Oilfield Technology Issue 2 2021

MAGAZINE | ISSUE 2 2021

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Contents 03 Comment

Issue 2 2021

Volume 14 Number 02

28 A leap forward in expandable liner technology Matt Godfrey, Enventure Global Technology, USA, outlines the features of a new development in expandable liner technology and describes its successful application in a commercial well.

05 World news 11 The tide is turning for the North Sea

33 Problem-solving, bit by bit

Martin Findlay, KPMG Aberdeen, UK, reports on the findings of a survey that show the Scottish oil and gas sector is on the brink of transformation.

Karl Rose and Danny Brietzke, Varel Energy Solutions, USA, highlight the field applications and achievements of three PDC bit platforms.

14 Avoiding ‘hollow out’ in the oil and gas supply chain

37 Responsive R&D

Barry Rust and Peter Bradshaw, Tata Steel, UK, consider the challenges facing the offshore supply chain industry, and the measures it can take, as the global transition to renewable sources of energy continues apace.

Scott Petrie, Adrilltech, UK, considers the development of continuous circulation systems and how the technology is being adapted in response to the pressures of the downturn.

41 Securing drilling data across the rig

20 The winds of change

Duncan Greatwood, Xage Security, USA, explains why security is a key precondition for efficient drilling operations.

Danny Constantinis, EM&I Group, Malta, outlines the asset integrity technologies being developed and deployed by the offshore industry during the energy transition to improve safety and reduce environmental impacts.

44 Malaysian mission Fuziana Tusimin, Latief Riyanto and Norbaizurah Ahmad Tajuddin, PETRONAS, and Mojtaba Moradi, Raam Marimuthu and Michael Konopczynski, Tendeka, reveal how the well performance of a complex oil reservoir offshore Sarawak was optimised by autonomous inflow control device technology.

25 Composite wrap vaccine Jean-François Ribet, 3X ENGINEERING, Monaco, shows how composite wrapping was used to repair a topside line experiencing damaging internal corrosion on a North Sea platform.

49 Unlocking stranded reserves Geoffrey Thyne, Vladimir Ulyanov, Brandon Skinner and Salem Thyne, ESal, USA, describe how simple technology could double the recoverable reserves in many fields while reducing operating costs.

Front cover SameDrift.(R) Single-Diameter Expandable Technology is the more efficient way to get through trouble zones.

Enventure’s SameDrift lets you extend a casing string to isolate trouble zones, while keeping the same ID. You can either tie back to the previous casing or simply clad the zone – or both. This groundbreaking technology will help you get through trouble zones more efficiently than ever before.

54 Switching on to electric control valves’

MAGAZINE | ISSUE 2 2021

potential

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Scott Losing and Andrew Prusha, Emerson, USA, explain how electric control valve drives are helping operators address methane emission regulations and adjust gas flow to maximise production.

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OFC OT Issue2 2021 indd 1

15/06/2021 16:00

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Copyright Palladian Publications Ltd 2021. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner.

All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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Comment Nicholas Woodroof, Deputy Editor

nicholas.woodroof@palladianpublications.com

Contact us

Editorial Managing Editor: James Little

I

s there any end in sight for the industry’s rollercoaster ride?

On the one hand, the price of Brent crude has reached the heady territory of US$73 a barrel; hefty contracts are being awarded for the Bacalhau and Tilenga projects in Brazil and Uganda respectively; and, as revealed by KPMG on pg. 11 of the magazine, contractor confidence in the UK Continental Shelf has rebounded impressively in the space of just six months.

On the other hand, the International Energy Agency recently published its ‘Net Zero by 2050’ report, with one of its many bracing conclusions being that investment in new oil and gas exploration projects must be halted immediately. While a report can be ignored, the judgements of shareholders or a court of law are less easy to shake off.

In a remarkable day for the Western oil majors (even by the standards of the past year), on 26 May ExxonMobil’s board was transformed by the appointment of three members keen to promote greener technologies, while Chevron shareholders endorsed a motion backing substantial cuts to the carbon emissions generated by the company’s products. Across the Atlantic, Shell – which on paper has a much more ambitious decarbonisation strategy than its American rivals – was ordered by a judge in the Netherlands to cut its carbon emissions by 45% by 2030 from its 2019 levels.

CEO Ben van Beurden said the company would appeal against the ruling, but conceded that Shell would look to accelerate its energy transition strategy.

Wood Mackenzie called the day’s events a ‘defining moment’ for the oil and gas industry. 1 The industry is now caught between impatient investors, civil society and governments wanting decarbonisation at a greater pace, and the need to meet the increasing demand for oil as the global economy tries to rebound from the effects of the COVID-19 pandemic.

As Barry Rust and Peter Bradshaw from Tata Steel argue in these pages, it is understandable therefore that offshore supply chain companies are struggling to come up with coherent, robust business strategies that look much beyond a few years ahead.

Ideas they suggest would help the offshore supply chain during the energy transition include increased early vendor engagement, greater dialogue and data sharing.

I’d recommend taking the time to read their article, which starts on pg. 14, with care: there’s a lot at stake if we don’t succeed.

Not that this uncertainty has stopped companies from continuing to innovate.

Take, for example, Neptune Energy’s repurposing of virtual reality (VR) technology originally developed to train astronauts bound for the International Space Station.

Neptune is now using the technology to allow workers to ‘visit’ and familiarise themselves with the Gjøa platform in the North Sea via interaction with a 3D model.

VR will also be used to obtain a clearer idea of the effect of any modifications to the platform, before they have actually been implemented. Perhaps it’s the millennial in me coming to the fore, but I enjoyed the element of gamification in this story.

I hope you enjoy reading this issue. If you have any feedback you’d like to share, please do not hesitate to email me at nicholas.woodroof@palladianpublications.com

james.little@palladianpublications.com

Senior Editor: Callum O’Reilly callum.oreilly@palladianpublications.com

Deputy Editor: Nicholas Woodroof nicholas.woodroof@palladianpublications.com

Design Production: Gabriella Bond gabriella.bond@palladianpublications.com

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Palladian Publications Ltd, 15 South Street, Farnham, Surrey GU9 7QU, UK Tel: +44 (0) 1252 718 999 Fax: +44 (0) 1252 718 992 Website: www.oilfieldtechnology.com

Reference 1.

CROOKS, E., Wood Mackenzie, ‘Big Oil’s watershed moment: five things you need to know,’ (11 June 2021).

Issue 2 2021 Oilfield Technology | 3

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World news

Issue 2 2021

Saipem, DSME JV to construct FPSO for Petrobras A joint venture of Saipem and Daewoo Shipbuilding & Marine Engineering Co. Ltd (DSME) has been awarded a contract by Petrobras to construct the FPSO P-79 as part of the development of the Búzios field offshore Brazil. The FPSO P-79 project is worth approximately US$2.3 billion overall. Saipem’s portion is approximately US$1.3 billion.

The FPSO vessel will allow initial separation of gas from the oil extracted in the deep offshore reservoir and will have a production capacity of 180 000 bpd and 7.2 million m3/d of gas, with a storage capacity of 2 million bbl of oil.

Saipem and DSME will execute the entire FPSO project, which encompasses the engineering, procurement, fabrication and integration of the topsides of the FPSO units and the installation of the mooring systems, as well as the hook-up, the commissioning and the start-up.

The Búzios field, the world’s largest deepwater oilfield, is located in the pre-salt Santos Basin, approximately 200 km off the coast of Rio de Janeiro, at water depths ranging from 1600 m to 2100 m.

There are currently four units in operation in Búzios, which accounts for more than 20% of Petrobras’ total production. The fifth, sixth and seventh platforms planned for the field (FPSOs Almirante Barroso, Almirante Tamandaré and P-78) are under construction and the ninth unit (P-80) is in the contracting process.

Lundin Energy sells oil certified as carbon neutral

McDermott to carry out work for BHP in GoM

Lundin Energy has said that all future barrels of oil the company sells from the Johan Sverdrup field offshore Norway will be certified as carbon neutrally produced under Intertek Group’s CarbonZeroTM standard. The field has been independently certified at 0.45 kg CO2e per boe, approximately 40 times lower than the world average.

In order to supply a fully carbon neutrally produced barrel, the residual emissions have been neutralised through natural carbon capture projects. As a result, there will be no net emissions released during the future production of Lundin Energy’s Johan Sverdrup net barrels, which currently amount to approximately 100 000 bpd.

The first trade of certified carbon neutrally produced oil from Johan Sverdrup has already been completed with the South Korean refiner GS Caltex. The 2 million bbl cargo will be loaded in July 2021 for delivery to South Korea.

McDermott International has been selected by BHP to provide a marine installation campaign for the Shenzi Subsea Multiphase Pumping Project (SSMPP). The project is located approximately 138 miles (222 km) offshore in the Gulf of Mexico at a water depth of 4400 ft.

The scope of the contract includes project management; design and fabrication for a pump station suction pile; umbilical installation and flexible jumpers and flying leads installation; transport of all materials and equipment; and pre-commissioning services and other necessary testing and surveys.

Engineering, procurement and project management services will be led by McDermott’s Houston engineering group.

McDermott’s North Ocean 102 vessel will be used for the transport and installation of the material and equipment.

The project will commence immediately and is expected to be completed in the summer of 2022.

In brief US Occidental is to sell non-strategic acreage in the Permian Basin to an affiliate of Colgate Energy Partners III, LLC, for US$508 million.

The transaction, which is expected to close in 3Q21, includes approximately 25 000 net acres in the Southern Delaware Basin in Texas with current production of approximately 10 000 boe/d from approximately 360 active wells. Proceeds from the sale will be applied towards debt reduction.

UK The organisers of SPE Offshore Europe 2021 have announced that the show’s face-to-face event is moving to 1 – 4 February 2022 at P&J Live, Aberdeen, and the conference will run virtually from 7 – 10 September 2021.

The virtual conference in September will include an opening ceremony, plenary panel, and keynote and technical sessions. The live event will include an in-person socially distanced exhibition, new energy transition keynote conference content, show floor features and networking events.

Norway Equinor has said that 3 – 4 new wells will be drilled at the Valemon field in the North Sea in 2021 and 2022 in order to extend profitable operations at the Heimdal field, which is processing gas from Valemon, to 2023. The extension will also enable production of the remaining reserves in Vale and Skirne and increase production from Valemon. When operations at Heimdal end the remaining gas reserves at Valemon will be transferred to Kvitebjørn and the Kollsnes plant for processing.

Issue 2 2021 Oilfield Technology | 5

World news

Issue 2 2021

Diary dates 21 – 23 September 2021 Gastech Dubai, UAE gastechevent.com

21 – 23 September 2021 SPE ATCE Dubai, UAE atce.org/welcome

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

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

Web news highlights Ì Ì Ì Ì

Transocean secures Norway contracts worth US$116 million Seabed Geosolutions awarded OBN project in Americas Shelf Drilling rig hired by Chevron EIA reports record oil and gas production in New Mexico

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

www.oilfieldtechnology.com

6 | Oilfield Technology Issue 2 2021

Lime Petroleum acquires Repsol’s Brage interest

Eni and SKK Migas sign exploration MoU

Lime Petroleum AS, a 90% subsidiary of Rex International Holding, has entered into a conditional sale and purchase agreement with Repsol Norge AS to acquire Repsol’s 33.8434% interests in the oil, gas and natural gas liquids (NGL) producing Brage field, and the five licences on the Norwegian Continental Shelf over which the Brage field straddles, for a post-tax consideration of US$42.6 million.

Approximately 1.38 million boe or 3800 boe/d were produced from the Brage field in 2020, net to Repsol’s working interest. Although the Brage field has been producing for a long time, work is still ongoing to find new ways of increasing recovery from the field.

According to the Norwegian Petroleum Directorate, there are 3.42 million m3 of oil equivalent or 21.52 million boe of remaining reserves in the Brage field.

Eni has signed a Memorandum of Understanding (MoU) with SKK Migas regarding cooperation on exploration activities in Indonesia.

The MoU defines the framework for further cooperation in the processing and interpretation of seismic data owned by the Republic of Indonesia by using Eni’s technologies and facilities, including the Green Data Centre supercomputers in Ferrera Erbognone, Italy, as well as seismic imaging algorithms.

Eni’s recent activities in the country include starting up gas production from the Merakes field offshore East Kalimantan in April 2021 and achieving positive results from the Maha-2 appraisal well in the West Ganal block in June 2021.

The company’s equity production in Indonesia currently stands at approximately 80 000 boe/d.

Bacalhau field development given go-ahead Equinor and ExxonMobil, Petrogal Brasil and Pré-sal Petróleo SA (PPSA) have decided to develop phase one of the Bacalhau field in the Brazilian pre-salt Santos area.

The investment is approximately US$8 billion. First oil is planned in 2024.

The Bacalhau field, operated by Equinor, is situated across two licenses, BM-S-8 and Norte de Carcará. The resource is a high-quality carbonate reservoir, containing light oil with minimal contaminants.

The development will consist of 19 subsea wells tied back to a FPSO located at the field. This will be one of the largest FPSOs in Brazil, with a production capacity of 220 000 bpd and 2 million bbl in storage capacity. The stabilised oil will be offloaded to shuttle tankers and the gas from Phase 1 will be re-injected in the reservoir.

MODEC, the FPSO contractor, will operate the FPSO for the first year. Thereafter, Equinor plans to operate the facilities until the end of the license period.

Lifetime average CO2 intensity is expected to be less than 9 kg/bbl produced, significantly lower than the global average of 17 kg/bbl. Work will continue through the lifetime of the field to reduce emissions and increase energy efficiency.

Subsea Integration Alliance has been awarded the contract for engineering, procurement, construction and installation (EPCI) of the project’s subsea production systems (SPS) and subsea pipelines (SURF).

Siemens Energy will provide pressure and temperature sensors for the subsea production system, electrical distribution equipment including flying leads, umbilical terminations, connectors for subsea modules and multi-leg harness assemblies. Installation and commissioning of the equipment are slated for 2022 and 2024.

