Oilfield Technology - March 2022

MAGAZINE | SPRING 2022

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Contents

Spring 2022

Volume 15 Number 01

30 Over the hurdle

03 Comment 05 World news 10 The great disconnect Mfon Usoro, Jean Charles Combe, Pablo Prudencio and Mark Oberstoetter, Wood Mackenzie, USA, consider why US oil production growth and investment is disconnected from surging oil prices.

Jonathan Rogers, Martin Shumway and Dr Amir Mahmoudkhani, Locus Bio-Energy Solutions, USA, review the progress that naturally sourced biosurfactants have made in maximising oil recovery in shale wells – for greater profits and a smaller carbon footprint.

14 The sands of brine Brandon S. Mitchell, TETRA Technologies, USA, says the decisive advance in sand removal technologies in recent years is cause for celebration.

18 Pulling the plug on fracturing challenges Jenny Darnell and Mohammed Munawar, NOV, USA, detail a new dissolvable frac plug designed to solve modern downhole challenges.

Over the hurdle

22 Addressing offshore challenges through digitalisation of operations

Jonathan Rogers, Martin Shumway and Dr Amir Mahmoudkhani, Locus Bio-Energy Solutions, USA, review the progress that naturally sourced biosurfactants have made in maximising oil recovery in shale wells – for greater profits and a smaller carbon footprint.

Andreas Fliss, Elisabeth Norheim and Fernando Zapata-Bermudez, Archer, Norway, discuss how the COVID-19 pandemic and CO2 emissions have created offshore challenges that are being overcome by technology.

G

lobal demand for energy is expected to keep growing – and oil and gas will remain a vital part of the energy mix for decades to come. Even the most conservative clean energy transition scenarios predict that US oil and gas liquids production will need to increase from the 12.24 million bpd average produced in 2019 to 13.3 million bpd by 2030.1,2 Production from shale wells typically declines by 50%+ in the first year. As a result, meeting increased

26 Making strides against well integrity challenges

demand requires E&P companies to increase production in cost-effective and sustainable ways to both compensate for these steep decline rates and produce additional crude to meet requirements. Adding to the challenge, producers must address evolving ESG requirements and transition to net zero energy production, even as falling operating costs make it cheaper to produce new barrels of oil. According to Rystad Energy, the average breakeven price for tight oil

was US$37/bbl at the end of 2021, down from US$47/bbl just 3 years prior.3 To boost declining production rates and meet growing domestic energy demand, US operators have traditionally employed conventional enhanced oil recovery (EOR) techniques, such as water flooding, chemical flooding, thermal techniques and gas injection. EOR has a proven history of maximising oil recovery in conventional oil

wells, which are drilled into sandstone and carbonate reservoirs with pore sizes ranging from 1 to 100 μm on average. But these same techniques are not as effective or economically viable in many shale reservoirs with pore throat radii in the range of 1 to 200 nanometres (nm). For size comparison 1 μm equals 1000 nm, with human DNA measuring just 2 nm in diameter. 1 nm is equal to 1 millionth of a millimetre.

30 30 |

Ørjan Frøyland, Expro, considers how annular intervention can offer a solution to well integrity challenges.

| 31

36 Inverting the status quo Matthew Offenbacher and Richard Toomes, AES Drilling Fluids, USA, explain why industry scepticism meant a different approach was required when developing an invert emulsion lubricant.

40 New heights below sea level Alexandre de Rougemont, MAN Energy Solutions, Switzerland, shows how new subsea compression systems are facilitating more sustainable and efficient production from deepwater gas fields.

Front cover Parker Wellbore’s Integrated Tubular Running Services (iTRS) bring our casing and tubular running technology, both hardware and software integration, into the drilling operation to build the highest integrity well.

By integrating personnel to run TRS, whether on Parker Wellbore rigs or rigs under our O&M programme, Parker’s iTRS results in a reduction of 3rd party services, fewer POB in support of carbon reduction along with gains in efficiency and shorter casing running times on your well.

MAGAZINE | SPRING 2022

44 Smart and speedy Peter Chronis, Winters Instruments, Canada, examines the network options available to operators requiring smart instrument measurement for better pressure and temperature monitoring.

Oilfield Technology Cover_v2.indd 1 OFC_OT_Issue4_2021.indd 56

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Copyright Palladian Publications Ltd 2022. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner.

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

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Comment Nicholas Woodroof, Editor

nicholas.woodroof@palladianpublications.com

R

ussia’s invasion of Ukraine has shattered many cast-iron assumptions: overturning decades of pacifism and underspending on defence, Germany now helps arm Ukraine’s military; Switzerland, neutral for centuries, has joined the European Union, the UK and the US in sanctioning Russia; and the US, looking for replacements to embargoed Russian oil and gas and an end to rocketing oil prices, is entreating long-time enemies Iran and Venezuela – which has blamed the US and NATO for the conflict in Ukraine – to increase production.

Amidst all of this, the US shale industry finds itself at a difficult juncture. On the one hand, President Joe Biden has urged US oil producers to also increase output to help make up for the millions of barrels of Russian oil that will be off the market. This has raised eyebrows – many in the industry see the Biden administration as hostile towards it, citing the cancellation of the Keystone XL pipeline last year. However, the anticipated shortfall in global oil production, as a result of the embargoes on Russia, is such that if US oil companies want any hope of supply tightness easing then they will have to comply with Biden’s appeal, and hope that Venezuela, Saudi Arabia and Iran follow suit, however unpalatable that may be.

