detection and sizing of casing ovality and geometric deformations
Pulse echo ultrasound uses 90° transducers and high-frequency sound waves to collect internal radius (IR) and wall thickness (WT) measurements. Internal radius measurements can be used to assess production casing ovality and to detect geometric deformations
Figure 5. In-field inspection data shows a geometric deformation detected in a well casing string at a depth of 523 m.
Winter 2023 Oilfield Technology | 35
cracks and crack-like defects to less than 1 mm of through wall height. Ultrasonic crack detection and sizing reporting provides an assessment of all cracks and crack-like features detected on the well casing, including detailed measurements and categorisation allowing for a full integrity assessment of the well.
Simulated test yard crack inspection data
Angle beam tip diffraction test yard inspection data shows fabricated electrical discharge machining (EDM) notches simulating cracking on the external pipe wall. The inspection data in Figure 6 shows defect confirmation using multi-angle transducer (skew 90, 270, and perpendicular) sets, allowing for accurate detection, sizing, and inspection. The unity plot in Figure 7 shows the plot distribution between actual EDM notch measurements confirmed using advanced full matrix capture ultrasonics vs detected sizing during the test run in the onsite test yard.
In-field crack inspection data
In-field inspection data shows cracking in a downhole production well casing. The crack was detected and sized to 25 mm long with a through wall height of 2.5 mm at a well depth of 1681 m (Figure 8). Figure 6. Test yard inspection data shows fabricated electrical discharge
machining (EDM) notches simulating cracking on the external pipe wall.
Two-tiered reporting structure
The well casing ILI programme includes a two-tiered reporting structure. The system provides rapid and actionable inspection results, allowing for immediate assessment of the well’s integrity, providing prompt decision-making on repair requirements, eliminating asset failure and ensuring maximum profitability and production capabilities. The two-tiered reporting structure is as follows:
Two-hour on-site field reporting
ÌÌ Includes a summary of all inspection operating details. ÌÌ Reporting is issued within two hours after the completion ÌÌ
Figure 7. Crack depth unity plotting compares actual defect depth vs measured defect depth during inspection verification testing.
of the inspection, allowing teams to return the well to production. Includes analysis and assessment of all critical defects requiring immediate repair.
24-72-hour final reporting
ÌÌ Final reporting is issued within 24 – 72 hours of completion of the inspection. ÌÌ This features a detailed assessment and analysis of all detected anomalies. ÌÌ The reporting utilisies mass quantities of inspection ÌÌ ÌÌ ÌÌ
data providing detailed corrosion mapping, including over 400 000 individual direct wall thickness measurements per square metre of pipe wall. Reporting is accompanied by A-Scan data of each individual internal radius and wall thickness measurement. Additional reporting criteria are available upon request to meet individual client reporting needs. Integrity assessment calculations are available on request such as fitness for service (FFS) in accordance with API 579 and ASME FFS-1.
Conclusion
Figure 8. In-field inspection data shows cracking in a downhole production well casing at a depth of 1681 m.
36 | Oilfield Technology Winter 2023
Production well casing in-line inspection (ILI) programmes are key within asset integrity management in the upstream oil and gas market, and are specially designed and built to address specific upstream inspection requirements, ensuring safe and reliable operations. The ability of these systems to provide rapid reporting, high-resolution data, and accurate defect detection helps operators to make informed decisions, reducing downtime, and ensuring safe and profitable operations.
Ida Christiansen, ChampionX Norge AS, Norway, discusses how emulsion viscosity reducers are tackling the issue of slugging in offshore assets.
A
s offshore assets progress into their mature production phase, operators are faced with the challenge of how to maintain or increase production with solutions that are not only cost effective but also sustainable. One such challenge is the increased viscosity of produced fluids as a result of higher water cut in wells. Once the emulsion inversion point is reached, viscosity begins to increase. Even above these inversion points, fluids with high water cuts can have relatively high viscosities in downhole conditions. When this happens, operational management can become challenging as slugging occurs, production is reduced, wells are choked back, and oil and water levels become out of specification. To address this issue, emulsion viscosity reducer (EVR) products have been produced which, in field trials, have shown to be effective in increasing mature field production by reducing produced fluids viscosity. Injected downhole by gas lift or capillary strings, EVRs act upon contact with fluids to prevent emulsion formation or remove
already formed emulsion. Meeting the environmental requirements of the North Sea, this technology can help maximise operators’ return on investment with minimal CAPEX investment. In the 2018 North Sea trials, the introduction of EVR presented production increases of hundreds of additional bpd in mature wells, resulting in a return of more than US$100 000, and had the potential for continued additional revenue for the operator.