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World news

Issue 2 2021

Africa Energy Corp., Total JV assessing early production system offshore South Africa

Havfram awarded FPSO contract for GTA project

Africa Energy Corp., part of the Lundin Group of companies, has said that the joint venture (JV) partners on Block 11B/12B offshore South Africa, which also include TotalEnergies, Qatar Petroleum and CNRI, are assessing the feasibility of an early production system for a possible phased development of the Paddavissie Fairway.

Block 11B/12B is located in the Outeniqua Basin 175 km off the southern coast of South Africa. The block covers an area of approximately 19 000 km2 with water depths ranging from 200 to 1800 m. The Paddavissie Fairway, located in the southwest corner of the block, now includes both the Brulpadda and Luiperd discoveries, confirming the prolific petroleum system.

The original five submarine fan prospects in the fairway all have direct hydrocarbon indicators recorded on both 2D and 3D seismic data and intersected in the wells, significantly de-risking future exploration.

Following the Luiperd discovery in October 2020, the JV partners decided to proceed with development studies and engage with authorities on the commercialisation of gas from Block 11B/12B. The JV expects to apply for a Production Right before the Exploration Right expires in September 2022.

Africa Energy Corp. holds 49% of the shares in Main Street 1549 Proprietary Ltd., which has a 10% participating interest in Block 11B/12B. Total E&P South Africa B.V. is the operator and has a 45% participating interest in the block, while Qatar Petroleum and CNRI hold 25% and 20% interests respectively.

Technip Energies has awarded Havfram a contract for the pre-installation and subsequent hook-up of the subsea mooring system for a natural gas FPSO to be deployed on the maritime border of Mauritania and Senegal as part of the Greater Tortue Ahmeyim (GTA) project.

The GTA project will provide gas to both the domestic market and the wider market via the inshore LNG hub/terminal.

Havfram will project manage, engineer, transport and install some of the largest ever driven piles and corresponding mooring lines.

Havfram will later return to hook-up the pre-installed mooring system to the FPSO on its arrival at the field.

The FPSO will be stationed 35 km from the shore in approximately 120 m water depth.

US$2 billion Tilenga EPCC contract awarded

Serica Energy reports positive Rhum flow test

ExxonMobil makes new Stabroek block discovery

A consortium of a subsidiary of McDermott International, Ltd. and Sinopec International Petroleum Service Corp. has received a conditional Letter of Award for a future contract valued at approximately US$2 billion from TotalEnergies for the Tilenga project.

Formal contract award remains subject to the Tilenga Partners’ approval.

The Tilenga project is located in the Lake Albert Basin, Republic of Uganda.

Tilenga includes six oilfields and will feature 426 oil wells at full production.

The consortium will provide engineering, procurement, construction and commissioning (EPCC) services for the development of an onshore oilfield that will generate up to 200 000 bpd. It will consist of 31 well pads connected to a central processing facility (CPF) via buried flowlines.

The project will be led from London, UK, and Yangzhou, China, before transitioning to Uganda for the construction activities. Work began in 2Q21 and first oil is expected in 2025.

Serica Energy has said that new completion equipment has been successfully installed into the Rhum R3 well in the UK North Sea and a flow test has now been performed.

A stabilised flow rate of 58.4 million ft3/d of gas and 135 bpd of condensate has been achieved through a 60/64ths in. choke. The rate was constrained by the surface well test equipment on board the WilPhoenix semi-submersible drilling rig, and it is expected that the well will be able to produce at higher rates when in production.

A diving support vessel has been contracted to install the subsea control equipment required so the well can start producing in 3Q21.

The recompletion of R3 will increase Rhum’s production capacity, utilising the existing facilities located on the Bruce platform, and will not lead to significant additional CO2 emissions, in line with Serica’s objective of reducing the carbon intensity of its production operations.

ExxonMobil has made a discovery in the Stabroek block offshore Guyana. Drilling at Longtail-3 encountered 230 ft (70 m) of net pay, including newly identified, high-quality, hydrocarbon-bearing reservoirs below the original Longtail-1 discovery intervals. The well is located approximately 2 miles (3.5 km) south of the Longtail-1 well. It was drilled in more than 6100 ft (1860 m) of water by the Stena DrillMAX. The Longtail-1 discovery was drilled in 2018, encountering approximately 256 ft (78 m) of high-quality, oil-bearing sandstone reservoir.

ExxonMobil has deployed two additional drillships in 2Q21, the Stena DrillMAX and the Noble Sam Croft, to enable further exploration and evaluation while continuing development drilling activities offshore Guyana. As the company advances its 15-well campaign in the Stabroek block, DrillMAX will move to Whiptail-1 while the Noble Sam Croft supports development drilling for Liza Phase 2.

8 | Oilfield Technology Issue 2 2021

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THE TIDE IS TURNING FOR THE

Martin Findlay, KPMG Aberdeen, UK, reports on the findings of a survey that show the Scottish oil and gas sector is on the brink of transformation.

I

t is no exaggeration to say that the Scottish oil and gas sector is at a tipping point.

The transition from carbon-based to sustainable energy sources represents a huge opportunity for the country’s oil and gas firms.

But, while the COVID-19 pandemic has put huge pressure on many oil and gas businesses, it has also created a new sense of political confidence for policy makers grappling with the energy transition, accelerating the journey along the road to a low carbon future. No doubt the COP26 conference in Glasgow later this year will focus minds even further.

Against this backdrop, the results of the latest Aberdeen & Grampian Chamber of Commerce Oil and Gas Survey are striking, and show a sector that is primed for change.

The survey, conducted in partnership with the Fraser of Allander Institute and KPMG UK, gathered the views of 100 firms that employ 27 400 workers in the UK (and more than 183 000 globally) and covers the six months to April 2021.

Almost half (49%) of contractors now say they are on a recruitment drive as they embrace change in the sector, with three-quarters (75%) planning a move into renewables work in the next three to five years – more than in every other survey since the question was first asked in 2015.

More than two-fifths (44%) said they are already moving to diversify away from oil and gas and will accelerate this strategy.

This should help put to bed the common misconception that the oil and gas industry is the cause of much of the climate crisis, when it is actually often the driving force behind the renewables revolution.

Indeed, the firms surveyed in the report said oil and gas will account for less than three-quarters of their business activity by 2025 – down from the current average of 86%.

But, while firms appear convinced of the opportunities available in the renewables sector and are taking action to make the most of this new revenue stream, this will require investment.

Driving diversification It is heartening to see contractor confidence in the UK Continental Shelf (UKCS) bounce back so robustly, from a net balance of -76% six months ago as the peak of the pandemic’s second wave loomed, to 6% this spring.

A pressing paradox Unfortunately, the global impact of the pandemic means these firms are approaching this crucial phase in their evolution from a relatively fragile position.

| 11

The challenges faced over the past year are reflected in the reduced level of reported activity in production and exploration work, with the net balance reported for production related activity of -15% indicating a continued overall decline, although this has eased from the -47% reported in 2020.

The level of demand is the most pressing worry for contractors, remaining a very important concern for three-quarters (75%) of those surveyed.

Still, this is no time to prevaricate.

While it is the larger corporates that are currently driving the sustainability agenda, it is the smaller supply chain firms that are crucial to its delivery.

It is a paradox that they are also often the firms that have the fewest resources – including capital and expertise – to invest in transitioning to a more sustainable footing.

But if smaller operators want to remain part of these supply chains, they will have to align themselves with corporates’ environmental agendas.

Transition targets That is laid clear in the research, with more than a third (37%) of firms saying they would evaluate their suppliers’ carbon footprints when awarding or renewing contracts – a figure that KPMG would only expect to grow in coming surveys.

When asked about their plans to reach net zero, only around a quarter of firms (27%) have set their own carbon neutral target, with their ambitions ranging from 2030 to 2050.

This aligns pretty well with a key commitment in the UK Government’s North Sea Transition Deal, which lays out targets to reduce emissions by 10% by 2025 and 25% by 2027 and has committed to cut emissions by 50% by 2030.

Just 3% of the firms in the Aberdeen and Grampian survey had already achieved net zero, while almost two-fifths (38%) said that, while they are

committed to becoming carbon neutral, they have not set a deadline for achieving it.

Firms cited a range of reasons for committing to reduce their emissions, with a fairly even split between environmental concerns (56%), a desire to increase their sustainability or longevity as a company (51%) and a drive to improve perceptions of their own business (50%).

An initiative that is purely driven by image enhancement is inadvisable – any firm perceived as greenwashing their operations risks being quickly called out for it, causing potentially catastrophic commercial and reputational repercussions.

Pride in pioneers The report finds an industry on the brink of transformation, with Scottish firms gearing up to deliver the energy transition.

Though many told researchers they feel hamstrung by their shaky financial position, it is expected that their sentiment will strengthen going forward, given that the majority of this survey was conducted before the announcement of the aforementioned £16 billion North Sea Transition Deal in late March.

The deal includes a commitment to support Scottish supply chains; by 2030, 50% of offshore decommissioning and new energy technology projects must be provided by local businesses.

Those firms that are taking action to build and retain a competitive advantage now will surely benefit as net zero ambitions become an increasingly tangible part of the procurement process.

As we emerge from the pandemic, there is an amazing opportunity to harness the skills and capabilities of Scotland’s oil and gas sector to steal a march in hydrogen production, carbon capture, offshore wind and decommissioning.

While Scotland and the North Sea have previously been synonymous with oil and gas exploration, there can be confidence that future generations will take pride in its pioneering role in the green energy transition.

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AVOIDING

‘HOLLOW OUT’ IN THE OIL AND GAS SUPPLY CHAIN

Barry Rust and Peter Bradshaw, Tata Steel, UK, consider the challenges facing the offshore supply chain industry, and the measures it can take, as the global transition to renewable sources of energy continues apace.

T

he offshore oil and gas industry is currently experiencing challenges and changes on two fronts.

Firstly, the COVID-19 pandemic, which has forced reductions in global travel and restricted industrial output due to workplace closures, has, until recently, had a significant negative impact on oil prices.

However, the short-term effects of the pandemic have merely exacerbated a long-term challenge for the offshore sector, which is the second issue facing the industry – an anticipated decline in demand as consumers look towards more renewable sources of energy and multi-modal transport options.

Driving greater decarbonisation Around the world, more and more countries and companies, led by societal demands for change, are setting goals to reduce carbon emissions. In 2019, the UN announced that over 60 countries, including the UK, had committed to carbon neutrality – or net zero – by 2050. However, a number of others are working towards an earlier deadline (in Scotland the target date is 2045; Microsoft plans to be carbon negative by 2030; and Apple has promised to become fully carbon neutral by the same time).

This trend can be seen in the oil and gas industry too, where several major operators – including Equinor, BP, Shell, Total and Eni – have announced their commitment to net zero emissions strategies. Some have also signalled diversification from their core business into renewable energy sources.

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The industry’s greater focus on sustainability is also being felt across the offshore supply chain, where companies are developing wide ranging, detailed and robust decarbonisation programmes that meet client and wider stakeholder ambitions.

One example of the sector’s understanding and accepting of the need to adopt more ambitious decarbonisation measures has been the recognition by steel manufacturers of the important role they can play in more sustainable pipeline manufacture.

For instance, Tata Steel has announced a target to reduce CO2 emissions by 30% before 2030 and aims to be a carbon neutral steelmaker by 2050. Already one of the world’s most CO2-efficient steel companies, in the last 30 years the company has reduced its CO2 emissions per tonne by approximately 15%. However, its ambition is to continuously improve its production processes and efficiencies.

The company recently started the first phase of its Everest project to capture CO2 from blast furnaces and transport it to former gas fields in the North Sea for storage. The second phase will see the company use blast furnace emissions for conversion into sustainable raw materials for the chemical industry and synthetic fuels.

Tata Steel recently announced that HIsarna, its reactor for lower carbon steel making, had exceeded expectations in sustainable steel production, with the possibility of achieving

a CO2 reduction of more than 50%. HIsarna has been in development since 2011, and the aim is for it to be operating at full scale with the potential to replace an existing blast furnace.

The reactor can cut up to 80% of CO2 emissions when combined with carbon capture and, in combination with an electric arc furnace, can allow for the recovery of zinc – often found in scrap – for reuse.

It is fair to say that the challenge of increased decarbonisation is one that the offshore industry is aware of and generally accepts. Across the offshore supply chain, there are examples of companies that started in hydrocarbons now reviewing their markets and current propositions – and some are moving into new verticals where a cross transfer of skills allow.

The ‘hidden’ challenge for oil and gas

However, another less visible challenge to the energy sector and its customers and consumers at large exists.

While the global transition to renewables may dominate many of the headlines, oil and gas still accounts for more than 50% of global energy demand today and will continue to play a major role in the world’s energy mix for decades to come. In its 2020 Energy Outlook, BP suggests between US$9 trillion and over US$30 trillion will be required to be spent on upstream activity over the next 30 years.1 Data from Wood Mackenzie also suggests that, whatever the pace of the energy transition, the world will still rely on oil and gas for much of its energy needs well beyond 2040. 2 Indeed, there are concerns that existing production will decline faster than global demand unless more is spent on developing already identified discoveries or, where these are uneconomic, exploring for new ones.

Such intense market volatility and lack of clarity adds to the confusion for offshore companies trying to make sound investment decisions while planning and developing robust and fit-for-purpose business strategies. A recent report from PwC highlights the challenge: do oil service companies follow their customers into low carbon markets, or do they double down on hydrocarbons to become ever more cost-efficient?3 Of course, a third option for some companies would be to do both.

It is widely accepted that the world will require a range of energy solutions – including fossil fuels, Figure 1. HIsarna, sustainable steel manufacturing. renewables and nuclear – to meet its future needs.