On the other hand, as outlined by Wood Mackenzie in these pages, the US shale industry is not ready for a rapid scale-up of production. Spooked by the boom-and-bust years, companies are now far more averse to expanding operations. Instead, reducing debt and delivering consistent shareholder dividends are key priorities. On top of this culture shift, supply chain issues also make a rapid, significant production increase in the shale plays tricky. As Occidental Petroleum chief executive Vicki Hollub said in an interview with The Economist earlier this month, supplies of tubulars, frac sand and lorry drivers are low. Hollub said: “…our industry today cannot replace those [Russian] barrels anytime in the near-term…we’re 10 to 12 months out from being able to significantly increase over what we already had planned to do.”1 Complicating an already fraught picture is the considerable uncertainty over the ability and willingness of OPEC to make up for the global shortfall; high oil prices look likely for the foreseeable future.

Despite the sense of pervading gloom, in the words of Brandon S. Mitchell from TETRA Technologies ‘amid today’s disruption and chaos, it is reassuring to pause for a moment to consider how much has been achieved in just the past 5 years’ by the upstream industry. Turn to pg. 14 for a piece by Brandon highlighting the recent advances in sand removal technologies. Elsewhere in the issue readers can enjoy articles on dissolvable frac plug technology, digitalisation of offshore operations, annular intervention, oilfield chemicals, subsea compression systems and smart instrument measurement.

It is also heartening to see the return of face-to-face events. My colleague Ben Macleod will be attending OTC 2022 in Houston in May – if you’re attending, be sure to say hello and find out how Oilfield Technology can help with your marketing plans this year.

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Reference 1.

TRICKS, H., ‘Money Talks: Houston, we have a problem’, 9 March 2022. Available at: https://play. acast.com/s/theeconomistmoneytalks/moneytalks-houston-wehaveaproblem

Spring 2022 Oilfield Technology | 3

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World news

Spring 2022

McDermott completes work on gas field for ONGC McDermott has delivered a gas field, known as the U-Field, for ONGC’s KG-DWN 98/2 Block project.

ONGC’s KG-DWN 98/2 Block project, located in the Bay of Bengal off the east coast of India, is the largest and one of the most complex subsea projects in Asia Pacific, involving major subsea infrastructure installation in ultra-deepwater. McDermott is delivering two gas systems for ONGC’s gas fields: U-Field and R-Field. The project is being executed in a consortium, with Larsen & Toubro Hydrocarbon Engineering (L&T HE) manufacturing the structures in India. Upon completion, the gas field is expected to significantly increase domestic production, helping meet India’s increasing energy demands while lowering reliance on imports. The U-Field is now connected to ONGC’s Vashishtha subsea infrastructure.

McDermott’s vessels, including Derrick Barge 30, Derrick Lay Vessel 2000, the North Ocean 102 and Lay Vessel 105 (LV105) installed hundreds of miles of pipeline, 37 miles (60 km) of umbilicals and nearly miles (16 km) of flexible pipes. All the structures for the KG-DWN 98/2 Cluster II development are being manufactured at L&T HE’s Modular Fabrication Facility at Kattupalli (LTHE-MFFK) in Tamil Nadu.

The U-Field gas manifold, installed in water depth of 4593 ft (1400 m), and the associated subsea distribution unit are the first subsea production system structures manufactured in India.

LTHE-MFFK also delivered SURF structures and served as a spoolbase facility for stalk fabrication and reeling of rigid pipelines, which have been installed to facilitate gas flow from the U-Field wells to the onshore terminal at Odalarevu.

SBM Offshore divests minority interest in FPSO project

Waldorf Production acquires MOL’s North Sea assets

SBM Offshore has entered into a shareholder agreement with Mitsubishi Corp. (MC) and Nippon Yusen Kabushiki Kaisha (NYK), whereby MC and NYK have acquired a respective 25% and 20% ownership interest in the special purpose companies related to the lease and operation of the FPSO Alexandre de Gusmão.

SBM Offshore is operator and will remain the majority shareholder with 55% ownership interest.

FPSO Alexandre de Gusmão is currently under construction. The FPSO will be deployed at the Mero field in the Santos Basin offshore Brazil, 160 km offshore Rio de Janeiro, under a 22.5-year lease and operate contract with Petrobras. The Mero Unitized field is operated

by Petrobras (38.6%) in partnership with Shell Brasil (19.3%), TotalEnergies (19.3%), CNPC (9.65%), CNOOC Ltd. (9.65%), and Pré-sal Petróleo S.A. – PPSA (3.5%) as the Federal Union representative in non-contracted areas.

First oil is expected in 2025.

Waldorf Production has entered into a binding Sale and Purchase Agreement with a wholly-owned subsidiary of MOL Hungarian Oil and Gas Plc (MOL) for the acquisition of certain of MOL’s UK subsidiaries comprising their entire UK Continental Shelf (UKCS) business.

The key UKCS assets being acquired include non-operated interests of 20% in the Greater Catcher Area (GCA), 50% in the Scolty and Crathes fields as well as 21.83% in the Scott and 1.59% in the Telford licences.

The transaction has an economic effective date of 1 January 2021, with completion currently expected in 2H22. The subsidiaries and assets being acquired will continue to be held by the company after completion.

Waldorf has estimated that the acquisition will increase the company’s 2021 production by approximately 55% to approximately 34 000 boe/d and its end 2020 2P reserves by almost a third from 51.6 million boe to 67.5 million boe.