Effective increased production
In the first trial, the operator had experienced slugging wells and increasing water production over a number of years on a particular asset. It was thought the slugging was mainly due to high friction and viscosity in the well. During the first set of trials, the potential uplift had not been proven, as the key focus at the time had been on maintaining the steady separation of oil and water. The client requested ChampionX return to the asset to further trial the technology, this time to optimise
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Figure 1. Slugging can be generated when fluid emulsions become highly viscous in wells or flow lines where the lifting forces are not sufficient to overcome the friction of the liquid column. Liquid will intermittently fall back, accumulate, and flow again, resulting in slugging. Table 1. Delta 1 shows results compared to the pre-trial baseline, while Delta 2 shows results compared to the post-trial baseline period. As the well was in decline during the trial, both sets of figures are shown for comparison. Dose
Total flow m3 hr-1
Oil flow m3 hr-1
Water flow m3 hr-1
oil ∆1
oil∆2
0 lph
14.4
1.76
12.64
-
+3.5%
1 lph
15.4
1.88
13.52
+6.8%
+10.6%
0.3 lph
16.0
1.95
14.05
+10.8%
+14.7%
0.4 lph
15.1
1.84
13.26
+4.5%
+8.2%
0 lph
13.9
1.70
12.20
-3.4%
-
the EVR application to mitigate slugging and quantify increased boe produced. Based on the initial trial that showed uplift of oil production on this particular asset, it was believed greater hydrocarbon recovery could be actualised by injecting EVR into the gas lift of daisy-chained wells. The field trial was performed with EVR chemistry FLOW48405A on a site with two daisy-chained wells. The client operator’s online process system was used to monitor wellhead pressure, wellhead temperature, bottomhole pressure and the bottomhole temperature of each well. A test separator was then used to measure the blended flow of the daisy-chained wells as well as basic sediment and water levels. Oil and water samples out of the separator were analysed as well as a flowline sample to check for emulsions. The injection rate of FLOW48405A was controlled through a temporary system and optimised based on the identified parameters. In addition to this, the client’s production engineer optimised aspects such as the gas lift and choke opening to make sure the process and production were running as smoothly as possible. The trial saw EVR being injected into the affected wells for five days, and during this time, EVR showed initial results of: Eliminating slugging completely on one of the wells. Providing a combined uplift on the two wells of 350 bpd. Reducing a combined gas lift consumption by 500 Sm3/hr, which was estimated to help production on other wells by around 100 bpd.
ÌÌ ÌÌ ÌÌ
Based on the measured uplift of the two wells throughout the field trial, it was estimated that the customer increased returns by more than US$100 000 during the five-day field trial alone after deducting the equipment, personnel and chemical costs for the field trial.
Chemical application for reduced slugging
Following initial testing, ChampionX was asked to conduct a trial for another operator in the North Sea. The EVR application, together with a modelling technology developed in-house, was tested to support declining oil production in wells with high amounts of slugging. The aim was to deliver increased oil production by reducing the viscosity of well fluids, leading to lower friction and less slugging. Based on the results of a previous bottle test at the asset, the EVR chemistry FLOW48396A was chosen for the trial and modelling. Due to imposed time limitations, the product was only tested on one well for less than three days. Results showed that the total flow and water content of the oil became much more stabilised during injection of EVR. Although time constraints did not allow for optimisation of the injection rate and other well parameters, the results achieved over the three days were extremely positive. Based on the total liquid flow rates at the test separator, the applied chemical resulted in oil uplift improvements of up to 14%. Because the limited trial time did not allow for proper chemical optimisation or optimum slugging reduction, these figures are likely conservative. Based on the trial results and the EVR modelling technology, ChampionX assumed an initial oil rate of the well at 1.76 m3/hr with a potential of 15% uplift to demonstrate the potential increase in production and return: Potential of 595 bpd uplift for full field implementation. US$6000 uplift for the two-day trial.