However, in the current challenging financial environment, where thousands of offshore oil and gas jobs are being lost worldwide and companies consider a move into the renewables sector, there is a fear that the offshore oil and gas supply chain could be hollowed out to such an extent that gaps in service provision and product delivery could occur in the future. Those offshore supply companies that are trying to maintain operations today with uncertain order books and no clear sight of light at the end of the tunnel may face extremely difficult decisions in the short term. For the operator community, this could be interpreted as a stark ‘use it or lose it’ warning from their suppliers.

It is therefore arguably more important than ever that, where possible, operators and the offshore supply chain, companies and clients work together to share whatever information they can for the greater economic good of all.

Figure 2. HIsarna cast house. Hot metal flows from the forehearth into a torpedo ladle.

16 | Oilfield Technology Issue 2 2021

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Increased early vendor engagement – a solution One way to achieve this would be through offshore operators adopting a policy of greater early vendor engagement.

An important step forward in this regard at an industry level would be for operators, industry organisations and governments to further increase their efforts to share the broad visions they see for the offshore sector. While accepting that commercial confidentiality is critical and detailed plans could not be provided (nor would they be expected), there may be general forecasts or trends in offshore investment cycles that operators could divulge with the supply chain to give its members greater clarity, to support their future direction and avoid gaps in support provision. Events such as share fairs organised by operators – which have been so popular over the years – or business updates from industry bodies and governments can provide excellent opportunities for operators and the supply chain to share what they expect to see in wide-ranging terms from a business and industry perspective.

At a more direct level, early engagement and integration with a chosen supplier or the original equipment manufacturer (OEM)

to determine specific project requirements can often generate financial efficiencies in the total cost of project ownership and risk profile, while simultaneously reducing operators’ carbon costs.

More dialogue and data sharing Greater digital integration, data transparency and dialogue between clients and vendors are ways of supporting such ambitions. The ability to collect vast amounts of data, analyse it and provide it in a structured manner at the point of decision-making can revolutionise offshore supply chain manufacturing.

As an example, Tata Steel uses dynamic data analytics to support steel manufacturing through to processing to produce its steel products. The data is connected to create an aggregated ‘digital passport’ for every product, and provides a thorough process database that grows over time and is further modelled by analysts. This process involves modelling and analytical techniques, including the development of visual representations for those that run the facilities – in the form of an online decision support tool – which is incorporated into process control and planning systems.

The ability to ‘fingerprint’ the process, with a complete understanding of how inputs at any point in production impact upon the product output, provides powerful support for optimised manufacturing.

Increased dialogue and data interchange across the offshore supply chain can lead to greater efficiencies (whether that is specification negotiation or quality documentation for approval) and support decarbonisation. An example of efficiency enhancement in the pipe manufacturing sector would be integrated pipeline tracking and tracing systems, and there are currently discussions within the sector on the adoption of a supply chain-wide, standardised system. Furthermore, horizontal collaboration across supply chains, such as the industrial clusters established in parts of the UK, can be a solution to help individual companies meet their CO 2 reduction targets. It will be by accepting such a range of initiatives that the challenge of optimising activity in the North Sea will continue to remain alive.

Avoiding a supply chain ‘hollow out’ Figure 3. Supporting the energy transition.

The global energy industry is in the midst of a transition towards greater decarbonisation and an increased adoption of renewable sources. The transition has broad agreement and is critical.

Hydrocarbons will continue to play a key role in the energy mix for decades to come as part of that transition. As the oil and gas supply chain considers its future and where best to allocate its resources, it is essential that companies in this sector have as much visibility of future industry projections as possible. This will ensure that oil and gas is able to play its full role in the energy transition, and continues to have a robust supply chain ready to support it.

References 1.

2.

3.

Figure 4. A robust supply chain is essential in order to avoid ‘hollow out’.

18 | Oilfield Technology Issue 2 2021

BP, ‘Energy Outlook: 2020 edition’, https://www.bp.com/content/dam/bp/ business-sites/en/global/corporate/pdfs/energy-economics/energy-outlook/ bp-energy-outlook-2020.pdf LATHAM, A., and WILSON, A., ‘Why exploration will be critical in meeting future demand’, https://www.woodmac.com/news/feature/explorations-future-in-alow-cost-low-carbon-world/ PwC, ‘Time to choose: oil services at a strategic crossroads’, https://www. strategyand.pwc.com/gx/en/insights/2021/oil-services-at-strategic-crossroads. pdf

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THE WINDS

T

he offshore energy industries face significant challenges in a period of transition from fossil fuels to renewable energy. It has taken over a century to master the fossil fuel industries, but the climate change objectives agreed by most nations now demand that the change to renewables will have to be much faster if global targets for reduced carbon emissions are to be reached.

Public awareness of human safety has also, rightly, come under scrutiny, with regulators in most countries insisting on higher safety standards, including in the energy producing industries.

Extreme weather events, which many believe are caused by climate change, have also become

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more frequent and this has cost the countries concerned thousands of lives, billions of dollars and countless problems in trying to cope with the after-effects of fires, floods and hurricanes, etc.

Fortunately, most of the major polluting nations have signed up to the basic principles of the climate change initiative and are taking steps to meet their commitments; as climate has no borders we will all have to work together to solve this problem.

Similar problems have been faced before, such as the so-called ‘hole’ in the ozone layer, which was caused by greenhouse gases such as chloroflurocarbons (CFCs), typically used in refrigerators. International action, such as the

OF CHANGE Danny Constantinis, EM&I Group, Malta, outlines the asset integrity technologies being developed and deployed by the offshore industry during the energy transition to improve safety and reduce environmental impacts.

Montreal Protocol, helped to ban the use of such gases and the problem has almost been resolved, but it has taken over 30 years so there is little likelihood of a ‘quick fix’.

The effects of the COVID-19 pandemic have given a glimpse of what life could be like with lower levels of pollution and encouraged the adoption of alternative methods of transport and working.

However, the world’s energy demands continue to rise, so it is clear that efficient, low-cost and, above all, clean energy is key to solving the problem.

The challenge of achieving much more efficient and environmentally low impact

methods of finding, producing and burning hydrocarbons is evident to all, including the major producers which are themselves moving swiftly to change their business models towards renewable energy.

The challenge is how to manage this transition to cleaner, safer and low-cost energy in the offshore industry.

Dealing with the challenges With the amount of technology available and the speed of further development in all areas, meeting the challenge starts with a clear definition of aims and then gathering stakeholders together to solve the problem.

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JIPs – defining and encouraging solutions

Improving oil

Joint industry projects (JIPs) are an important part of the solution, where major stakeholders work together to solve common problems, agree on standards and encourage or fund solutions.

The EM&I Group has led a JIP on behalf of the Global FPSO Research Forum called Hull Inspection Techniques and Strategy (HITS), which has produced a number of innovations and technologies over the last eight years, including diverless inspection and maintenance (ODIN®), remote inspection of tanks (NoMan®) and reduced need for tank cleaning.

New JIPs, such as the ‘FloGas’ JIP for floating gas assets, e.g. FLNG, FSRU and FSRP vessels, are already underway and other JIPs are being discussed for managing the integrity of floating wind assets.

From onshore to offshore the oil industry has developed dramatically over the last century and overcome tremendous engineering challenges in both exploration and production. However, it is now largely governed by fluctuating and short-term demands for oil and returns for shareholders.

This is a difficult juggling trick for an industry that requires long-term investment decisions. Inevitably this results in a ‘stop-go’ industry that can move from glut to dearth quite quickly. Many experts think that ‘peak oil’ demand has already been reached, and that the industry will gradually stabilise and then wind down over the next 30 years or so as reliable, alternative, renewable and ‘greener’ sources of energy become commercially available.

Oil will still be required in the short to medium-term for transport, lubrication and chemicals but in the meantime, greener, more efficient and safer methods of operation and maintenance are required to attract investment.

Assets will increasingly be based in deep water with fewer personnel on board (POB). This objective requires remote inspection, maintenance and production technology such as diverless and unmanned tank inspection methods.

Inspection strategy will change from a means of discovering anomalies to one where remote monitoring determines and predicts fitness-for-service, and inspection is simply used to confirm the monitoring data.

Digital data offers major improvements in how asset integrity is assured. It is clear that many inspection and maintenance costs can be safely reduced by analysing data to obtain better and faster insights into plant condition.

Figure 1. ExPert scanner.

Increased use of gas Many see floating gas as a transition energy source from oil to renewables, and it has become a fast-developing market as it is a relatively clean, plentiful and low-cost fuel that can now be produced offshore by FLNGs. Gas supplied to FSRUs also provides a ‘quick fix’ electricity supply for many isolated or emerging economies with little or no infrastructure.

Most of the integrity challenges and solutions associated with FLNGs are similar to FPSOs, although FRSUs are often moored on jetties in river estuaries and generally near population concentrations.

Lack of water clarity, strong currents, port and terminal operations and sophisticated gas containment systems pose challenges for integrity assurance, but nevertheless improved remote inspection technology will ensure that floating gas will be an important part of the energy mix for many years to come.

The future – renewables Figure 2. Hull repair using diverless caisson.

Renewables are the future for clean, green energy, much of which will be offshore, from wind, wave or tidal energy solutions. The principal problem is ‘intermittency’, as these energy sources cannot guarantee 24/7 power and battery technology is not sufficiently developed to cope with peak power for more than a few hours at the most. ‘Back up’ power will therefore still need to be available to cope with peak demand until battery technology or other solutions can be developed.

Gas-powered solutions would appear to be the obvious choice to reduce carbon emissions, with nuclear being an efficient but socially unpopular option.

Floating wind shows real promise

Figure 3. Laser image of cargo oil tank.

22 | Oilfield Technology Issue 2 2021

Wind – particularly offshore and floating wind – would appear to be one of the most promising of all the renewables. It does not take up any valuable land space or create any noise problems offshore.

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Shallow water fixed bottom solutions have already been installed very successfully in many countries throughout the world.

However, the most attractive option is for floating wind turbines, which can be installed in more productive and available acreage and even relocated if required.

Floating turbines can be huge – up to 20 MW capacity currently with 100 m blades, so capable of generating considerable energy in the wind speeds available in deepwater locations.

While they are technically quite different from floating carbon-based units, many of the technologies developed for inspecting and maintaining floating assets can be adapted for the floating wind sector, noting the benefits of asset duplication and the need for lower unit costs.

The future of floating wind asset integrity may well include high levels of monitoring and resident robots where appropriate.

The many infrastructure and regulatory challenges, as well as design standardisation, will need to be addressed as the market develops and the transition from fossil fuels accelerates.

Other renewables will form part of the offshore mix Wave energy is another promising technology that could be combined with the floating wind market. Many different solutions have been developed, from articulated ‘worm-like’ floating chambers – which

Figure 4. LNG storage tank.

bend in the waves to generate power – to underwater ‘paddle’ type structures, which move back and forwards in the motion of a wave to generate power.

Developments driven by tides and currents are moving forwards, with the potential for overcoming ‘intermittency’ by combining multiple energy solutions in one asset. This may well also reduce overall costs and avoid the need for multiple transmission systems.

Asset integrity challenges A consistent challenge for all the changes described is the need to manage and assure the integrity of offshore assets.

Clearly, unmanned renewable assets will pose a lower risk to safety than heavily populated FPSO and FLNG units. However, the risk of a large floating wind turbine breaking free of its moorings and damaging other units and the subsea infrastructure is something operators, owners, insurers and regulators will want to avoid.

Asset integrity strategies and methods have advanced hugely in the last few years to become much more economic, efficient, safer and greener.

Some of these diverless, robotic and digital technologies are readily adaptable to the diverse types of asset that will be used to overcome the challenges encountered offshore in the coming years.

ODIN diverless hull and valve inspections and repairs have been used successfully on hundreds of projects throughout the world in the last few years. Cost benefits of over 50% and 70% POB have been achieved, and all these technologies can be used while the vessels are on station, on hire and in operation, reducing the need for shutdowns or out of service periods.

NoMan technology that uses remote cameras and ‘synchronised’ laser scanning for tank and confined space inspections is replacing manned entry, significantly reducing the safety risks associated with confined space entry and working at height. By way of example, a 90% reduction in man time was achieved on a recent North Sea project.

ExPert™ is intended for the non-intrusive and remote inspection of Ex electrical items. This technology can ‘see through’ electrical components and detect any anomalies without having to isolate or dismantle them. Ex equipment that normally requires rope access for close inspections can now be inspected using robotic cameras in under 50% of the time, without the risk of working at height.

ANALYSE™ optimises the inspection of pressure systems. By using a combination of both risk-based inspection (RBI) and probability theory, this has made it possible to safely reduce the number of thickness readings to establish the level of safety required. Savings of over 60% have been achieved on recent projects.

HullGuard® is used for the diverless cathodic protection of hulls and sea chests, using retractable impressed current cathodic protection (ICCP) anodes. These can be readily installed through class-approved access ports in the hull or sea chest – either in the shipyard or retrofitted at any stage during the life of the asset. They can also be retracted for inspection, cleaning or replacement whenever required.

LORIS™ has been created for the inspection and temporary repair of mooring chains and risers; the LORIS robot can swim to, attach itself and climb up and down the items to be inspected. Armed with measurement and inspection tools and robotic arms, the system can operate in much harsher conditions than free-swimming ROVs or divers.

Conclusion

Figure 5. NoMan camera on telescopic pole.

24 | Oilfield Technology Issue 2 2021

The offshore industry is constantly faced with new challenges that have to be addressed if we are to survive. Fortunately, the industry is innovative and resilient and will find solutions that improve safety, environmental impact and efficiency.

COMPOSITE WRAP VACCINE

Jean-François Ribet, 3X ENGINEERING, Monaco, shows how composite wrapping was used to repair a topside line experiencing damaging internal corrosion on a North Sea platform.

A

geing offshore platforms face numerous problems with their topside lines today.

Due to the harsh offshore conditions, external and internal corrosion are common problems. In addition, due to normal (and sometimes inadvertent) operations, they are also subjected to dents and cracks, which are other types of defects identified in oil and gas operations. In the worst case scenario, these may lead to through wall defects and associated loss of primary containment, generating serious safety and environmental issues.