In brief Gabon VAALCO Energy has contracted DOF Subsea to perform subsea construction and installation services to support the subsea reconfiguration associated with the replacement of the existing FPSO vessel with a FSO vessel at the Etame field, offshore Gabon. DOF Subsea will provide personnel, crew and equipment to assist with reconfiguring the Etame field subsea infrastructure to flow field production to the FSO. Engineering and design work in relation to the field infrastructure upgrade has been completed, with subsea work planned to commence in July and be completed before the FSO is operational in September 2022.

Norway Baker Hughes is to acquire Altus Intervention, a provider of well intervention services and downhole oil and gas technology. The acquisition complements Baker Hughes’ existing portfolio of oilfield technologies and integrated solutions by enhancing the company’s life-of-well capabilities. Altus Intervention, headquartered in Norway and operating in 11 countries, specialises in fully integrated well intervention solutions, including proprietary technology. The transaction is expected to close in 2H22 and will be integrated into Baker Hughes’ Oilfield Services segment.

UK Petrofac has been awarded a 2-year operations and late life asset support contract extension with Spirit Energy.

The contract includes the provision of operations and maintenance support for Spirit Energy’s York platform in the Southern North Sea, and engineering, project and consultancy services for all of the operator’s North Sea assets.

Spring 2022 Oilfield Technology | 5

World news

Spring 2022

Diary dates 02 – 05 May 2022 Offshore Technology Conference 2022 Houston, USA 2022.otcnet.org

10 – 12 May 2022 Canada Gas & LNG Exhibition and Conference Vancouver, Canada canadagaslng.com

23 – 27 May 2022 28th World Gas Conference Daegu, South Korea wgc2022.org

05 – 08 September 2022 Gastech Exhibition & Conference Milan, Italy gastechevent.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 ÌÌWoodside Energy awards DOF Subsea offshore support services contract

ÌÌHalliburton, Schlumberger and Baker Hughes suspend Russia operations

ÌÌShell releases new plan for Jackdaw field development

ÌÌReach Subsea acquires OCTIO To read more about these articles and for more event listings go to:

www.oilfieldtechnology.com

6 | Oilfield Technology Spring 2022

CGG wins 4D OBN imaging contract offshore Brazil

Eni and Sonatrach make discovery in Algeria

CGG has been awarded a two-part ocean bottom node (OBN) seismic imaging project by PXGEO over the Sapinhoá Shared Reservoir in the Santos Basin offshore Brazil.

The resulting data will bring improved geological insight to the asset operator, Petrobras, to assist with better management of oil recovery and production development.

The baseline 3D seismic survey acquired by the PXGEO Poseidon OBN crew, covering 575 km2, is already being processed at CGG’s Rio de Janeiro subsurface imaging centre. Its geoscientists are applying CGG’s latest proprietary imaging technologies, including time-lag full-waveform inversion, internal multiple attenuation and least-squares migration, to resolve challenging structural uncertainties in the pre-salt and gain better insight into the reservoir’s geomechanical behaviour.

CGG will process the 4D monitor survey after its planned acquisition, again by PXGEO, in 2023.

Eni and Sonatrach have made an oil and associated gas discovery in the Zemlet el Arbi concession, located in the Berkine North Basin in the Algerian desert. The concession is operated by a joint venture between Eni (49%), and Sonatrach (51%). Preliminary estimates of the size of the discovery are around 140 million barrels of oil in place.

HDLE-1 discovered light oil in the Triassic sandstones of Tagi Formation, confirming 26 m of net pay. During the production test, the well delivered 7000 bpd and 5 million ft3/d of associated gas. The HDLE-1 well is the first well of an exploration campaign that will include the drilling of five wells in the Berkine North Basin. The discovery will be appraised with the drilling of a second well, HDLE-2, in April 2022.

Eni and Sonatrach will perform studies and analyses to accelerate the production phase of the new discovery through a fast-tracked development, with start-up foreseen in 3Q22.

Aker Solutions delivers Njord A platform to Equinor Following several years of extensive upgrades, Aker Solutions has said that the drilling and production platform Njord A is ready for handover to Equinor and towing the platform back to the field has started.

Njord A has been described as Norway’s largest renovation project. After the contract was signed on 17 March 2017, significant upgrades have been carried out on the hull and the platform deck to extend its lifetime for another 20 years of production.

The engineering was performed mainly by Aker Solutions’ offices in Bergen, Stavanger, Fornebu and Trondheim. The construction has been carried out at the company’s yards at Stord and Verdal. Close to 400 different supplier companies have been involved in the project, most of them Norwegian.

The Njord A contract was a groundbreaking undertaking in the Norwegian oil and gas industry when it was originally signed in 2017, being the first time a production platform on the Norwegian continental shelf was transported to shore for complete overhaul and upgrades. In 2018, an additional contract was awarded to Aker Solutions to prepare the platform for receiving oil and gas from the Fenja field, which entailed additional manufacturing and installation work on the platform. The company has also been tasked to assist Equinor in the offshore hook-up work preparing it for the start of production in 4Q22.

Njord A was originally delivered by Aker Solutions in September 1997. The platform deck was manufactured and assembled at the Stord yard, while the hull was constructed at the Verdal yard. Njord A was the first EPC contract on the Norwegian continental shelf following the implementation of the NORSOK standard in the mid-1990s.

In recent weeks, the platform has been in Klosterfjorden on the west coast of Norway, conducting various sea trials.

World news

Spring 2022

Oil discovery made near Dorado development offshore Western Australia

Production resumes from Rhum gas field

Santos has said the Pavo-1 exploration well has confirmed a significant oil discovery 46 km east of the Dorado field in the Bedout Sub-basin, offshore Western Australia. The well was drilled on the northern culmination of the greater Pavo structure and encountered a 60-m gross hydrocarbon column in the primary Caley member reservoir target. Wireline data has confirmed 46 m of net oil pay, with an oil-water contact intersected at 3004 m measured depth (MD). Excellent reservoir quality is interpreted from logs with 19% average porosity, permeabilities in the 100 to 1000 millidarcy range and hydrocarbon saturations averaging 80%, similar to that encountered in the Dorado field.