ÌÌ ÌÌ
Figure 2. Viscous emulsions in produced fluids can cause slugging in wells. Emulsion viscosity reducer (EVR) chemistries can prevent emulsion formation or remove already formed emulsion, resulting in increased mature field production.
38 | Oilfield Technology Winter 2023
Optimised well performance through EVR
Trials recently took place for a client in the Caspian region and produced encouraging early results. The well selected for trialling
was choked back due to stability issues of the slugging well, causing a 0.45 bpd production deferral. It was believed that the root cause of the issue was the presence and accumulation of emulsion thousands of feet below ground, where the inclination of the well is between 30° and 60°, preventing the transportation of these emulsions to the surface, therefore impacting production. 48 hours after applying EVR chemistry through the gas lift system, the well started to respond, and the slugging behaviour of the well reduced to zero. This enabled the client to slowly open the choke valve from 30 – 100% without any slugging. As a result, there was a production increase of 58% without any increase of water cut from the well. Due to the success of this trial, operations teams are now developing a permanent solution for chemical injection. The effectiveness of the EVR chemistry on this particular well was further confirmed when the installation experienced a planned shut-down. The decision was made to start up the well without EVR, leading to the return of the sluggish behaviour, which could not be mitigated. Once the EVR application was restored, the slugging stopped, and the well returned to full production within hours. The trial continues and the team, in consultation with the client, is now considering options for applying the technology to other wells.
Cost effective solutions for mature fields
EVR chemistries use existing offshore infrastructure, so required investment is minimal, and the complexity of a trial to determine effectiveness is low. The technology was developed as a solution for underperforming and slugging wells with the goal of increasing production by 5 - 15% on average.
Figure 3. Emulsion viscosity reducer (EVR) technology was developed as a solution for underperforming and slugging wells with the goal of increasing production by 5 – 15% on average. Increasing production on mature wells therefore reduces relative operational costs and increases profitability for operators. Benefits have also been observed in oil and water separation, which has positive impacts on the installation overboard water quality. In cases where gas lift is applied, it can also be optimised and directed to other wells, giving the potential for additional uplift. In fields with slugging wells, improvements have also been observed in reduction of well noise, resulting in reduced wear on production equipment and smoother processing operations.
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O
nce an exploration drilling campaign successfully finds new oil or gas reserves, engineers look to bring the asset to full production in a safe, swift and cost-effective manner. The optimal solution may use subsea equipment where manifolds, valves and risers fixed to the seabed are electrically powered and controlled from a platform or vessel topside. While this approach has a track record of reducing capital expenditure and unlocking value in marginal developments, operating subsea equipment brings its own challenges. Underwater electrical cables are critical to the operation of subsea equipment, and loss of cable integrity can ultimately lead to field shutdown and loss
40 |
of production revenue. The ability of a cable to protect its conductor is called its insulation resistance (IR). Monitoring, predicting and preserving the IR of a cable over the life of a subsea field is a science in itself.
What is insulation resistance?
A subsea cable can have multiple copper conductors that carry electrical current in the form of power or communication signals, and an insulating layer which isolates the conductors from other conductors and electrical earth. When the cable is new and the IR is high, power cables deliver the voltage and current needed by the equipment on the seabed without tripping overcurrent circuit breakers, or letting the voltage
Viper Innovations, UK, explores the risks of unmonitored cables and copper loss in subsea electrical systems.
drop to a point where the subsea control module (SCM) can no longer function properly (Figure 1). Damaged and faulty cables will eventually allow sea water to ingress onto the conductors, causing low IR and leakage currents which can be hazardous to personnel and will eventually lead to system shutdown. The salt water also acts as an electrolyte, promoting a chemical reaction that can erode and weaken the copper conductors, which may accelerate the time taken for a fault condition to occur. Although no insulator is ever completely perfect, cable IR (the ability to resist flow of leakage currents from the conductor into surrounding sea water, cable
armour or other conductors) is vital to safe and compliant subsea operations.