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Despite these issues – which can be critical – the platforms need to produce continuously, and shutdown is rarely an option; if it must happen it can only be for a very short time according to the pipes and to their functions.

3X ENGINEERING (3X) specialises in maintenance solutions for the oil and gas industry, including leak sealing systems,

anti-corrosion products and composite repairs to restore pipe integrity and for structural matters.

REINFORCEKiT® 4D (R4D) is a permanent composite repair system for pipelines and piping experiencing corrosion-related defects and mechanical damage. Made of an epoxy resin and bi-directional woven high-strength Kevlar® aramid-fibre material, the system is a non-metallic technical alternative to metal clamps, welded sleeves and pipe replacement. Thoroughly tested by third-party laboratories, it can restore pipe integrity in compliance with applicable standards such as ISO 24.817 and ASME PCC-2.

R4D composite is applicable in environments ranging from onshore transmission pipelines and refinery piping to offshore piping, risers and even sealines. The company has over 30 years of experience in composite repair for pipe and pipework repairs, with a particular focus on subsea composite repair. Several R&D projects intended to expand the limits of composite repair are ongoing, such as online leak sealing, high-temperature solutions or deep subsea repair.

Case study

Figure 1. R4D composite repair wrapping in subsea environment.

Figure 2. Energy release rate – qualification of R4D system at high temperature.

3X and its partner in the North Sea were asked to repair a pipe on an offshore platform that had a substantial hole due to internal corrosion. The damaged area was located on a 4 in. pipe near a flange.

The challenge was to implement a solution that took into consideration the harsh environment, the damaged state of the old pipe section and the considerable size of the hole. It was thus decided to install R4D to seal the leakage and reinforce the damaged area. A condition of the intervention was to install the composite repair at an ambient temperature (during shutdown of the line), which was more or less 20˚C; after the repair, the line would operate again at 70˚C. A defect assessment was provided and calculations using the company’s REA software program made it possible to propose a technical offer and a repair design that complied with the ISO 24.817 standard. Once the go-ahead was given by the client, the job could start.

A surface preparation was made in order to achieve a good surface state and surface profile. This preparation made it possible to remove rust and obtain a sufficient roughness to ensure good bonding between the steel and the composite. It was performed with a Bristle Blaster® machine.

A roughness test surface profile evaluation was carried out to check the quality of the blasting. A test was conducted across different locations of the pipe. Using a roughness comparator, it was established by 3X that the roughness was acceptable and superior to 60 µm.

Before applying the resin, it was important to make sure that the hygrometric conditions were satisfying. Tests were carried out using a calibrated hygrometer.

The company’s requirements, in terms of climatic conditions, are: Dew point at least 3˚C below the pipe surface temperature (∆T>3˚C).

Moisture lower than 85% relative humidity (RH).

Surface temperature superior to 10˚C.

Ì Ì Ì

Figure 3. Hole defect overview.

26 | Oilfield Technology Issue 2 2021

The whole prepared surface was then cleaned with acetone and white rags in order to remove any residual contaminants, such as dust or grease, from the carbon steel substrate.

The first step of the proper repair was to apply the filler with a plate to cover the hole for leak sealing purposes. The filler was selected according to its high mechanical properties and chemical resistance.

The second step was the application of the chemical-resistant epoxy resin on the prepared surface to transfer the loading from the piping to the composite sleeve.

The third step was the application of the Kevlar roll on the wet surface. It was wrapped helicoidally around the straight pipe with 50% covering with continuous tape impregnation. The wrapping on the straight part started from one edge with a turnaround for the first lap to prevent any sliding of the tape. After that, the tape was shifted to obtain a 50% overlap of the previous layer. The wrapping job was made by applying a regular tensile strength. When the pipe was fully covered by the impregnated tape, the first pass was achieved. The wrapping had to be continued to the other sides and so on and so forth.

Figure 4. Repair overview with ID plate installed for traceability.

Once the tape was positioned on the pipe, it was immediately impregnated with 3X resin and testing and a job report was issued to the end user for their wrapping continued. records.

The final step was to apply a final layer of resin all over Conclusion the repair to ensure good wetting of the fibres and give a good Despite the striking features of the defect, it was repaired surface aspect. To finalise the repair, an identification plate successfully. The company can now also perform hole repair was applied on the composite, enabling traceability of the repair. online through its FIXOKiT® engineering solution.

Eventually the curing was followed up by hardness (shore D)

A leap forward in EXPANDABLE LINER

TECHNOLOGY

Matt Godfrey, Enventure Global Technology, USA, outlines the features of a new development in expandable liner technology and describes its successful application in a commercial well.

T

he SameDrift expandable mono-diameter liner, the latest development in expandable technology by Enventure Global Technology, allows wells to be designed for a larger envelope of capabilities. It was developed with the goal of isolating fluid losses or wellbore intrusion encountered while drilling, thus enabling optimal inner diameter (ID) during extended reach drilling. The liner also includes several other advantages that only come with a mono-diameter system. Planned-in and/or contingency SameDrift liners will ensure that trouble zones are isolated from the start, with no effect on the diameter of the wellbore, completion design or other wellbore contingencies. Maintaining the same drift means operators can reach their extended reservoir section at

28 |

planned or larger ID to optimise production rates. The liner also opens opportunities for reducing costs by implementing light casing designs. High departure wells tend to use multiple casing strings to reach target depth (TD) with an acceptable ID; SameDrift can be planned-in to minimise the need for intermediate or isolation strings, thus reducing the cost of casing, mud and cement as well as rig time.

The liner is deployed with an expansion assembly on drill pipe made up at the bottom of an expandable liner string.

The expansion assembly enables torque to be transmitted to the liner while running in hole, allowing full rotation of the system. Once run in to TD, the liner may be cemented in place, or uncemented using conventional or swellable elastomers to clad into the openhole. The expansion assembly contains a segmented cone that forms downhole using a jack mechanism. Expansion is initiated by landing a wiper dart into the shoe at the bottom of the expandable liner

to create a pressure chamber. Pressure is increased, causing the jack to activate and stroke the cone segments together into a fully built conical shape, while radially expanding the liner in the process. A casing lock, which carries the weight of the liner while running in hole, is mechanically timed to release the casing when the cone is formed and locked to full diameter. Expansion begins at this point, as indicated by a clear pressure and hook load drop at the surface. Through the combined use of overpull and hydraulic pressure, the entire length of the liner is expanded from bottom up in a similar operation to conventional solid expandable liners by leaving the liner shoe at TD.

Once the liner has been expanded, the fully built cone exits the top of the release joint. The release joint contains a proprietary connection that is designed to part as the cone expands through, creating the re-entry guide for subsequent operations through the expanded liner. It also allows the final few feet of the liner to be expanded with a combination of hydraulic force and overpull, rather than relying solely on overpull and risking dragging the liner up hole and out of position.

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Figure 1. Extend casing strings or isolate multiple trouble zones.

After the cone exits the release joint, the cone’s diameter is too large to convey back to the surface.

A retract ball is dropped, which unlocks the cone and shifts the cone into its smaller segmented outer diameter (OD), allowing the expansion assembly to be pulled out of hole and leaving the expanded liner in place.

The expanded liner may either be deployed as an openhole clad, which is a liner that covers and isolates the trouble section of the openhole, or as a planned-in liner. In the application of installing SameDrift as a planned-in liner and/or contingency, a short receptacle is required to clad into and tie the system back to the previous base casing string. The receptacle is a section of the larger OD/ID casing crossed over at the bottom of the previously installed casing string. Its length is determined by the length of the expandable liner, the post-expanded shrinkage calculation and the pilot hole length, and is typically just a few joints in length.

Both methods require the formation to be drilled and underreamed, in order to provide radial space to allow for the SameDrift liner to be expanded and to allow for a good cement bond around the expanded liner.

A key advantage of the technology is that it allows for subsequent clads of the same drift diameter to be run in below the previous clad or liner.

SameDrift is currently commercially available in three post-expanded drift sizes: 6 1/2 in., 8 1/2 in. and 12 1/4 in. The 12 1/4 in. size is available in standard and high performance (HP) versions. The HP version offers increased burst and collapse ratings, if required. During the development phase of the tool, extensive use of finite element analysis and other stress state calculations were employed to verify the strength and dynamics of the internal mechanisms and their functionality in a wide range of potential wellbore environments. This approach ensures that the mechanisms are robust enough to function as intended downhole.

Each commercially available size has been successfully tested in a laboratory setting and downhole on a test rig environment to verify the functionality of the internal mechanisms, including cone build, expansion, cladding and cone retraction. In addition to testing the normal tool functionality, there are several built-in contingency mechanisms within the tool to allow the operator to release the expansion assembly from the liner in the event that the liner becomes stuck. These contingency scenarios have also been successfully tested in the laboratory and downhole.

Case study

Figure 2. One-trip expansion: expansion only takes one trip and is continuous from the bottom to the top, which lowers non-productive time.

30 | Oilfield Technology Issue 2 2021

During 3Q20, the 12 1/4 in. Standard Wall SameDrift was successfully deployed in a commercial well, with all installation objectives being met. This application was a planned-in installation as an openhole clad. Total unexpanded clad length was 251 ft. In this application, the operator had set 13 3/8 in. casing and was drilling the 12 1/4 in. section below while underreaming to 13 1/4 in., starting at the bottom of the 13 3/8 in. shoe at 5325 ft to TD at 5748 ft. This installation was elected to be installed as an openhole clad and rely on anchor hangers to provide isolation of the section rather than cementing.

The anchor hangers are a joint of expandable pipe with

an elastomer element bonded to the outside. As the openhole clad is expanded, the anchor hanger is compressed either against the formation or casing to provide an anchor and a seal. A caliper run was performed prior to the installation to gauge the openhole section and determine the most effective placement of the anchor hangers along the liner string.

The openhole clad was made up to length with four precisely located anchor hangers and run in hole to TD on 5 in. drill pipe.

Using a safety sub connection, the drill pipe was stabbed into the expansion assembly at the bottom of the expandable openhole clad. Lastly, prior to running in hole, the release joint was stripped over the drill pipe and made up as the upper most joint in the expandable openhole clad.

The openhole clad was then run to TD, and the wiper dart was loaded and pumped through the drill pipe at 4 bbl/min. and 300 psi until it landed in the shoe. Pressure integrity was verified, and pressure was increased at 1/4 bbl/min. until verification that the cone was formed and locked. The cone was fully formed at 3700 psi, and expansion began. This was verified by clear indications of hook load drop and pressure drop at the surface.

Flowrate was increased to 2 to 3 1/2 bbl/min. once operations shifted from cone building to expansion mode. The first stand was expanded with pressures fluctuating between 2100 and 2500 psi.

Expansion continued in this range until all three stands were expanded and the cone exited the top of the release joint, signalled by a total loss of pressure. Once expansion was complete, the cone retract ball was dropped to seat within the expansion assembly.

Pressure was increased to 2800 psi until the cone retraction was verified by a subsequent loss in pressure and regain of circulation.

Tools were tripped out of hole and laid down at the surface.

Once the openhole clad was expanded, a mill run was performed to drill out the shoe, dart and float equipment.

Milling was completed with an 11 in. junk mill and 13 ¼ in. section mill. Once milling was completed, the openhole clad was drifted and confirmed to have a 12 1/4 in. post-expanded drift, indicating a successful installation.

With the 12 ¼ in. drift expanded openhole clad in place, the client was able to drill a 12 1/4 in. openhole beneath the expanded openhole clad for an additional 2113 ft. An extensive formation sampling programme was then undertaken by the client with two wireline logging runs and three conditioning bottomhole assemblies (BHAs) through the installed openhole clad. The subsequent 9 5/8 in. conventional liner string was run through the SameDrift openhole clad and cemented back into the 13 3/8 in. base casing string. The successful operations through the 12 1/4 in. openhole clad were used as confirmation of the overall success of the installation. The value added to the client was a system that can be used to isolate losses or trouble formations without losing drift diameter, allowing for continued drilling with the same BHA through trouble zones without deviating from the planned well completion.

Conclusion In summary, the SameDrift openhole liner or openhole clad can provide permanent isolation of weak formations and ensure optimal ID at TD. The technology enables optimum fluid design, which reduces formation instability and non-productive time as well as the chances of lost BHAs. SameDrift also enables optimum well design to further step out for extended reach applications.

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PROBLEM-SOLVING,

BITT BY BIT BI Karl Rose and Danny Brietzke, Varel Energy Solutions, USA, highlight the field applications and achievements of three PDC bit platforms.

C

omplex modern wellbores place extreme economic and performance demands on drill bits. Improvements in drilling efficiency – in order to put more energy downhole – demand a response from drill bit solutions to build angle, hold trajectory and effectively drill through changing formation tops.

As a result, a wide array of bit advances are being methodically combined to produce a new generation of specialised but adaptable drill bits. Three new bit platforms from Varel Energy Solutions (VES) are demonstrating how collaborative problem-solving can successfully meet the demands of modern wellbore designs.

| 33

Bit engineering Each bit is engineered to address the problem at hand – either to hold direction, provide the responsiveness and consistency needed to effectively build angles or deliver the durability and speed required to drill efficiently in long laterals with potential transitions. Leveraged by a customer-focused workflow, integrated software applications and a versatile set of attributes, these bit platforms have been developed to consistently meet customer needs.

Figure 1. 360˚ Workflow process.

At the centre is the 360˚ Workflow, an iterative process by which the company’s sales professionals engage the customer. Its focus is on continuous improvement through effective planning, support during the run and by incorporating operational results into the next planning cycle.

Integral to the workflow is a suite of software tools aimed at an applications-based approach to solving problems. In the pre-job initiative, GeoScience – an application for understanding the formation and lithology in the drilling application – is used to assess the expected drilling challenges. Next, PDC Designer and Dig3D simulate bit design parameters through cutter force, work rate, imbalance forces and formation to bit contact area. In post-job initiatives, drilling logs are evaluated in single or multi-well formats with outputs that are accurate and easy to follow.