Wireline logging operations to collect pressure, sample and rock data across the target Caley reservoir to inform resource volume estimates have been completed. Initial indications from rig site analysis are of a light sweet oil (~52˚API) with a low gas-oil ratio. A 2C contingent resource for the northern culmination is assessed at 43 million bbl of oil gross. The result at Pavo-1 also significantly de-risks the hydrocarbon bearing potential of the separate southern culmination of the greater Pavo structure. The southern culmination has an additional best estimate P50 prospective resource of 40 million bbl gross.

The Pavo-1 well is being drilled using the jack-up mobile offshore drilling unit, Noble Tom Prosser, in a water depth of approximately 88 m and is currently drilling ahead to the final planned total depth of approximately 4200 m MD. Once wireline logging operations are completed at final total depth, the well will be plugged and permanently decommissioned as planned, and the rig will move to the Apus-1 well location 20 km south-west of the Pavo-1 well location.

Serica Energy has confirmed that production has restarted from the Rhum gas field in the UK North Sea following a successful operation with a Diving Support Vessel (DSV) to replace a faulty component in the Rhum Subsea Control Module, which had necessitated a temporary shutdown of Rhum production in February 2022.

The operation was carried out at water depths of over 100 m.

Production from the Bruce field continued throughout the operation and Serica’s other producing fields (Erskine and Columbus) were not impacted by the issue at Rhum. During the Rhum outage, the company’s average net production was in excess of 15 000 boe/d.

Mitch Flegg, Serica Energy’s Chief Executive, said that optimising the Bruce production rates had minimised cash flow reduction.

Neptune Energy confirms discovery at Hamlet well

Veolia/Peterson JV given decommissioning contract

Fennex secures contract wins worth over £250 000

Neptune Energy and its partners Petoro, Wintershall Dea and OKEA have announced hydrocarbons were encountered at the Hamlet exploration well in the Norwegian sector of the North Sea. Having entered the reservoir, located within the Gjøa licence (PL153), logs encountered hydrocarbons and a decision was made to initiate coring.

The operations in the reservoir section are still at an early stage and it has yet to be confirmed if commercial volumes are present.

A contingent side-track may be drilled to further define the extent of the discovery.

Located 58 km west of Florø, Norway, at a water depth of 358 m, Hamlet is within one of Neptune’s core areas and close to existing infrastructure. The drilling programme comprises a main-bore (35/9-16S) with an optional side-track (35/9-16A) based on the outcome of the exploration well.

Hamlet is being drilled by the Deepsea Yantai, a semi-submersible rig owned by CIMC and operated by Odfjell Drilling.

Neptune Energy operates the well with a 30% interest.

Lerwick Harbour is to be the location of a further decommissioning project following the award of another North Sea contract to international partnership, Veolia/Peterson, to dismantle and recycle a northern North Sea platform jacket.

It follows their winning the contract to decommission the 14 500-t topside for the same platform, the biggest to date at the port’s Dales Voe Base and recently successfully completed on time, with Veolia/Peterson achieving their target of more than 98% materials recycled.

The latest project has been awarded by Allseas. The 83-m high steel jacket, weighing around 8500 t, will also be delivered by Allseas’ Pioneering Spirit construction vessel in April.

Preparation is well underway at the site for receipt of the jacket. Like the topside, it will be removed in a single lift and transferred ashore at the base via a barge. A heavy-duty purpose-built decommissioning pad will again be used. Decommissioning of the jacket is expected to take around 8 months to complete.

Fennex is continuing its growth following recent contract wins worth over £250 000 with personnel increases and entry into new markets.

The Aberdeen company has seen year-on-year growth since it was established in 2016. The company designs, builds and implements solutions to digitise, automate and transform critical industry processes.

Project wins over the last 6 months include an integration solution to support the rig start-up for a major new offshore project off the coast of Mexico, the first for Fennex in the region. The company also recently developed a bespoke extreme weather software solution for a major drilling contractor in the Gulf of Mexico.

To support the increase in demand for its services, Fennex has increased its specialist software team by 40% over the last 2 years, bringing its headcount to 12. Recognising the need to support the next generation of AI and tech specialists, the company also has a programme of graduate placements with six students given the opportunity to gain vital sector experience.

8 | Oilfield Technology Spring 2022

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The great disconnect Mfon Usoro, Jean Charles Combe, Pablo Prudencio and Mark Oberstoetter, Wood Mackenzie, USA, consider why US oil production growth and investment is disconnected from surging oil prices.

O

il prices have surged this year as a result of the war in Ukraine but drilling activity in the US, particularly in the Permian Basin, does not fully reflect this. The disconnect between oil prices and activity levels is more pronounced than ever. And while 2021 was clearly an outlier year, activity so far this year is even further removed from historical trends. Well spuds today reflect something more akin to a US$50/bbl price environment.

The reason for the disconnect is continued capital discipline, which has impacted reinvestment rates. Two US basins – the Permian and US Gulf of Mexico (US GoM) – are worthy of a deeper dive and highlight examples of how corporate factors are limiting growth in activity levels despite the rising oil price. The Permian and the US GoM accounted for over half of US oil production in 2021 (Figure 1).