Scratching the surface of insulation resistance failures
The reasons for loss of cable IR can be classified as either intrinsic or extrinsic factors. Extrinsic factors are those not native to the cable itself and can include stresses from incorrect handling during installation, seabed scouring causing abrasion damage to the surface of the insulator, or incorrect loading or ballasting placing strain on the cable. Impact damage from trawlers or remotely operated vehicles (ROVs) is also an extrinsic factor.
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Intrinsic factors are associated with the construction of the subsea cable. Manufacturing issues or material defects can cause a low IR fault to develop even after years in service. Incorrect soldering or crimping of pins can damage connectors, and small defects in the polyethylene or polypropylene insulation material can escape quality checks during cable extrusion, leading to eventual IR breakdown once in the field. Subsea electrical power systems are generally designed using an isolé terre (IT, unearthed) earthing philosophy to
maximise availability. There is no residual current device (RCD) protection in such a system, and it is vital that an insulation monitoring device (IMD), also known as a line insulation monitor (LIM), is installed to monitor for breakdown in insulation by measuring any conductor to earth leakage currents. However, even the monitoring voltages applied by a LIM can accelerate copper loss in a damaged cable by promoting the electrochemical reaction with sea water. Left unchecked, the cable is weakened to the point where it acts as a fuse, leading to an open-circuit fault that cannot be recovered (Figure 2). Deteriorating IR can take place gradually, as opposed to collapsing suddenly. Having permanent IR monitoring hardware properly configured with appropriate alarm setpoints is vital and is a legislation requirement. This information can allow the most effective life extension measures to be put in place at the earliest possible stage.
Copper loss in subsea electrical systems
Figure 1. The measured value of electrical cable insulating material is called insulation resistance (IR) and is measured in ohms.
Figure 2. The most common cause of subsea electrical failures is the ingress of water into the cable insulation.
Due to its high conductivity/low resistance and other material properties, alongside its availability and cost, copper is a common material found in subsea electronics, especially cables. However, despite its ubiquity, there are disadvantages to using copper in subsea electrical systems where the use of a LIM is a statutory requirement. If subsea cable insulation is damaged, or suffers degradation through ageing, sea water penetrates the cable and encounters the conducting copper core. Sea water is an electrolyte with sodium and chloride ions in solution. When the system is active with its normal operating current running through the system, the copper cable immersed in the sea water electrolyte becomes an anode and the steel wire mesh protecting the cable becomes the cathode. The negative chlorine ions react with the copper anode to form copper chloride, with a small amount of copper ions entering the solution (Figure 3). The copper chloride is deposited onto the cathode, or steel wire protective sheath. Another process occurring is the formation of hydrogen gas at the cathode, soaking up the spare electrons produced when the copper is deposited. When combined with other processes within the umbilical, such as galvanic reactions and microbial activity, hydrogen gas production can be so acute that it is vented topside.
The impacts of copper loss if operators take no action Gradually, the copper anode, which is the copper cable carrying power and control signals to the subsea infrastructure, loses material. Copper chloride deposits build up, and this impacts upon performance, reducing IR. The combined material loss and build-up of deposits can result in damage to the cable (Figure 4). Eventually, enough damage will be caused that it will lead to system failure. Hydrogen gas production in the subsea umbilical is a well-known phenomenon. The copper loss process may contribute to this production and venting of hydrogen gas needs to be carefully managed by the operator to ensure safety risks are mitigated.
How a LIM can mitigate the impact of copper loss
Figure 3. Ions migrate in different directions when a DC current is applied to a seawater solution using a copper anode.
42 | Oilfield Technology Winter 2023
Damage to cable insulation and LIMs cause copper loss. Research data shows that the rate of copper loss is directly proportional to the leakage current, meaning the lower the IR, the worse the copper loss. The Viper V-LIM was designed with copper reduction in mind. It can be reconfigured to reduce the applied
voltage and therefore leakage current in low insulation resistance conditions, further reducing any copper loss. It is accepted that the use of IMDs, which are a statutory requirement in IT unearthed systems, will lead to the corrosion of the copper conductors and the generation of hydrogen gas, as the IR degrades. The obvious question that results is; why not remove the IMDs when a low IR situation occurs and manage the safety risk to personnel, via procedures and other protective measures? If a ‘first fault’ is detected by an IMD, then it is very likely that a similar secondary fault will impact the second conductor or wire in the power delivery system. If that occurs, there is a completely different electro-chemical cell where the leakage current (the current through the electrolyte or seawater) is driven by the high voltage power supply that is connected between the two conductors. The IMD is creating a leakage current between the conductors and earth, but what is now being considered is the leakage between the two conductors created by the surface to subsea voltage.