The data and recommendations from this tool set of integrated software are utilised and communicated by the company as customers are engaged through the workflow. The accuracy of these tools allows operators to have confidence in the results and have more trust in the outputs, and therefore know that performance will be optimised to meet drilling economic requirements.

Bit technologies

Figure 2. Integrated software solutions.

As solutions emerge from the 360˚ Workflow, customised bit attributes are developed and applied across the product line. The bit designs are further optimised for the application and operator objectives through selective use of these attributes, which include cutter technology and hydraulics enhancements.

VENOM™ Cutter methodology matches optimal diamond grades to the application, while enhancing them with specifically engineered shapes. Diamond cutter attributes include abrasion, impact resistance, thermal stability, cutter strength and cutting efficiency.

Particularly suited to increasing speed and durability in laterals runs, COBRA™ Shaped Cutters combine a sharp-edge cutter and leading-edge geometry. The design creates a stress point to pre-fracture the rock for a higher rate of penetration (ROP) in brittle formations, even with heavy transitions.

Combining computational fluid dynamics (CFD) with cutting structure design, the HYDRA™ hydraulic system applies webbed blades, curved nozzles and engineered junk slots to enhance cuttings evacuation and cutter cooling and improve cutter face cleaning.

Drilling through transitions

Figure 3. Day/depth curve for VION 616.

34 | Oilfield Technology Issue 2 2021

Drilling through transitions when necessitated by current well designs requires increasing durability and speed. The challenge can be complex due to directional requirements and varying formation tops. In tangent and intermediate intervals, drilling may range from all-rotary to the use of positive displacement motors (PDMs) or with rotary steerable system (RSS) tools, while transition zones vary from soft to hard formations.

The VION PDC ‘Tangent’ Drill Bit series is designed to provide a balanced cutting structure profile that

adds the bit stability necessary to overcome the ROP and durability challenges of drilling transition zones and abrasive formations. Its toughened cone, strengthened nose and shoulder and the addition of advanced attributes contribute to achieving both a greater durability and ROP.

Directional drilling

The operator pursued many attempts to complete the section in a one-bit run and less overall time in hole. Through the 360˚ Workflow, process engineering identified the most appropriate cutter placement strategy to match the application using the VION 616 design platform.

A second Cotton Valley benchmark one run performance saved 20 hours. The application involved drilling a vertical/tangent interval from the bottom of the Travis Peak into the Cotton Valley formation.

The VION 616 bit, with enhanced hydraulics and design features specific to the applications, drilled the interval.

Historically, all offsets required multiple bits and associated tripping costs; the operator’s fundamental objective was to complete the vertical/tangent interval in a single run.

Collaborating with the drilling engineer in post-run analysis, the company’s applications engineers analysed formation characteristics

In directional drilling applications building angle is essential, as it requires a high degree of responsiveness and consistency. These applications in directional intervals often include bottomhole assemblies (BHAs) with a variety of motors and RSS, encountering varying lithologies in a single run.

To address this scope of use, the EVOS PDC Directional ‘Build’ Drill Bit series is designed to achieve the best possible ROP while achieving a high degree of tool face control with a consistent yield, regardless of the directional drive system.

Critical to development of the series was bit-to-rock contact simulation within the 360˚ Workflow and the use of customised tool face geometries that enable solutions across a diverse set of directional applications. DIG3D, a tool within the 360˚ Workflow, is critical to EVOS development by simulating bit-to-rock contact, which in turn is critical to directional response.

Chassis design, cutting structure arrangement and tool face wear element locations are engineered based on these outputs. This creates a design system with a passive tool face during kick-off that is receptive to directional input and has sufficient side-cutting capability for ROP gains as the trajectory is established.

Figure 4. Cotton Valley VION 616.

In horizontal and combined drilling applications, holding direction with speed and low walking tendencies is essential. With the aid of PDC Designer, designers minimise bit imbalance, creating the HAVOX PDC ‘Hold’ Drill Bit series. Its gage configurations are engineered and tested to maintain trajectory based on the directional system requirements – this yields smooth torque with consistent trackability and creates strong wellbore quality, minimising doglegs and making it that much easier to get casing to bottom.

Case histories In a wide range of applications around the world, VES’s bit platform designs have shown the effectiveness of the 360˚ Workflow and software in addressing many of the challenges currently faced by drilling operations.

Figure 5. Abu Dhabi 16 in. EVOS 616.

East Texas In East Texas, VION product solutions are demonstrating success. A 9 7/8 in. drill-out scored record one-bit performance in the intermediate section in the Haynesville’s Travis Peak/Cotton Valley formations.

The VION 616 bit with HYDRA hydraulics and VENOM shaped cutter technology drilled the moderate to hard interbedded shale, limestone and silt.

The bit completed the approximately 8500 ft interval in one bit run and 4.59 days, producing a superior performance for the section and formation.

The run was more than 64% ahead of the average footage for all offset performances. The intermediate section typically required two to three bit trips, costing an average of between US$65 000 to US$70 000 per trip.

Figure 6. Kuwait 9.25 in. EVOS 616.

Issue 2 2021 Oilfield Technology | 35

and design attributes in conjunction with offset run data and dull studies. A rapid design project produced the winning solution.

Abu Dhabi and Kuwait Drilling operators in Abu Dhabi and Kuwait using EVOS bit designs surpassed conventional ROP records in finishing build sections for onshore and offshore wells.

Offshore Abu Dhabi, a 16 in. deviated section marked a new field record with a 14% increase in ROP compared to the top four field average. The bit drilled in interbedded limestone, dolomite, anhydrite and shale formations with an RSS. The EVOS 616 bit drilled a total footage of 5823 ft at 130.9 ft/hr, outperforming the field average of 115.1 ft/hr and area record of 118.7 ft/hr.

VES’s proposal leveraged the EVOS solution-based bit platform.

The solution was a six-bladed, 16 mm cutting structure steel body bit for optimum open face volume. VENOM cutter technology applied a shaped ARTIMIS cutter to increase cutting efficiency by pre-weakening the rock.

Onshore in Kuwait, an EVOS 616 steel body bit on a hybrid ‘push and point’ RSS drive system increased ROP by 21%, drilling the build section at a field record speed of 19.9 ft/hr. Previous wells in the area produced an ROP of 16.4 ft/hr when drilling the 9 1/4 in. build section through interbedded limestone, dolomite and shale.

Using a hybrid push and point the bit RSS system, the operator wanted to complete the entire 9 ¼ in. build section with one run while maintaining high ROP, lowering the average cost per foot drilling cost.

The bit technology used a steel body, six-bladed, 16 mm cutting structure configuration for optimal open face volume. A specific cutting structure and gage configuration were aimed at optimising toolface control through better torque management and greater stability.

Figure 7. Eddy County, New Mexico, 8.5 in. HAVOX 616.

New Mexico and North Dakota In New Mexico and North Dakota, the ROP improvements achieved with the HAVOX design have significantly reduced drilling time and days per well.

Drilling the second Bone Spring lateral encountered sandstone and siltstone formations with high unconfined compressive strength (UCS), abrasion and thermal challenges with moderate to low impact conditions.

To improve interval performance and reduce overall days on a well in Eddy County, New Mexico, a HAVOX bit design was selected.

Using VENOM cutter technology with COBRA shaped geometry, the target interval was drilled 3.4 days faster than prior runs and competitor offsets on RSS. In collaboration with the drilling engineer, VES’s engineers used GeoScience Studies software to analyse formation characteristics in conjunction with offset run data and dull studies, which identified an opportunity for improved performance through enhanced cutting efficiency. A design project incorporated the latest 8.5 in. 616 design development and shaped cutter technology, improving performance over several wells on the pad.

The bit’s first run saw an increase of 53.1% footage drilled and 10.5% higher ROP compared to the baseline performance. Further proof of the design was seen on the second run, which produced a 130% gain in footage drilled and 62.3% higher ROP. The bit drilled the fastest lateral for the area and was 3.4 days ahead of the next fastest offset. Improved performance and collaboration over all drilling operations resulted in the well reaching total depth (TD) 12.2 days ahead of schedule.

In Dunn County, North Dakota, a HAVOX 613 bit drilled the fastest two-mile First Bench Three Forks lateral in 54 total hours.

The operator record, based on more than 900 wells targeting the Three Forks formation in the Williston Basin, was 7.5 hours, or 13% faster than the previous record.

The application drilled the lateral in shale, limestone and dolomite formations with moderate UCS, abrasion, thermal and low impact conditions. The operator’s objectives were to complete the entire two-mile lateral in one bit run, improve ROP and reduce the overall time in the hole.

The solution used VENOM Cutter methodology to place COBRA shaped cutters into the previously successful baseline of the bit design. The baseline bit used planar cutters in the primary row and had been run successfully near the new well location.

Through the application of proprietary software and analysis of previous dull conditions the optimal cutter arrangement was designed to improve cutting efficiency.

The baseline bit with planar cutters was outperformed by the COBRA cutter version by 4014 ft and an ROP of 15 ft/hr. It improved over the average offset run footage drilled by 53% and gained 17% ROP.

Conclusion

Figure 8. Dunn County, North Dakota, HAVOX 613.

36 | Oilfield Technology Issue 2 2021

The company’s drill bit platforms will continue to be scientifically matched to current and future tangent, directional and hold applications.

Understanding the application with clear definitions of as many variables as possible sets the stage for starting the workflow process. This then results in matching the core design requirements for tangent, directional or hold layouts while determining how to apply the proper attributes of cutter technology and hydraulic enhancements.

The end result is value that is provided and realised in reduced drilling costs.

Scott Petrie, Adrilltech, UK, considers the development of continuous circulation systems and how the technology is being adapted in response to the pressures of the downturn.

RESPONSIVE R&D M

anaged pressure drilling (MPD) technology is now seen as a mature drilling technique, more of an accepted norm than the niche, novel technology it was 10 years ago.

When MPD was developed, continuous circulation systems were perceived as a secondary, less capable offering. However, 15 years on and, in areas where cost considerations are paramount, continuous circulation has firmly established itself as a high value, lighter footprint solution that is quickly deployable to drill depleted formations for gas storage, geothermal or enhanced oil recovery (EOR) applications.

By diverting flow from the standpipe via a dedicated port in the side of the drill string and therefore isolating the top drive from the inside of the drill pipe, the pipe can sit in slips while circulation continues through the pipe/annulus and back to the active pit.

Once the top drive is isolated and bled down, the next stand can be picked up and connected to the stump without stopping circulation.

Flow is then re-established through the top drive and the hose used to circulate while the connection is made, is bled down and disconnected. The string is then picked up out of slips and rotation restarted before going back to the bottom and drilling ahead.

| 37

System deployment is relatively simple, small and non-invasive, with much of the technology employed being standard oilfield equipment: hydraulically activated 10 000 psi gate valves, modified Kelly valve submersibles and conventional high-pressure and low-pressure pipework. Systems can be operated remotely and are non-electrical.

The key, patented technology of the system consists of the non-return valve in the side of the Kelly valve submersible, which is rated to 15 000 psi.

Development of continuous circulation systems Following Eni’s development of early continuous circulation systems for use in the Mediterranean, ExxonMobil pioneered use of the technology for drilling in remote locations where heavy losses were being experienced. Adrilltech has spent the last 11 years further developing the technology with lessons learned from over 100 operational deployments around the world; in multiple operating

Figure 1. NSD hose with quick connector.

Figure 2. NSD sub with ball valve.

Figure 3. NSD rig floor arrangement.

38 | Oilfield Technology Issue 2 2021

environments, including onshore, offshore, shallow water, deepwater and high-pressure, high-temperature (HPHT) – both alone or with MPD – the technology has delivered value.

As with many new technologies, development of the Non Stop Driller (NSD) system was driven by necessity. While drilling top hole sections in the mountains of Papua New Guinea with fresh water, ExxonMobil was driven to seek an alternative approach as a result of experiencing total losses, lost bottomhole assemblies (BHAs) and an inability to reach section total depth (TD). By switching to foam drilling with a 3-phase separation system, some of the issues were alleviated. The change required rotating control devices (RCDs) to be installed, yet with 1600 psi of air pressure there still existed the issue of bleeding down and defoaming over each connection. This could result in connections taking an hour, bringing into question the viability of foam drilling these wells. By introducing the NSD system, which is capable of continuous flow throughout the connection process, the need to bleed down and defoam was removed and continuous circulation could be maintained while the next stand was picked up. Several days of rig time were saved per well, giving ExxonMobil the confidence to attempt directional work and drive section TD and casing setting deeper in the formations. Following the technology’s first successful campaign, further improvements were sought – the next stage of any work where underbalanced drilling (UBD) and air drilling are being used to simplify processes.

At the time, MPD technology was becoming increasingly viable and therefore, following detailed FEED engineering, the value of combining MPD and the NSD system was established, with the combination of technologies enabling very narrow pore pressure/fracture gradient (PP/FG) window wells. MPD with NSD was applied to difficult drilling environments in Malaysia, Egypt and the Netherlands on multi-well campaigns.

During the development of the technology much has been learned regarding the benefits of continually circulating the well.

The process was seen to allow maintenance of stable equivalent circulating density (ECD) and continuous cleaning of the wellbore over connections, improve management of high specification mud systems and reduce weight-to-weight times during drilling and tripping operations. These improvements are seen whilst simultaneously reducing non-productive time (NPT) and assisting with the detection and management of well control events – often encountered during pump-off events and connections. Additionally, continuous circulation has been shown to enable the maintenance of the downhole tool temperature at safe, stable levels in HT applications.