10 |

Key reasons why tight oil growth is not surging more this year

A combination of lingering balance sheet concerns, field development patterns, cost inflation, tight labour and the strong need to not deviate from 2021’s successful playbook all compound on one another. Energy transition pressures play a role in the restraint, but are muted compared to their impact on global upstream spending elsewhere.

Some developments might suggest that companies are well positioned to advantageously increase budgets and accelerate rig additions. Leverage is lower, equity valuations are up and companies are embedding cost synergies. Yet, despite this, the capital discipline put in place in 2021 has proved iron-clad.

| 11

The Permian remains the bellwether for production growth.

Wood Mackenzie’s latest Lower 48 supply outlook calls for nearly 0.5 million bpd of crude and condensate year-on-year growth in 2022. This represents tight oil production growth levels close to what we saw back in 2017 – but with an average oil price that is US$30/bbl higher.

The Permian is highlighted in Figure 2, as it contributes the most to monthly rig additions and 85% of all Lower 48 liquids supply growth over the next 5 years.

Company peer groups heavily influence supply growth this year

Understanding the nuances in the operator landscape is more important than ever to calibrate supply expectations. Each Permian operator peer group is following a different path and some E&Ps will push harder than others. Wood Mackenzie has analysed how the majors, largest privates and independents are responding to 2022 price signals as future supply trends are analysed.

The majors in the Permian are set to see year-on-year gains of circa 170 000 boe/d via significant spending hikes. However, that growth includes associated gas and NGLs. For perspective, the 2022 activity level will be at most one-third of their combined 100 rig peak in early 2020.

Permian private E&Ps are more of a wildcard, as they have been growing aggressively and bring upside risk if their strong momentum remains uninterrupted. The largest ones, led by Mewbourne and Endeavor, control over 60 rigs and could add over 100 000 bpd this year if they continue the same growth trajectory as last year. But downside supply risk – albeit smaller – also persists if any of the large privates are purchased in a market that is still consolidating.

While public independents control the lion’s share of Permian production, they are so far only guiding towards flat or single-digit growth in 2022. Therefore, their production trajectories can counterbalance growth from the other groups. For example, ConocoPhillips has messaged it intends to only add four rigs across the entire Lower 48 this year. Devon averaged 16 rigs in 4Q21 and is guiding towards an average of 14 rigs this year.

Looking at 2022 and beyond, public independents are showing no signs of deviating from the current playbook of strict capital discipline, improving leverage and maximising investor returns. Rising oil prices have made little difference to date.

That leaves future supply growth largely in the hands of the majors and private operators, who only control a fraction of Lower 48 supply. Despite all of that, oil production in the Permian is at an all-time high (Figure 3), and Wood Mackenzie expects the play to continue leading Lower 48 growth for the foreseeable future.

Figure 1. US liquids production growth indexed to 2015. Source: Wood Mackenzie oil supply tool (US$50/bbl long-term).

Figure 2. Permian horizontal rig count to WTI price relationship. Source: Wood Mackenzie, Baker Hughes, EIA. WTI = nominal.

12 | Oilfield Technology Spring 2022

Is the US offshore showing similar growth trend seen in the Lower 48?

US offshore production is set to grow to record levels, but most operators in the region are also exhibiting similar capital restraint as seen in the Lower 48. Wood Mackenzie estimates US GoM 2022 production to reach 2.4 million boe/d. But the growth is not driven by the uptick in oil prices, as offshore operations are long-cycle in nature and lack the flexibility to ramp up activity quickly. The production growth is a result of an investment cycle that began in 2016.

Three new semi-submersible production facilities are expected to begin production this year, including the BP-operated Argos, Shell-operated Vito and Murphy-operated King’s Quay.

The three projects were sanctioned between 2016 and 2019 and discovered as far back as 2009.

Evidence of continued capital discipline can be seen in project well above US$100/bbl will not spur much more activity. But even if sanctions in the US GoM. Wood Mackenzie expected five major a theoretical price trigger is hit, any growth will be checked against projects to be sanctioned in 2022, but one will likely be delayed financial performance – and oil prices are not guaranteed to stay at or fall off the queue of pre-final investment decision (FID) projects the current high levels. entirely. 2022 had been pegged by Wood Mackenzie for the sanction There is no denying the massive impact US tight oil growth had of the ultra-high-pressure North Platte project. But the operator – on global oil and gas markets over the past decade. Future Permian TotalEnergies – recently pulled out of the project, citing better capital growth will still be closely watched. But Wood Mackenzie expects allocation opportunities in their portfolio. Although North Platte’s the volumes to be much more modest. Volume growth in the next economics are attractive, it missed TotalEnergies’ new hurdle rate decade will come more from OPEC countries, Brazil and Guyana. for oil investments of CAPEX plus OPEX of US$20/bbl and breakeven Instead of sheer volume additions, the next decade could of US$30/bbl. Wood Mackenzie estimates CAPEX plus OPEX of instead see North American innovation leading the sector on energy US$22/bbl and breakeven of US$36/bbl (NPV10), which is not far transition topics. Companies are addressing methane emissions, from but outside the bar TotalEnergies set. This highlights the strict planning small and large carbon capture and sequestration adherence to capital allocation criteria set by public companies, projects, and making increasingly ambitious carbon pledges. especially amidst execution of energy transition strategies.

Funding these efforts while still addressing shareholder returns Wood Mackenzie still foresees projects like the LLOG-operated will be another factor moderating volume growth from the region.

Leon/Castile, Shell-operated Rydberg and Chevron-operated But the US will continue to play a critical role in supplying energy Ballymore getting sanctioned in the near-term. These operators to the globe. remain committed to the US GoM and their respective projects rank favourably in their global portfolio.