Mitigating against low IR and copper loss
The common causes of IR failure are well known. Without monitoring and prompt action, its effects can be catastrophic to the operation of a subsea field. IEC 60364 requires that an IT earthed system is equipped with a monitoring or protection device, and a LIM is the best option for keeping the system in service in a hostile subsea environment. The V-LIM can be configured to annunciate over a variety of industrial communications protocols for early warning, but it can actively help the situation in two ways. Firstly, the V-LIM uses a lower voltage measurement signal which has been optimised
Figure 4. Corrosion affects a wide area as a result of water penetration of the wire intersects. The copper corrosion has resulted in strands breaking. to ensure that accuracy and repeatability are not compromised. This lower voltage has the effect of slowing the rate of copper loss from a cable with sea water ingress while maintaining the quality of its measurements, even at low IR levels. This can extend the service life of a subsea cable with a low IR fault, without compromising the quality of the gathered data and still meeting the legislative IR monitoring requirements. In addition, all V-LIM units can reduce further deterioration of the cable condition. By also enabling the V-LIFE IR recovery service, units can play a role in actively healing cable damage and helping to prevent copper loss.
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T
Alistair Mykura, Castrol, UK, discusses the role of all-electric and hydraulic systems in today’s subsea sector.
here is a clear demand for a better and more balanced energy system in response to a growing population with greater demands for secure, affordable, and cleaner energy. This represents quite a challenge. It is critical that this energy not only leads towards low carbon objectives, but also has the security of being in supply and being affordable. To achieve this aim, investment must continue in today’s energy system and the transition towards net zero, as witnessed in the upswing in regional investment globally.1
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With this scale of demand and commercial pressure on owners and operators, every missed hour of production could mean millions of dollars of lost revenue; ensuring and maintaining asset reliability is critical, especially as the industry ventures into more complex, deeper, and more remote fields as seen across Brazil, Guyana and the Gulf of Mexico. One segment experiencing a particular upswing to meet this growing demand is the subsea sector, with investment estimated to reach US$15.3 billion by 2030 alone.2 This growth in demand sees partners throughout the value chain looking to suitably invest in technology to secure and deliver on what the industry needs. Two juxtaposed technologies where R&D continues is all-electric system solutions and perhaps surprisingly subsea control fluids, the life blood of all EH-Mux systems. Yet, with any industry, there needs to be field-proven solutions that are available today to meet the increased scrutiny with skyrocketing demand but without onerous costs. The industry is abuzz with talk of technology, such as all-electric, that can ‘solve all in one swoop’. But is there a risk getting carried away with the hype around the next big thing? Is there a danger that already available
technology that has proven its reliability and can deliver known performance and value today is being overlooked?
Making the most of what works
The all-electric future may be coming, but can it do all the industry needs it to? When it is considered that between 5 –10% of the 1200 xmas trees (XT) forecasted in the next five years will be all-electric, there is still a critical role that the EH-Mux systems should fulfil. Track record and technology readiness level (TRL) signals that hydraulics are here to stay and continue to be fundamental in ensuring the success of many new ventures and field developments. Hydraulic systems have evolved and do not present the revolution that all-electric could, however a gradual evolution is no bad thing. Decades of system design, analysis and re-work mean that systems are more optimised than a decade ago. They are also more reliable and benefit from having well known failure modes that help with further design optimisation to justify their use. This has only come with time. Whilst a small leak on an EH-Mux system can be addressed from the HPU without impacting production and keeping the well flowing, an interconnection failure or electronics failure in an all-electric system could require a more drastic intervention. Beyond the technical capability of subsea control fluids to ensure a safe and reliable operation of the system, an arguably even more fundamental element of their development lies in ensuring that the environmental impact of their use is minimised. Continued product development, investment and collaboration with industry regulators ensures that the impact of the fluid use is minimised. Yet, as has been seen, environmental standards continue to evolve, and legislative bodies such as OSPAR and OCNS necessitate sustained continued investment in ensuring a compliant product offering.