Responding to the downturn Despite these benefits, technology continuously evolves and during the recent downturn application of technology has been limited by many factors. Cost reduction, a lack of dedicated engineering resources to qualify new technologies, a switch in contracting philosophy to integrated services and changing regulatory approaches discouraging the use of new technologies are among the many issues faced when attempting to introduce innovative technologies. These constraints are driving developers to pivot into spaces where technology is most needed, applying R&D efforts towards increasing value though improved rate of penetration (ROP) and reduced NPT alongside removal of personnel from the rig site via digitalisation and automation. NSD’s development has sought to meet these challenges head-on, developing the technology to reduce the cost of deployment, automate systems, train rig crews to use and service the equipment and offer the system for sale to drilling contractors. Specifically, driven by industry-wide ambitions

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to reduce risk by removing personnel from the well centre, NSD has introduced a re-designed continuous circulation system that allows fully automated, hands-free operations to be performed, eliminating the need for personnel in the red zone and allowing rig crew to operate the system from the safety of the doghouse. It has additionally focused on developing engineering capabilities and FEED for specific projects, helping to clearly identify where value is added.

Widespread acquisition of additional downhole information from pressure while drilling (PWD) has allowed more detailed studies into the technology to be carried out, demonstrating ROP advances and improved outcomes from circulating over connections while drilling and tripping, particularly in depleted or unstable formations.

Over the last two years, Adrilltech has identified several niche technologies which, when used either in combination with NSD or with each other, can bring added value with limited additional people at the rig site. An example is the combination of NSD with DrillClean, a cuttings volume management system. The combination allows accurate measurement of the volume of cuttings returned to the surface throughout the drilling of a section, even over connections, while pressure variations that may be related to cuttings loading can be measured and managed, avoiding hole cleaning issues and ensuring optimal ROP for drilling the well. The company has launched seven similar technologies that are effective both when used individually and when utilised in combination.

The successful application of new technologies cannot happen without effective management of change. Safety statistics when implementing new technologies are often highly favourable, as the first use of novel technology is usually closely scrutinised to ensure initial deployments are successful. A substantial part of the pre-planning phase is devoted to performing HAZID/HAZOP assessments, identifying all key interfaces and ensuring that

adequate control measures are in place at every interface to significantly reduce the risks associated with any first-time deployment. Although adding value is a fundamental KPI for the first use of any technology, it is universally accepted that safety must be of primary concern; if additional time is required to ensure that everyone is trained, familiarised and working to the common goal of successful and safe implementation of the technique, then the process can be deemed successful. With new technologies, teams often begin with a healthy scepticism and there is a learning curve to follow. However, they quickly become enthused with new methods if they are seen to improve their work practices. Managing this change to get to this stage is crucial to the success and longevity of any project.

Conclusion NSD continuous circulation has reduced overall section days in multiple wells and has a small and easily managed rig site footprint.

Change is forever a feature of the drilling industry: the management of that change is vital to ensuring that new technologies add value with immediate effect. Adrilltech’s technologies aim to make the drilling process more efficient, reducing the overall carbon footprint of well construction whilst helping operators to drill lower cost wells with the fewest people at the rig site. Throughout the technologies’ development many different applications have been identified and realised by different operators. Applying these advances to the nascent energy transition, the company have been active in the drilling of difficult geothermal wells, such as improving hole stability during the drilling of ash and tuff deposits, while looking to minimise cost per foot drilled and maximising megawatt output per dollar input. The equipment helps drilling efficiently to TD, protecting expensive BHAs from temperature and risk while drilling the lowest cost high-enthalpy geothermal wells.

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SECURING DRILLING DATA

ACROSS THE RIG Duncan Greatwood, Xage Security, USA, explains why security is a key precondition for efficient drilling operations.

I

n drilling operations multiple different systems operate on the same rig in silos, creating inefficiencies that have for decades been accepted as inevitable – the nature of doing business.

Oil and gas exploration and production spans multiple parties and platforms, meaning that data generated during the drilling process on-site is typically isolated in each contractor’s network and analysed independently. Operator and vendor systems looking at seismic properties, vibration systems, pressure systems, fluid density and temperature are commonly siloed to reduce the risk that no system is compromised.

That being said, this separation has not come without consequences: the inability

to aggregate data, combined with the slow turnaround of off-site analytics, slows the processing of information and impedes operators’ ability to make adjustments in real-time – resulting in excess downtime, lost revenue and the possibility of high risk scenarios for on-rig operations.

What many operators do not realise is that there is another way. Security technologies and strategies have advanced to a point where secure remote access and data sharing among multiple vendors on-rig is now practical, and can create opportunities to improve well construction results, fill competency gaps between contractors and enable more efficient working environments.

| 41

Granting secure remote access to multiple parties Most oil rigs have a handful of active parties working on the same drilling project, making access to one another’s systems and data a key roadblock to efficient oil and gas production. When there is one party monitoring conditions downhole and another responsible for the fluid going down, the parties need to be aligned and in sync to avoid costly mistakes. For instance, if the viscosity needs to change, each party at the site needs access to that information in real-time for that change to be made both quickly and safely.

To complicate matters further, fear of cyber-compromise of other contractors’ remote access method results in a proliferation of different access approaches, each having its own particular defects and cyber vulnerabilities that could affect drilling. To grant local and remote access in a truly secure way oil and gas operators need a common approach – one that embodies the principles of zero trust. They need remote and local access solutions that can grant authorisation to specific users, applications and devices to conduct a controlled set of interactions in a restricted window of time, blocking the risk of cyber cross-contamination between systems and preventing operational disruption due to the failure of an individual access mechanism. By using identity-based access models instead of perimeter-based models, oil rig operators can establish a secure environment for all users and applications to work together efficiently, whether remote, local or third party.

Once access is hardened and streamlined, operators can then provide a secure, controlled and trusted medium for real-time data

exchanges between previously isolated network segments and systems.

Enabling secure data sharing to drive digital transformation With the deployment of data sensors in exploration, drilling and production operations, oil and gas has become a data-heavy industry.

Managing information on-rig, from multiple sources, is an important process that all producers need to master if they want to maximise efficiency from the early planning stages to final well production.

The invention and application of new data recording techniques combined with artificial intelligence has made it easier to leverage the benefits of data analytics in drilling operations, but unless data is trusted and secure producers will continue to be reluctant to carry out multiple party data assembly and analysis at the rig. According to Deloitte, the adoption of connected technology in the oil and gas industry has outpaced the integration of holistic cybersecurity measures designed to protect a mix of legacy systems and newer technologies – making operators a ripe target for cyberattacks.1 Fortunately, advancements in cybersecurity are filling this gap. In the past year new technologies emerged that enable forward-thinking oil and gas operations to facilitate secure data sharing between multiple parties, from on-rig, to enterprise, to cloud. They make it feasible for multiple participants and their applications to both access and publish data securely so they can work together, in real-time, without losing control or exposing themselves to cyber risk.

The following are two examples that demonstrate how zero trust remote access combined with secure data processing and sharing can help operators and contractors improve operational efficiency and drive business outcomes.

Example 1: drilling (down)time

Figure 1. Rig operators must be able to aggregate and analyse data in real-time to make informed decisions and avoid costly disruptions.

Figure 2. Drilling operations are distributed and collaborative environments by nature – necessitating secure, granular remote access control and data sharing across multiple parties.

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Industry research has documented numerous cases where real-time downhole measurements, provided by wireline in a test environment, are different to those at the surface.2 The surface consists of multiple sensors and systems that process data separately and remotely, and analytics used to obtain information about the drilling mud pumped downhole can be inconsistent, resulting in slower drilling times to completion. However, if operators are able to securely combine and analyse multiple data streams on the rig itself, it is then possible to modify drilling parameters in real-time and increase efficiency.

A select few oil and gas companies have already started adopting these more modern security strategies, and the benefits have been stark. One oil and gas supermajor needed to analyse seismic and microseismic data to improve reservoir characterisation and simulation, reduce drilling time, ensure drilling safety, optimise production pump performance and improve asset management.

They experienced challenges with data quality due to operational latency, and had difficulty aggregating multiple sources of data and ensuring the data’s objectivity on-rig and from on-rig to the data centre. In these environments data is siloed by vendor, such that security and integrity issues exist between the vendors and the rig operator. In this case, the rig operator needed a secure and high integrity way to collect and share data at the rig, in real-time, to improve drilling outcomes.

To address these challenges, the company identified a data security solution from Xage Security that used a zero trust approach.

As a result, the operator aggregated trusted production data at the rig while blocking the risk of cybersecurity issues spreading from one rig system to another. At the same time, the solution enabled data to be shared safely between the rig and the customer’s centralised, off-site data centres.

With zero trust remote access, this secure edge analytics solution established trust across multiple entities; through techniques such as logging while drilling (LWD) and measurement while drilling (MWD), data was created by and shared among contractors on-rig, allowing it to be analysed as it was generated.

By integrating data from traditionally separate systems such as those that manage mud tanks, the rig floor and hazardous gas properties, the solution made a significant difference. Access to this shared data on-rig allowed operators to head off drilling issues that slow or stop the drilling process, decreasing well completion time to 2.5 days per drill cycle compared to the previous 14-day average.

In this scenario, a secure data sharing solution allows for the analysis of data on the rig, ensuring that information can be seen by all authorised parties and allowing the parties to have confidence in the data. Furthermore, with zero trust remote access all parties can access relevant data on the rig and confidently process and share key data in real-time.

The ability to securely collaborate between sources in this way allows operators to react to information on the spot, optimise the weight and torque parameters being applied to the bit, successfully reduce vibration and improve operations immediately.

The secret to faster drilling and better wells Example 2: vibration data Vibration measurements offer another example of how a lack of information about drilling parameters in real-time can impact oil operations, as poor weight transfer and poor torque transfer typically reduce drilling performance by 40 – 50%. Vibrations also negatively impact the life of the drill string, bottomhole assembly components and surface equipment, which can result in catastrophic failures and costly downtime.

A great deal of collaboration is needed to understand and mitigate vibration, but in most cases the broader engineering team does not have sufficient data access to understand instantaneously what is happening downhole. With current methods, critical and expensive downhole equipment can be several miles from the rig floor (especially with long laterals), making it impossible to know with any degree of accuracy their behaviour and the surrounding bottomhole conditions.

Whenever data is sent back to a central location to be analysed and compiled this creates a clear gap between the downhole and surface data while drilling. Moreover, because data is typically not shared between vendors/contractors, it is impossible to make modifications with accurate and consistent real-time multi-source data.

With the ability to securely communicate, collaborate and share data between all sources – for both downhole and surface components – the onshore and offshore drilling environments will enter a new era.

By enabling secure local and remote access, and aggregating and controlling multi-vendor data and analysing it on-rig, operators and their subcontractors can share real-time measurements that improve operational efficiency and safety, and can capture revenue that would otherwise be lost.

A system that can facilitate secure remote access and data sharing in a multi-party rig environment unlocks a level of reliability and flexibility that is novel to many oil and gas operations, yet is shaping the future of the industry while accelerating its digital transformation.

References 1.

2.

MITTAL, A., SLAUGHTER, A., and ZONNEVELD, P., ‘Keeping drilling data safe: Cybersecurity for upstream oil and gas’, https://www2.deloitte.com/content/ dam/Deloitte/de/Documents/energy-resources/CybersecurityforOG_factsheet. pdf PASTOREK, N., YOUNG, K.R., and EUSTES, A., ‘Downhole Sensors in Drilling Operations’, https://pangea.stanford.edu/ERE/pdf/IGAstandard/SGW/2019/ Pastorek.pdf

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MALAYSIAN MISSION W

ell completion design with inflow control devices (ICDs) is one of the important steps in efficient field development planning. It has a strong influence on not only the production profile but also the economics. Technology advances, in conjunction with drilling capabilities, have significantly improved well productivity and enhanced hydrocarbon recovery.

Reservoirs developed with horizontal wells face various challenges, such as early water and gas breakthrough, leading to reduced oil recovery.

This is often the result of a variation in the reservoir properties, including the fluid and petrophysical properties, layer pressure and fluid contacts.

Several studies assert that such challenges can be mitigated by deploying advanced well completions

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to manage the reservoir fluid influx along the wellbore and therefore optimise the performance of wells.1 – 6 In addition, research suggests the application of autonomous inflow control devices (AICDs) to control water or gas production acts as a type of insurance policy against geological and dynamic reservoir uncertainties to reduce the risk and variation in the expected oil production profiles.7 In 2018, Tendeka successfully performed an infill development campaign for PETRONAS-Malaysia to improve production with the first delivery of its FloSure AICD completion in a complex offshore oil reservoir in Sarawak, northwest of Borneo.8 The field itself had been producing for more than 45 years (Figure 1).

Fuziana Tusimin, Latief Riyanto and Norbaizurah Ahmad Tajuddin, PETRONAS, and Mojtaba Moradi, Raam Marimuthu and Michael Konopczynski, Tendeka, reveal how the well performance of a complex oil reservoir offshore Sarawak was optimised by autonomous inflow control device technology.

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The workflow The chosen horizontal well, Well-A, was drilled in a very thin formation, with the oil rim averaging a thickness of 13 ft (the thinnest AICD application to date). The well intersects two geological layers with different properties. A large gas cap and an aquifer are located above and below the well. In addition, oil production from this well was expected to be reduced significantly due to a high probability of early water and gas breakthrough, potentially within days or weeks.

It was therefore critical to optimise the stand-off distance from gas-oil contact (GOC) and oil-water contact (OWC) to ensure sustainable long-term production from Well-A and to identify suitable technology to minimise the anticipated threat.

The workflow comprised: Pre-drilling studies, including AICD flow loop testing.

Well candidate selection.

Flow performance evaluation (static/dynamic modelling).

Post-drilling analyses involving real-time completion design, history matching and comparison of production data with neighbouring wells.

Ì Ì Ì Ì

Figure 1. Structure map with well penetrations in reservoir X and cross-section of reservoir X.

Based on the off-set wells, structural uncertainty was anticipated to be 25 ft true vertical depth subsea (TVDSS), which is greater than the oil column thickness. This made building the deviation angle while drilling and landing the horizontal well in the thin oil column challenging.