But the shift in sanction and first oil date for North Platte will have an impact on the long-term pace of production growth in the US GoM (Figure 4).

Early indicators of a price-induced ramp-up in activity would be increased exploration activity and pursuit of short-cycle tie-back opportunities. But operators in the region are not signalling a major increase in 2022. Wood Mackenzie revised its exploration well forecast to 25 wells, which represents a 25% increase from 2021. But 25 wells is a far cry from the 40 wells drilled in 2012 when the oil price was around US$100/bbl. Operators continue to maintain structural cost improvements made since Figure 3. Permian Basin oil supply by operator type. Source: Wood Mackenzie Lens.

2014, like minimised appraisal drilling, dual use of wells and phased developments. Aside from companies keeping their purses tightened, supply chain log jams limit the ability of operators to ramp up drilling activity. Rig supply in the GoM area is tight and the lead time for subsea production system kit orders has risen.

Will the capital restraint trend be reversed?

Most trends eventually turn, which begs the question: is there an oil price at which companies will ramp up drilling in the US? So far, recent comments from Lower 48-focused companies like Pioneer suggest that even seeing prices

Figure 4. US Gulf of Mexico oil and gas production. Excludes yet-to-find volumes. Source: Wood Mackenzie Lens.

Spring 2022 Oilfield Technology | 13

THE SANDS OF BRINE F

ar from the mythical Sandman of folklore who brings pleasant sleep and sublime dreams, sand production in oil and gas operations is an all-too-real nightmare that seems to intensify with every improvement in production technique. Finding novel ways to squeeze more hydrocarbons from the formation invariably entails producing not only more water but also more sand – in many cases, a lot more. Not only are sands of finer grain size being used as proppant (further complicating its capture and removal), producers are encountering increasing volumes of sand as operations tap into an ever greater number of ‘soft’ formations, especially in gas fields.

And as the demand for natural gas continues to soar with the shift away from coal and other trends, the volumes of sand will naturally track with that upward demand.

Costly geophysics

Sand in the flow stream may be an old problem, but it remains as serious as ever, and it is just as ‘scalable’ as the best modular equipment. Sand can inflict tremendous harm on everything in the wellbore: from the smallest section of tubing to the casing, all the way up to surface equipment and downstream production facilities.

It can even compromise wellbore stability and prematurely end the life of a well. If sand-blasting with only moderate pressures can

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remove layers of rust from metal and carve lines in concrete, imagine what it can do at the high pressures found in wells.

Moreover, the problem is not confined to this or that basin – it is global and prevalent in Africa, North America, South America, Southeast Asia and other regions, both onshore and offshore, particularly in gas fields where reservoir formations are unconsolidated or semi-consolidated. High-flowrate gas wells are especially prone to damaging levels of sand production, where the elevated flow and turbulence exerts drag on the formation, thereby dislodging ever more sand particles, which are then accelerated to erosive velocities that wreak even more havoc on operational infrastructure. Much more than a mere inconvenience, the damage wrought by sand continues to cost companies millions of US dollars every year.

Hydrocyclones: not just spin

Fortunately, and despite the headwinds, the same industry that has for some 170 years fuelled modern living and economic growth continues its long-held tradition of pioneering innovation. Just as recycling flowback and produced water continues to evolve and become the norm, the removal of sand from the flow stream has advanced dramatically in just the past few years.

Brandon S. Mitchell, TETRA Technologies, USA, says the decisive advance in sand removal technologies in recent years is cause for celebration.

Hydrocyclone technology has now eclipsed passive filter systems and cyclonic sand separators as the favoured means of managing high volumes of fine sand, yielding greater levels of efficiency in removing sand from the flow stream. In fact, one particular advanced hydrocyclone technology has been achieving consistent efficiency rates of 97+% and as much as 100%. Such efficiency rates are gauged by placing separators downstream from the cyclones and measuring the amount of sand they capture, which is now often close to zero.

Centrifugal wizardry

The hydrocyclone is basically a cylindrical-shaped device with a lower conical section, outputs at the top and bottom – called the overflow and underflow, respectively – and an angled feed input on the side near the top. Inside is the vortex finder, a tubular section extending downward a short length from the overflow, and the apex valve adjacent to the underflow.

The core operating principle of the hydrocyclone is centrifugal force, but unlike its cousin, the centrifuge, it has no moving parts.

The elegance of the design is that it exploits the velocity of the well’s output to impart centrifugal force on solids as they enter the unit at a tangent to the cylindrical body. The decreasing radius of the conical section increases the centrifugal force, which enhances the

separation of the sand and solids from the fluid (this latter term denoting both liquid and/or gas).

Inside, the multiphase content whirls around with enough velocity to force the heavier and denser sand particles outward against the walls of the body, while the vortex finder induces the solids-free fluid to form a vortex column in the centre. The force, described by Bernoulli’s principle, diverts the solids-free vortex upward through the overflow, while gravity forces the sand to funnel down through the apex valve and out the underflow.

Variation in the field

Regarding the application of sand management technologies, and oversimplifying the operational picture to some degree, we could say: all uncomplicated operations are alike; each operation with high sand production is complicated in its own way. That is to say, no two high-volume sand production scenarios are the same; each is unique and requires a solution tailored to the specifics of the reservoir, the well, the flowrate and the sand.

Thus, innovating technologies to address sand production is only half the equation; the technology must also be adapted to accommodate the enormous variation among not just several wells on the same site but also the variations within a single well –

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varied pressures, varied volumes of sand, varied particle size, varied flowrates and other potential variables all occurring in the same well.