Learning not to compare apples and pears Figure 1. Subsea production.
Hydraulic and all-electric systems have the ability to co-exist, and this will be more apparent than ever as the energy transition journey continues. All-electric systems will help with the acceleration to decarbonise the offshore world, from platforms to the growth of wind and wave power. Investment in all-electric continues, and second generation systems and hardware are becoming available because of the numerous JIPs in place across the industry.
Foundations for the future
There is a lot of dialogue focused on the transition to all-electric technology. As the sector rationalises operations to reduce costs and boost efficiency, a rapid move to all-electric is a challenge and will not happen without through-life benefits being ratified. To unlock the true potential of all-electric, the collaborative journey of sustained investment must be continued, and the safety and reliability of these latest technical offerings must be proven. As the industry continues to focus on system uptime, reliability and overall sustainability, all-electric solutions do present an interesting value proposition, however, when the requirements are system solutions that can be relied upon today to unlock energy for the short and medium term, EH-Mux systems will continue to present a proven viable answer.
References Figure 2. Castrol subsea control system.
46 | Oilfield Technology Winter 2023
1. www.bp.com/content/dam/bp/business-sites/en/global/corporate/pdfs/ sustainability/group-reports/bp-advancing-the-energy-transition.pdf 2. www.globenewswire.com/en/news-release/2023/06/23/2693722/0/en/ Subsea-System-Market-to-Surpass-19151-Million-by-2030-Drives-Due-toRising-Offshore-Investments-Drive-Demand-for-Subsea-Systems.html
Ken Feather, TGT Diagnostics, UAE, explains how innovative acoustic array technology for well and reservoir flow dynamics can drive major operational benefits.
E
stablishing the details of fluid movement in wells and reservoirs is a complex and vitally important oilfield challenge. One of the biggest obstacles to improving well and reservoir performance is a lack of clarity with regards to flow dynamics. When engineers and asset managers have an accurate picture of what is happening in and around their wells, they can confidently select strategies that protect their assets, decarbonise operations, and enhance performance. Modern spectral acoustic systems have been successfully applied in wells around the world and can reveal a wealth of crucial information about well system flow.
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Untangling the challenges of acoustic interpretation
signals required for precision flow diagnostics. The well and near-well environment contains a range of different materials and fluids with varying acoustic properties, multiple physical boundaries and mechanical noise that combines to create a complex spectrum of acoustic energy. The accuracy of an acoustic diagnosis, and the quality of the decisions based upon it, hinges upon the fidelity and resolution of the sound recording and the effectiveness of processing and analysis technologies. Decoding complex sound signals and extracting useful flow information from them requires a special combination of technology, expertise and experience.
The sounds generated by fluids flowing in a well or in near-well reservoir zones can provide a wealth of information about reservoir architecture and flow dynamics. The principle behind spectral acoustics is to record and interpret the acoustic signals generated by flowing fluids. These signals may be generated by fluids flowing through a well or reservoir, or by fluid leaks in downhole components. Advanced analysis and interpretation of the signals offers crucial insights, enabling experts to assess well integrity, identify production and injection intervals, and provide a detailed hydrodynamic characterisation of the reservoir. The principle is simple, but in practice there are serious issues to overcome. The well reservoir system is an extremely challenging environment for capturing and analysing the high-fidelity sound
ACOUSTIC POWER SPECTRUM SD
ACOUSTIC POWER SPECTRUM HD APS CHORUS 10
DEPTH
WELL
61
M
SKETCH
0.1
APS CHORUS X
76 dB SPL 61 kHz
68 dB SPL
58.6 0.1
kHz
PHASE MAP
APL
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PHASE MAP
CHS 10
0.1
120 62 dB SPL 74 -1000
ACOUSTIC RADIAL MAP 1.0 0
mcsec
Cutting-edge acoustic technology
CHS X
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1 0
1000 0.00
m
1
0.18 0.19
m
NEAR
ZONE
1.00
61 dB SPL 75 16
18
SOUND SPEED
0.2 0.19
FAR
339.725 244.475 127
20
The oil and gas industry thrives on its ability to develop technologies that meet existing challenges and open up new possibilities. The key focus areas for operators are optimising energy and resource efficiency and maintaining or increasing production, SOUND SPEED MAP while ensuring that operations are safe and environmentally responsible. Advanced acoustic diagnostic systems play a crucial role in delivering these goals. TGT Diagnostics created the ChorusX acoustic array platform specifically to tackle these challenges. 1.0
m/sec
SPEED VALUE
5000 970
m/sec
1630
22
Reach, recognise and locate
24
26
The ChorusX technology has been designed to deliver performance in three areas: Extending spatial and audible reach to record the furthest and quietest flows. Recognising different types of flows. Pinpointing flow source locations with accuracy, in depth and radially.