The maximum dogleg severity (DLS) of the openhole horizontal section had to be limited to 3˚/100 ft or less to reduce running forces and bending stresses during lower completion installation, especially for the screen and swell packer installation. This was confirmed through torque and drag analysis.

Completion equipment, including the AICD and screens, had only been purchased for a 1400 ft horizontal length.

Due to the unique nature of the devices, using additional material from other projects to make up a longer horizontal section was not an option. The final horizontal length was therefore limited by the material readiness.

A significant difference between the prognosed and actual permeability in one of the subunits was observed, despite good well control at the Well-A location. This impacted the planned completion strategy for the subunit.

Fast, real-time decisions, based on the actual data, were needed to optimise the completion design.

Balancing the influx of reservoir fluids

Figure 2. Construction of FloSure AICD.

Figure 3. AICD performance prediction for single phase oil at 0.4 cP, water and gas.

46 | Oilfield Technology Issue 2 2021

Like an ICD, the AICD (Figure 2) is designed to balance the influx of reservoir fluids, thus delaying the production of unwanted effluents prior to their breakthrough (proactive solution). However, once breakthrough occurs, the device restricts the production of unwanted effluents with lower viscosity, such as gas in light oil applications and both gas and water in viscous oil production (reactive solution).

Fluid enters the device through an orifice in the top plate. This impacts the levitating disk and disperses fluid radially between the disk and the top plate, before turning around the periphery of the disk to exit the device through an array of ports at the bottom of the device.

The pressure drop experienced by fluid flowing through the AICD is a function of the volumetric flow rate and the viscosity and density of the fluid. The degree of flow restriction is a result of the position of the levitating disk, while the disk position is determined by the balance of three principal forces: a change in momentum force; a force created by the frictional pressure drop of the fluid flowing through the device; and a ‘lifting’ force created by a reduction in pressure of the fluid moving at high velocity in the gap between the disk and the top plate, as described by Bernoulli’s equation of constant energy.

Field B employs 7.5 mm AICD valves to match device performance to the well flow rate requirements. In field B, the oil viscosity is 0.67 cP, water is 0.37 cP and gas is 0.02 cP. When gas or water flows through the AICD valve at the same drawdown the velocity of the water and gas will increase, and hence reduce the dynamic pressure and levitate the disk towards the inlet to choke the flow.

The AICD valve is assembled as part of the sand screen joint.

The size of the device is interchangeable at the rig site if the calibration modelling using the actual log data acquired after drilling suggests something different than expected. Dynamic reservoir simulations are required to quantify the production benefits of the AICD completion over field life.

Figure 3 shows the single phase AICD performance curve at reservoir X conditions.

Several production scenarios depicting the unwanted fluids breakthrough were simulated to quantify the performance of the well with the AICD completion in later life and, in turn, design an optimised AICD completion.

Well completion design process Based on a petrophysical study, a thick shale section was expected from 6907 – 7187 ft. The X3.2 reservoir is estimated to have a 5 ft stand-off from the OWC at the heel location of the well and is prone to early water breakthrough. Meanwhile, the top of the X3.1 reservoir is closer to the GOC, with high gas saturation over 60% observed from 7187 – 7667 ft depth. This section of the wellbore is also susceptible to early gas breakthrough.

Blanking off this high gas zone would be the ideal solution to mitigate early production of gas. The mid and toe section of the X3.1 reservoir contain good saturation of oil, which necessitates more AICD joints to be placed in these sections for improved well production.

Figure 4 shows the near wellbore reservoir properties obtained from logs after reaching target depth (TD). The reservoir permeability averaged 1000 mD, with a high permeability zone observed at 7852 – 8032 ft.

The observed reduction in oil rim thickness at Well-A necessitated re-evaluation of the remaining recoverable reserves and well placement strategy.

First, an analytical study identified the need for a new drainage point in the south-east area of reservoir X. Secondly, a fit-for-purpose dynamic model was constructed to meet the following objectives: Understand the impact of a thinner than expected oil rim on recoverable reserves.

Optimised stand-off distance from GOC and OWC in Well-A. Design of the AICD well completion.

horizontal depth placement is 1/3 stand-off distance from the GOC and 2/3 from OWC, in order to sustain well life and recover the new estimated reserves.

Multiple simulation runs were completed to test the sensitivity of production rates and recovery efficiency to the number of AICDs and packer placement for the horizontal section segmentation. Oil, gas and water production rates were compared at two time-steps: initial and at end of well life. This found that the gas/oil ratio (GOR)

Figure 4. Near wellbore reservoir properties from logs.

Figure 5. Initial AICD placement along the horizontal section of Well-A.

Ì Ì Ì

A segmented well model was created in the reservoir dynamic simulation model to represent the proposed AICD placement. The investigation used multiple parameter sensitivities to evaluate the impact on oil production from thinning of the oil leg column, and the timing and extent of early water and gas breakthrough. Based on the analysis, the optimised

Figure 6. Pre-drill and post-drill over completion diagram of Well-A.

Issue 2 2021 Oilfield Technology | 47

Figure 7. Well-A and Well-B performance comparison.

can be reduced by 46% compared to a standalone screen completion after gas breaks through. Oil production can be increased by up to 50% with constant downhole rate control via two AICDs mounted on each joint of 5 1/2 in. 150-Micron premium sand screen.

In addition, a segmentation analysis recommended the creation of seven producing compartments with seven swell packers to achieve better inflow control. For the upper completion, the tubing size is 3 1/2 in. and is equipped with a gas lift mandrel to kick-off the well for production. The initial design for Well-A is shown in Figure 5.

The application of real-time reservoir mapping-while-drilling enabled the evaluation of the oil column thickness in both the X3.1 and X3.2 reservoir subunits. The oil rim in X3.2 was shallower than prognosed and was interpreted to be 17 ft thick, while the oil rim in X3.1 was deeper than what was seen in Well-B and was interpreted to have a thicker oil column of 25 ft.

Well-A was drilled until the final target depth (FTD) with a total horizontal length of 2000 ft. Additional 5 1/2 in. blank liner joints were secured, which enabled the completion of the additional horizontal length. Using the post drilling results, a real-time inflow control simulation was rerun to confirm the final placement of AICDs prior to the completion operation.

For the analysis, several scenarios were simulated by manipulating the late-time fluid saturation to mimic breakthrough scenarios and observe AICD performance along the horizontal section. The inflow control simulation considered the possibility of early water breakthrough from X3.2 as a result of the 5 ft stand-off from OWC at the heel, as well as early gas breakthrough at the top of X3.1 and the significant permeability difference along the horizontal penetration within the X3.1 subunit. The strategy was to limit AICD joints in the X3.2 subunit to restrict the water inflow, to blank-off the high gas saturation zones in X3.1 and to limit AICD joints at the high permeability intervals.

To evaluate the AICD performance at late life, several completion designs were considered to examine the functionally of the AICD completion design and quantify the impact on well productivity.

As a result, the final completion design was better compared to the pre-drill plan. A total of seven swell packers and 18 AICD joints were installed. Figure 6 shows the completion diagram between pre-drill and post-drill of Well-A.

Results Well-A was successfully drilled within the thin oil rim, optimally placed and completed with an advanced AICD completion that was designed using a strategy based on the integration of fit-for-purpose and innovative approaches, incorporating the appropriate application of FloSure AICDs. The drill-in and completion fluids

48 | Oilfield Technology Issue 2 2021

were unloaded from Well-A to establish communication between the wellbore and reservoir. It was able to flow at an instantaneous rate of 3140 bpd of liquid with 8% water cut. Gas production was also monitored to measure AICD effectiveness; initial readings were low and comparable to the solution GOR. Subsequently, the dynamic model was updated with observed contacts, well trajectory and final completion. Several withdrawal scenarios for different liquid production rates were performed. Greater withdrawal rates result in increased pressure drawdown and consequently earlier water coning. Log-log plots of the simulated water-oil ratio (WOR) and the time derivative of WOR illustrate how a higher withdrawal rate exacerbates water coning. Therefore, controlling Well-A drawdown is one way to mitigate coning and thereby sustain oil production for a longer period.

Figure 7 shows the performance comparison of Well-A, completed with FloSure AICDs, and Well-B, completed with another completion technology. Although Well-B showed significant GOR reduction (from 25 000 ft3/stock tank barrel to less than 1000 ft3/stock tank barrel) at initial testing of production life, it was later shut-in due to excessive gas production. However, Well-A is still producing at a high oil rate while maintaining a stable GOR of 2000 ft3/stock tank barrel.

Tendeka’s FloSure AICD completion ensures balanced contribution from all reservoir sections and limits gas and water production. This enables the operator to implement an optimum reservoir drainage strategy that capitalises on the ability of the AICD downhole flow control to react autonomously based on dynamic well conditions – restricting the flow of unwanted effluents – without the need for control lines and surface control systems.

The technology has delivered a 200% increase in oil production while reducing the GOR by up to 90% and water cut up to 50%, compared to several offset wells with various other completions.

References 1.

2.

3.

4.

5.

6.

7.

8.

AHMAD, F., AL-NEAIMI, A.K., SAIF, O.Y., CHANNA, Z., IWAMA, H., SARSEKOV, A., EL-SAYED, H.S., KONOPCZYNSKI, M., ISMAIL, I.M., and ABAZEED, O., ‘Rejuvenating a High GOR, Light Oil Reservoir Using AICD Completion Technology for Gas Control’. Society of Petroleum Engineers.

SPE-183486-MS (November 2016).

DOWLATABAD, M.M., ‘Novel Integrated Approach Simultaneously Optimising AFI Locations Plus Number and (A)ICD Sizes’. Society of Petroleum Engineers.

SPE-174309-MS (June 2015).

HALVORSEN, M., MADSEN, M., VIKØREN MO, M., ISMA MOHD, I., and GREEN, A., ‘Enhanced Oil Recovery on Troll Field by Implementing Autonomous Inflow Control Device’. Society of Petroleum Engineers. SPE-180037-MS (April 2016).

MORADI, M., KONOPCZYNSKI, M., MOHD ISMAIL, I., and OGUCHE, I., ‘Production Optimisation of Heavy Oil Wells Using Autonomous Inflow Control Devices’.

Society of Petroleum Engineers. SPE-193718-MS (December 2018).

MOHD ISMAIL, I., CHE SIDIK, N.A., SYARANI WAHI, F., TAN, G.L., TOM, F., and HILLIS, F., ‘Increased Oil Production in Super Thin Oil Rim Using the Application of Autonomous Inflow Control Devices’. Society of Petroleum Engineers.

SPE-191590-MS (September 2018).

DOWLATABAD, M.M., MURADOV, K.M., and DAVIES, D., ‘Novel Workflow to Optimise Annular Flow Isolation in Advanced Wells’. IPTC-17716-MS (December 2014).

DOWLATABAD, M.M., ZAREI, F., and AKBARI, M., ‘The Improvement of Production Profile While Managing Reservoir Uncertainties with Inflow Control Devices Completions’. Society of Petroleum Engineers. SPE-173841-MS (April 2015).

AHMAD TAJUDDIN, N.B., DAN, H.X., TUSIMIN, F., KAWAR, S., RIZA FEISAL, S.M., WAHID ALI, N.A., SHAH, J.M., RIYANTO, L., HUSSAIN, M., A’AKIF FADZIL, N.A., and SAKDILAH, M.Z., ‘Successful Monetisation of an Extremely Thin Oil Rim and Slanted Contact Reservoir, Offshore Malaysia, through Emerging Technologies and Innovative Concepts’. SPE-196513-MS (October 2020).

Geoffrey Thyne, Vladimir Ulyanov, Brandon Skinner and Salem Thyne, ESal, USA, describe how simple technology could double the recoverable reserves in many fields while reducing operating costs.

UNLOCKING STRANDED RESERVES T

he oil and gas industry faces unprecedented pressure from demand changes, bans on drilling on federal lands in the US under a new White House administration and rising costs for drilling and production.

New technologies in all phases of exploration, drilling and production have led to incremental production increases – but the average field still strands 65% of reserves after all available production techniques have been exhausted.

New discoveries regarding the connection between the chemistry of wettability and enhanced oil recovery (EOR)

show promise for unlocking another 35% of reserves in approximately half of the world’s oilfields. As further data adds to understanding of the issue, there is hope that using salinity to improve wettability could boost production in up to 75% of fields.

Background ESal founder Geoffrey Thyne began this study of salinity and wettability almost by accident when assigned to prove the opposite of what was ultimately proven to be the case.

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The task, assigned by a non-profit organisation dedicated to researching improvements in EOR, was to prove that using low salinity water (this from a coalbed methane project in the US state of Wyoming) would improve EOR rates. However, extensive laboratory and field testing showed that the low salinity water did not affect oil production at all.

In the process Thyne realised however that there were indeed some cases where saline water did boost production. He left the employ of the organisation and set out to use his training in chemistry and geology to determine the deciding factor.

The standard thinking was that a field should be water-wet to achieve maximum production, but there were indications as far back as 1959 that the best production came when oil and water move equally well, in what is known as neutral wettability: equally water-wet and oil-wet. This condition strikes the balance between adhesion (oil-wet) and water block (water-wet). This work was further validated by empirical data collected by Thyne over a period of several years.

Salinity and wettability had been studied for decades, but always from the engineer’s view of how liquids flow. This was understandable because the only known testing at that time involved contact angles, each study of which could require weeks – making in-depth study of the chemistry impractical.

To address this limitation and further evaluate this theory an associate of Thyne’s developed a direct testing method, combining samples of oil and rock in a field with water in a test tube, with varying degrees of salinity in each test. Small amounts of naphthenic acid were added. The test tube was then shaken and the contents allowed to settle out.

This test – repeated hundreds of times with similar results – yielded a major surprise. This flotation test could accurately measure wettability quickly and efficiently across a wide spectrum of reservoir conditions.