For example, the initial peak flowrate of a well immediately after stimulation is typically much higher than the subsequent normalised, long-term flowrate. When dealing with a high-flowrate gas well, the initial peak could be exceptionally high.

Tailored adaptation to the uniqueness of each job is achieved through meticulous planning (the importance of which cannot be overstated) and having a scalable technology, a technology that lends itself to adaptation in the interests of efficiency, effectiveness and footprint. Depending on the expected well conditions, modular hydrocyclones can be outfitted with one of several inserts, each of which is designed to be efficient through a wide operating range.

The inserts can reliably endure the harsh stresses of fast-moving, solids-laden fluids for up to a year, and they are affordable when replacement is necessary.

In terms of scalability, both filter systems and hydrocyclones are scalable, but there is a catch: filter systems can exert significant back-pressure on the flow stream, handicapping production, especially when stacked in series. By contrast, the inherent design of the hydrocyclone minimises back-pressure by not tapering the fluid flow.

Automated is differentiated

Once a carefully planned and properly sized solution is in place, adding automation greatly amplifies overall operational efficiency.

As with water management, an automated sand management system enables TETRA Technologies to reduce the number of personnel needed onsite to operate all the equipment. Instead of, say, four workers constantly changing filters or manually dumping sand from separators, it is now possible to reduce personnel requirements to a single roaming technician performing routine maintenance and ensuring everything runs smoothly.

Meanwhile, automated monitoring and control keeps operations humming along with maximum consistency, reliability and safety,

either from a distant control centre or the field technician’s phone or tablet. Adding to its benefits, a ‘smart’ automated system not only provides a host of metrics on efficiency and volumes – invaluable for reports and subsequent job designs – it can also apply algorithms to automatically tweak operations to further optimise performance and efficiency.

Case study

In the summer of 2021, a producer operating six gas wells with very high flowrates in Ohio’s Utica Shale Play approached TETRA seeking an efficient, adaptable sand management solution. In addition to the required small footprint due to limited space on the pad site, the system had to accommodate the very high flowrates the region is known for, as well as be adaptable to the variation from the initial peak flowrate immediately after stimulation to the subsequent normative flowrate. In addition to their high output, the wells were unique for their exceptionally long laterals of nearly 20 000 ft (6069 m), whereas most laterals in the region extended no more than 10 000 ft (3048 m). It goes without saying that the longer the lateral, the more opportunities for unwanted sand production.

TETRA engineered an adaptive solution that used the company’s SandStormTM advanced cyclone technology to achieve 99% efficiency in sand removal with a peak flowrate of 255 million ft3/d from the six wells, a yield that surpassed all other well pads in the area. With the SandStorm units operating so efficiently, the value for the operator has been virtual elimination of the risk associated with sand in the flow stream, thereby safeguarding the equipment while enabling a very high rate of production volume.

Finally, a seismic shift

Within the past 5 or so years, as sand removal technologies have advanced so decisively, the industry has seen a lexical shift from “sand control” to “sand management”. While this might seem like a rather trivial semantic distinction, it is actually a telling turn. It signifies less of a piecemeal improvement and more of a clean break from the past, a reorienting from a thoroughly reactive stance of just trying to control the production of sand, with limited success, to a radically proactive stance of managing and overcoming the challenge. This shift is not unlike the digital revolution or the recent advancements in water management, moving from disposing of produced water in saltwater wells to recycling it for use in hydraulic fracturing.

Of course, there is no final goal post in the field of industry and technology – there is always room for continuous improvement. Invention is always required, especially given the exponentially rising demand for energy on the planet. But amid today’s disruption and chaos, it is reassuring to pause for a moment to consider how much has been achieved in just the past 5 years, enduring the unpredictable vagaries of the market, politics and pandemics, fired and fuelled by our industry’s insatiable spirit of innovation.

Figure 1. TETRA SandStorm advanced cyclone technology captures frac sand and solids with efficiency and minimal pressure differential, without line restrictions or moving parts.

That is certainly worth celebrating.

16 | Oilfield Technology Spring 2022

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PULLING THE PLUG ON FRACTURING CHALLENGES Jenny Darnell and Mohammed Munawar, NOV, USA, detail a new dissolvable frac plug designed to solve modern downhole challenges.

A

cross the industry, extended reach wells are becoming the norm. An emphasis on minimising drilling and completions costs has pushed out lateral lengths, meaning fewer wells are needed to maintain the same amount of reservoir contact. Today’s longer laterals, enhanced drilling techniques and friction reduction tools have delivered new challenges to operators, though.

Modern wellbore challenges

Due to the constraint of deploying coiled tubing (CT) to reach the bottom of extended reach wells, it is impossible to deploy traditional composite plugs beyond a certain point. Difficult well geometries make friction reduction methods difficult, expensive and, sometimes, inefficient.

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In plug-and-perf completion operations, there is a concern about the drill-out of composite plugs and remaining plug debris in the wellbore that could hinder future well completions, production and workover success. In addition to the potential for debris, operators have used different technologies to evaluate downhole conditions and perforation erosion, and been confronted with oversized casing erosion due to unreliable elements in frac plugs.

Operators have seen big holes around the frac plug area.

The main problem is the seal around the rubber – after it is hit with high pressures the seal is penetrated, resulting in higher velocities around the slips area. Introducing proppant to the system in these areas will act like sand jet perforating, creating bigger holes in the casing and allowing the frac to go to one area rather than planned perforations.

To control the frac, it is essential to maintain the integrity of the casing.