28
ÌÌ ÌÌ ÌÌ
30
32
34
36
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Figure 1. The acoustic array platform homes in on the precise source of the signal and shows it with clarity and precision. The addition of phase and radial maps delivers a complete picture of flow events. PLT
LITH
DEPTH
PLT
WELL
m
500 m3/d 2500
SKETCH
PERM
TEMPERATURE
CHORUS 10
Perm
Flowing
ACOUSTIC POWER SPECTRUM
0.01 mD 10 106.4
°C
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106.6 70 0.1
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58.6 1
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ACOUSTIC PHASE MAP
ACOUSTIC RADIAL MAP 1 c.u. 0
0
120 -1500
mcs
1500 0
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distance (m)
1.5 -40
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N/F 180
114.3 X381.5
Single sensor acoustic power spectrum
X382.0 X382.5
Array sensor acoustic power spectrum
Combined Localised flow and Fracture flow signature
Far flow from fractures
Improving resolution, sensitivity, proximity, clarity and efficiency
X383.0 X383.5 X384.0 X384.5
PLT confirms ports outflow Gas flow from fracture
X385.0 X385.5 X386.0 X386.5 X387.0
Near flow from frac ports
X387.5 X388.0 X388.5 X389.0
Figure 2. The system separates flow events that occur close to one another. In this scenario, the phase map and radial map reveal the location of active fractures directly behind the frac ports.
48 | Oilfield Technology Winter 2023
The technology has a compact array of eight nano-synchronised sensors that record high-resolution flow sounds across an extreme dynamic range of intensities and frequencies. A phase analysis workflow combines specialised acoustic field modelling with a waveform-matching algorithm. This combination delivers new dimensions to acoustics and flow diagnosis, and locates and maps flow throughout the well system.
Advanced acoustic diagnostic systems offer better resolution, increased sensitivity, an indication of flow proximity relative to the well, greater clarity, and increased efficiency from the survey through to decision-making. The crucial difference is that it features an integrated acoustic sensor array. The presence of multiple sensors delivers a range of benefits when compared to single-sensor options. The first diagnostic benefit is improved resolution. The acoustic system operates at a 30 cm resolution, which is approximately three times better than the 80 –100 cm resolution
possible using the best single sensor systems. High-definition answers make it easier to pinpoint the precise location of singular or localised flows within the well system and the exact extent of distributed flow intervals. The second benefit is extended sensitivity, which is achieved through an expanded dynamic range that delivers improvement at the low energy end of the sound spectrum. This means the system can identify much quieter flow sounds, whether those are attenuated sounds coming from further away in the reservoir, or subtle sounds within the completion. A proximity assessment that determines whether a flow is ‘near’ the wellbore or ‘far’ in the reservoir is the third benefit. This helps to simplify analysis and improve the certainty of diagnosis when trying to unravel complex flow dynamics. The fourth benefit is increased clarity. The acoustic system features answer products that make it quicker and easier for analysts to reach a higher level of confidence in interpretation: The higher data density and higher-resolution power spectrum; the multi-sensor system triples data density to offer both better resolution and increased richness of data. The phase map offers an easy-to-interpret display where the shape of the phase shift transition indicates the type of flow; a singular flow such as a leak in tubing would have a sharp transition phase shift at a precisely defined depth, whereas distributed flow would have a more gradual transition. The radial map, which enables analysts to establish whether the flow energy originates from the near zone (well completion) or far zone (reservoir). This offers more clarity and certainty to interpretations. The sound speed map plots the speed of sound in the fluid surrounding the tool and can discriminate between inflows of water and gas. This provides an independent acoustic determination of fluid type that complements other fluid type indicators.