Oil-wet rocks would partition above water-wet rocks in the test tube and, through extensive modelling, would represent the accurate wettability state of the reservoir (Figure 1).

The key takeaway was that wettability is fundamentally a chemical reaction, not a property inherent to the reservoir.

Thyne realised that this method would allow ESal to quickly test for optimal wettability in multiple fields by putting rock and oil samples from a field into a test tube, and then over a series of tests manipulate the salinity of the water added to those samples to determine the best water for overall recovery.

the oil, rock, water and temperature (also a factor) naturally aligned.

Research found this condition in the massive East Texas oilfield, covering 140 000 acres across five counties.

The field is now approaching 80% recovery by simply reinjecting its own untreated produced water. That 80% figure is a much higher rate than the world average of 35%. This field is first in the US in terms of total volume of oil recovered since its discovery in 1930.

The true test, however, would come with changing the salinity in an existing field, then monitoring the results. Expectations were that optimal wettability would increase production by 35% in a field where that is a factor at all.

But the opposite is also true – changing the salinity improperly would lead to production loss and possibly damage the formation.

Case study 1: the wrong wettability decreases production In this case study, the field’s production had peaked at approximately 300 000 bbl/month, with a decline curve of 5.9%. The reservoir’s wettability was at 0.35 water-wet (Amott-Harvey). At the time the water sources were switched it was producing approximately 170 000 bbl/month.

The new water shifted the reservoir wettability to much more water-wet conditions, at 0.9. Optimal wettability/production for this field is seen between 0.3 oil-wet and 0.3 water-wet.

As the new water spread throughout the reservoir, the decline rate almost doubled to 11.45%. These numbers were derived by observing individual well decline under close-to-optimal conditions prior to switching to the wrong water and the onset of reservoir damage (Figure 2).

The production changes were dramatic. As a result of the switch, the company has: Missed 5 million bbl of production.

Lost US$212 million in pre-tax profit.

Trapped a total of 16 million bbl.

Potentially lost US$363 million in pre-tax profit over the life of the field.

Reduced field life by 23.5 years.

Increased water handling, injection and disposal costs.

Lost US$130 million in field value.

Ì Ì Ì Ì Ì Ì Ì

Many of these detrimental consequences can be reversed through optimal wettability alteration in the future by using the correct water.

Occurring naturally One way to evaluate Thyne’s prior discovery would be to find where neutral wettability was already enhancing production in a field in which

Case study 2: success with the right wettability

The second field is operated by the same company. Here, at the same time as the water switch in the previous field, they allowed ESal to evaluate the field and to adjust the water for improved production.

The fields are geographically nearby, but differences in water, rock and oil combinations brought different results in production. ESal tested field samples and accurately predicted the oil recovery improvements to be realised from appropriate water formulations.

This field (Figure 3) peaked at approximately 230 000 bbl/month with a decline rate of 15.91%.

Its original wettability was 0.6 water-wet.

To test the benefits of updated wettability, a screening algorithm is used that evaluates a field based on temperature, depth, minerology, oil API and other factors. Samples come from rock, water oil core or cuttings. In this case the test took four weeks to arrive at formulations that predicted improved production.

Figure 1. ESal’s flotation test measures the effect of salinity on wettability in a reservoir.

50 | Oilfield Technology Issue 2 2021

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Changing the water to those formulations brought the wettability to 0.4 water-wet, approaching the optimal range. As the injection of the proper water mix continues, future wettability is expected to reach the 0.3 water-wet optimal range.

Within the first five months of the change in water injection the decline rate dropped from 15.91% to 10.22%.

Under these conditions the company has to date: Unlocked an additional 1.9 million bbl.

Potentially unlocked an additional 4.9 million bbl over the life of the field.

Gained an additional US$63 million in pre-tax profit.

Boosted future expected pre-tax profit by US$92 million.

Ì Ì Ì Ì

Ì Ì Ì

Lengthened field life by 12.5 years.

Increased field value by US$50 million.

Stabilised what had been a growing water cut.

The cost for this procedure is approximately US$4.00 per incremental barrel produced.

Limitations As stated, approximately 50% of fields tested show that there would be no production benefit to changing the water source. Pre-testing allows ESal to concentrate only on fields that would benefit from changes in salinity and wettability. The company is extensively testing samples from a wide variety of fields in order to expand their understanding of why some fields do not respond to these changes.

The hope is that they can increase the number of fields that do benefit to around 75%.

The future

Figure 2. Changing water source results in reservoir wettability damage, reducing estimated ultimate recovery (EUR) and field life.

In addition to salinity, wettability can be optimised through surfactants or other chemical treatments. The company works with both chemical companies and water treatment companies to generate optimal wettability conditions in a reservoir.

Wettability testing during the completions phase can inform the salinity of water needed for hydraulic fracturing, which can optimise production from wells too young for EOR. A production increase of even 15% in existing wells on a large scale could add 400 million bbl of oil to recoverable US reserves.

Across the world, boosting production to 70% instead of today’s standard 35% could add more than a trillion barrels to reserves across the world.

Many fields across the world have never undergone EOR of any sort. Determining which areas could benefit from EOR and applying wettability principles there could boost production even more.

Conclusion

Figure 3. Changing water source results in improving reservoir wettability while increasing EUR and

field life.

52 | Oilfield Technology Issue 2 2021

The cost of this treatment, at approximately US$4.00 per additional barrel of production, is much less than the cost of drilling and completing new wells.

With economic and environmental concerns mounting across the globe producers are seeking ways to improve costs and efficiencies, as well as boost their environmental, social and governance (ESG) footprint. Making minor changes in produced water for use in EOR procedures that could double current production would seem to be a simple decision.

As the oil and gas industry adapts to rapid changes more companies are emerging from their hesitancy in adopting new technology.

Whereas the old mantra was, ‘Someone else must try this before we will’, there is little time for that kind of waiting now in the face of research and field data showing how to boost production.

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SWITCHING ON TO

ELECTRIC CONTROL VALVES’ POTENTIAL M

any wellheads are located in very remote sites, many of which lack both compressed air and power, so controls have historically been limited to simple pneumatic systems utilising pressurised natural gas as a motive force.

While the controls do function their capabilities are quite limited and the natural gas-operated transmitters, positioners, controllers and control valves continually vent methane to the atmosphere. The pneumatic instruments offer virtually no means for remote monitoring or control and are also prone to maintenance problems that can rapidly escalate, depending on the quality of the gas.

These and other issues can be addressed by applying recent advances in control valve technology.

54 |

Scott Losing and Andrew Prusha, Emerson, Emer USA, explain how electric control valve drives are helping operators address methane emission regulations and adjust gas flow to maximise production.

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Methane emission regulations

Figure 1. Recently introduced by the US Environmental Protection Agency (EPA), CFR 40 Part 60 Subpart OOOO seeks to dramatically reduce methane emissions.1

Recent government actions are driving major changes in wellhead instrumentation. In an effort to curb methane emissions, the US, Canada and many European countries have passed regulations that significantly impact field instrumentation activated by natural gas (Figure 1).

These standards force wellhead operators to either replace natural gas-driven pneumatic devices with electric/electronic alternatives, install air compressors to replace the natural gas supply lines or to replace each pneumatic device with a low bleed alternative that satisfies the stringent methane emission limits. In either case significant CAPEX may be required. Fortunately, the introduction of limited electrical power at many well sites is creating an opportunity to reduce these costs.

Solar systems, batteries and small natural gas generators are becoming increasingly available – and the electrical efficiency of instrumentation is improving.

When natural gas-powered pneumatic instruments are replaced with electric alternatives, methane bleed emissions are cut to zero. Additionally, the new electrical instrumentation provides diagnostics while enabling advanced controls and remote monitoring.

Electric valve drives A third aspect creating change is the introduction of powerful, low-cost electric drives that can be easily retrofitted to many existing control and on/off valves.

These drives only require low voltage (12 V and/or 24 V) and low current, while providing fast and reliable control along with diagnostics. This gives users the ability to satisfy the new methane-reducing environmental regulations while providing remote control and monitoring of their well sites. More importantly, the new drives and instrumentation enable profitable, advanced control strategies that were not easily implemented before these upgrades.

Oil separator level controls Figure 2. An oil separator uses gravity to separate incoming well fluids into gas, oil

and water.

Figure 3. Gas lift uses natural gas injected at the base of the well to help push fluids to the surface. Electronic controls and valves enable more advanced control schemes to maximise production while minimising wasted energy and natural gas usage.

56 | Oilfield Technology Issue 2 2021

One advanced control option is improved level control for oil separators, a simple piece of equipment used to split well fluids into gas, oil and water. As shown in Figure 2, a liquid/vapour mixture enters the left side of the vessel and the liquids quickly disengage and fall out to the bottom of the vessel. The gas vapours continue across the top of the vessel and exit via overhead piping to downstream gas processing.

The water and oil collect in the compartment to the left of the weir, where the oil floats on top of the water. A transmitter detects the oil/water interface and the water valve is modulated to keep the interface about halfway up the weir.

Excess oil overflows the weir and collects in the lower right compartment. The oil level on that side is detected by a second transmitter and the oil level is controlled by modulating the oil feed valve. The oil level is kept high enough to block gas vapours from escaping through the oil line.

While tight control is possible utilising two transmitters, two control valves and two controllers,

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many operators reduce the installation cost by eliminating the controllers and tying the level transmitter signals directly to the valves. The resulting on/off, coarse control dumps oil and/or water as needed, but the gas and oil flow pulses are difficult to measure, creating understated oil flow and lost profits.

Electronic control valves offer an improved control strategy. The valves can be programmed to open and close at varying levels and to operate continuously in between levels. This method results in tighter level control and more consistent oil flows, using the same basic control equipment.

Electronic control valves were recently employed on a number of oil separators in North Dakota, US. The control improvements reduced gas loss down the oil line by 80% and improved oil flow measurement accuracy by 5%, effectively increasing well production.

Enhanced recovery methods

Figure 4. Plunger lift uses a plunger and trapped wellhead pressure to push liquids to the

surface.

As a well ages, the pressure falls and enhanced recovery methods may be employed to help raise the liquids and natural gas to the surface. Methods include gas lift, plunger lift and rod pumps.

Gas lift injects pressurised natural gas down the well annular space to reduce the well fluid density and help push the liquids up the well.

Plunger lift is usually used in gas wells that have liquids building up inside and blocking gas flow. It utilises a plunger that falls to the base of the well, with downhole pressure pushing the plunger back up the well string, driving the liquids to the surface and clearing the path for gas to flow.

Rod pumps use a downhole rod-driven pump to push liquids up the well.

All of these methods can be much more efficient if advanced control strategies that utilise electronic control valves are employed.

Gas lift (Figure 3) can increase production, but the improved yield comes at the cost of compressing and injecting natural gas. Injecting too little gas will reduce production, while injecting too much gas will waste energy and could also reduce oil production.

If pneumatic controls are used, the gas flow is usually adjusted on initial system set-up and left at a static setting. However, electronic controls and control valves have the ability to automatically adjust the flow to maximise production as conditions change.

Plunger lift control schemes

Figure 5. A rod lift well can experience reduced liquid production due to ‘flumping’, when high gas flow from the well creates vapour lock conditions on the pump. Electronic controls and control valves can maintain accurate backpressure on the well to maximise oil and gas flow.

58 | Oilfield Technology Issue 2 2021

Plunger lift is used on ageing gas wells where falling well pressure is unable to push entrained liquids to the surface. Liquids can pool at the bottom and eventually stop all gas flow. There are several methods of plunger lift, but all employ some type of plunger to help push the liquids up the well (Figure 4).

The well outlet is blocked at the surface and the plunger is released at the top, and it then falls down the well tubing until it reaches the base of the well.

In the meantime, the blocked well slowly builds pressure.

When the pressure is high enough, the control valve at the surface is opened and the resulting surge of gas flow pushes the plunger to the surface.

As the plunger rises it pushes liquids ahead of it. When the plunger reaches the surface it is trapped and held while the gas continues to flow. Eventually the gas pressure will fall and liquids will begin to build at the base of the well, choking gas flow. At this point the well outlet is blocked, the plunger released and the plunger falls to the base of the well to start the cycle again.

Control of a plunger lift well requires logic to detect falling pressure and gas flow and to control the plunger cycle. There is also some advantage to controlling how quickly the well pressure is released in order to ensure reliable plunger operation while accurately measuring the surging gas flow. If the well outlet valve is not throttled, the gas flow often overwhelms the gas flow meter and production is understated.

Electronic transmitters and control valves enable plunger lift operations and are able to control and measure the resulting gas surge flow. This improved gas flow measurement saves approximately US$85 000 a year on an average well.

Rod lift flumping controls Rod lift is an enhanced recovery method that uses a downhole pump to push liquids to the surface (Figure 5). The method works well but fails when the gas pressure in the well is great enough to flow up the annulus, but not enough to push the liquids.

This combination condition of gas flow and pumping is called ‘flumping’, and the gas flow can be enough to vapour lock the pump, reducing pump efficiency and liquid production.

Electronic controls and valves can be used to maintain enough backpressure on the well to maximise gas flow while maintaining liquid production. The elimination of flumping can generate approximately US$2000/d in increased production on a 250 bpd well.

Conclusion Recent methane emission regulations are forcing oilfield operators to replace and/or upgrade natural gas-powered instrumentation and control valves, even as electrical power sources are becoming increasingly available at well sites.

Since natural gas-powered pneumatic control components must be replaced regardless, many users are taking advantage of the capability and reliability of low power electronic control valves. Methane emissions are reduced to zero, and the new electronic instrumentation and electric control valves improve profitability through advanced control strategies, extensive diagnostics and remote monitoring.

When considering a wellhead instrument upgrade, take the time to investigate the latest technology. Implementing electronic transmitters and electric control valves can significantly increase production and improve the bottom line.

Reference 1.

Figure 1 courtesy of “Environment and Climate Change Canada Proposed Methane Regulations Webinar” (2 June 2017).

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