ÌÌ ÌÌ ÌÌ ÌÌ
The value of increased resolution and the new phase map and radial map tools is shown in Figure 1. In this example, the previous single-sensor generation of the platform indicates the effects of a flow event in the tubing-casing annulus that appears to be spread over a 4 m interval. Combining the higher-resolution power spectrum with information from the phase map and radial map products enables the acoustic system to narrow this down to within 30 cm and define the event as a singular, localised flow within the completion. The fifth benefit is greater efficiency, with the new system being more efficient across the workflow of surveying, analysis, interpretation and decision-making. The multi-sensor array gathers four times as much data as previous generations in half the time, and the new answer products help make analysis simpler and quicker. Improved clarity means that there is potential to accelerate decision-making, and greater accuracy increases the probability that remedial actions will succeed first time. Combining the answer products and multi-sensor capabilities enables oil and gas operators to address some fundamental challenges: Assessing whether an acoustic signal, and the associated flow event is from the completion or the reservoir. Identifying the failed component in a complex completion. Characterising low-flow-rate events and leaks with greater accuracy. Evaluating fracture performance and the effectiveness of stimulation programmes.
ÌÌ ÌÌ ÌÌ ÌÌ
Ì Ì Accelerating flow and integrity surveys in horizontal wells. Ì Ì Providing an independent, acoustic-based indication of fluid type.
Making sense of fractures
Acoustic array platforms such as ChorusX can distinguish between separate flow events, even when they are in close proximity (Figure 2). Being able to differentiate between flow types and locations makes it much easier to reach a solid conclusion about flow dynamics in complex settings and to select appropriate actions to correct any problems. In the example of a gas producer in a tight reservoir, ChorusX enabled analysts to distinguish between flows that were in close proximity and to differentiate between near-completion flows (at an inflow control device) and flows in the reservoir (fracture flows). The system’s data identified and precisely located fractures along the reservoir section. The survey also provided an accurate flow geometry that displayed the relative contribution each fracture makes to production. The acoustic radial map serves as a high-resolution, near–far indicator for flow and can distinguish between port flow and reservoir fractures in the immediate vicinity of the ports. The results provided the operator with valuable insights for optimising fracturing parameters and completion design for field-wide roll-out. This delivered savings in time, cost and resources, thereby helping operators access ‘hard to recover’ reserves in a more efficient and economical way.
Conclusion
Innovative acoustic systems can easily categorise and display flow events in high definition. These insights can provide compelling support for major operational or investment decisions. They serve as a springboard for actions designed to boost performance in a single well or right across a field. Detailed flow information can help operating companies manage resources, assess strategies for stimulation and find new ways to optimise production. Being able to diagnose well-system problems in unprecedented detail helps operators avoid the cost and disruption of unplanned downtime. The capability to locate and characterise induced fractures and to distinguish between different types of fluid flow makes innovative acoustic systems a good choice for operators who are seeking to refine and optimise recovery through stimulation programmes. Asset teams can decide how best to improve recovery rates or extend economic lifetimes. Maintaining high levels of well integrity, with the associated implications for safety, decarbonisation and environmental protection, is a key consideration for oil and gas operating companies. New systems can make a vital contribution to flow and integrity assessment and, through monitoring, help to minimise the risk of leaks or spills. In addition, by improving the efficiency of well operations and enhancing recovery rates, they indirectly help reduce the carbon footprint of the operation. Global demand for energy is rising, but the oil and gas industry is facing increasingly stringent environmental regulations. Operating companies are looking for new ways to maximise production and increase operational efficiencies while maintaining the highest standards of safety and sustainability. Innovative technologies are likely to be at the forefront of these efforts.
Winter 2023 Oilfield Technology | 49
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