While dissolvable frac plugs are available on the market, most do not have any back-up protection for the rubber for reliable isolation and require ideal wellbore conditions to dissolve completely, reintroducing the potential for debris-related slowdowns and inefficiencies. The challenge has been getting the right design and dissolvable technology to provide complete zonal isolation throughout the stimulation phase and reliably dissolve in an expected timeframe.

Solving frac plug issues

NOV’s VapRTM dissolvable frac plug’s design, downhole performance during frac treatment and customisable material together provide a solution to frac plug issues.

The plug has a metal-to-metal, expandable, dissolvable back-up system, is fully dissolvable and is designed to provide a dependable method for temporary zonal isolation during frac operations in vertical and horizontal completions.

Its compact, minimalistic design eliminates milling and post-frac cleanout, leaving no debris to remove from the well.

The flug features 60% fewer parts than other products, leaving less material in the well to be dissolved, maximising the fluid area contact to ensure consistent material dissolution and eliminating remnant debris, which makes wellbore cleanout efficient and reliable.

Case studies

With many dissolvable plug options available on the market, operators look for a product that performs well in all categories:

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ease of deployment, pump-down maximisation, pressure and mechanical resistance, and dissolvability, rather than a product that focuses solely on material selection. The VapR incorporates each of these metrics and provides strong operational performance while allowing significant dissolution improvements over previous generations of dissolvable frac plugs.

An operator in the Utica Shale Play of the Appalachian Basin deployed multiple VapR dissolvable frac plugs, with the Figure 1. An emphasis on minimising drilling and completions costs has pushed out lateral lengths, deepest plug installation occurring meaning fewer wells are needed to maintain the same amount of reservoir contact. at 16 247 ft. The robust design allowed the operator to maximise efficiency in reducing water consumption and operation during pump-down operations, with rates of up to 19 barrels per minute (bpm) and 550 ft per minute line speed. During frac operations, 100% of the ball seat signatures were identified and no slipping of the frac plugs was observed, with a maximum frac rate of 90 bpm at 11 400 psi surface treating pressure.

In one of the stages, operations were shut down due to an issue with the surface pumping equipment that left the plug subjected to corrosive downhole fluids for several hours. Despite this exposure, the frac plug continued to hold treatment pressure, maintaining zonal isolation and maximising performance.

Upon cleanout, no downhole tags were observed for the plugs, confirming that they had completely dissolved in a challenging low-temperature environment.

Operators experienced similar success in the Permian Basin when VapR plugs were used in three wells, covering more than 40 zones each. The plugs were set at targeted depths and maintained grip with no slippage in each well. The ball signatures at each stage were clear and improved fracturing efficiency with zero downtime.

Operators placed approximately 200 pounds of frac plug material in each of the three wells. Upon cleanout, less than 20 pounds were recovered, confirming the efficiency of the plug’s design and enabling a smoother transition to the production phase.

Figure 2. Multiple VapR frac plugs deployed in a well in the Appalachian Finally, the plug has been deployed on several occasions Basin. in Western Canada, where it is commonplace to pump acid for each zone for reservoir reasons. The ability for a dissolvable frac plug to seal in these scenarios is of vital importance, as most dissolvable materials are not acid-compatible. Operators have long struggled with leaks past dissolvable frac plugs. The VapR’s reliable seal/back-up system allowed these operators to place acid successfully and maintain zonal isolation and frac plug integrity during stimulation operations.

Conclusion

Figure 3. The VapR dissolvable frac plug’s design, downhole performance during frac treatment and customisable material provide a solution to frac plug issues.

20 | Oilfield Technology Spring 2022

Operators have long struggled with the integrity of dissolvable frac plugs, leading to premature plug failure, inefficient operations and job site frustrations. The dissolvable frac plug developed by NOV provides reliability and strong performance, adding a modern twist to the industry’s solution to this issue.

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ADDRESSING OFFSHORE CHALLENGES THROUGH DIGITALISATION OF OPERATIONS T

he oil and gas industry is known for moving through cycles, and each cycle represents a challenge for the industry.

Most experts were worried about the low oil prices during the previous downturn, but no one ever expected the unprecedented outbreak of the COVID-19 pandemic, which has disrupted the balance of demand-supply to levels never seen before. Therefore, maximising production from existing infrastructure and minimising costs for well intervention and well abandonment are key objectives for operators during the current pandemic in order to accelerate the transition of the oil and gas industry to a more sustainable future. With these challenges accentuated even more in the offshore environment, the oil and gas industry has remained resilient with the support of oilfield services companies.

COVID-19 has limited the ability to travel, and many companies struggled especially during the beginning of the COVID-19 emergency to get the required specialists offshore to perform the necessary drilling and well activities. While some operators had focused on integrated operations (IO) before the pandemic, many more have been forced to conduct this type of operation during the pandemic as a contingency measure to keep operations running.

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Archer Oiltools has focused on offering solutions where well integrity, reliability and time savings are of the highest importance; to meet these requirements, the company has implemented solutions into their IO to improve operational efficiencies offshore and act upon these challenges, demonstrating how safe, cost-effective operations with high efficiency and minimum staffing can create value for operators.

IO

IO are defined as the integration of people, disciplines, organisations, work processes, information and communication technology to help operators make smarter decisions in real time. Together with oil and gas operators, digital enablers and cutting-edge technology, IO have allowed platform and rig operations to be integrated into a collaborative environment where offshore skills can be augmented with onshore expertise to enhance execution, deliver more complex solutions whilst reducing the rig-based people on board (POB) and reduce risk exposure for employees.

The company has executed IO in the North Sea region for the past decade. Currently, more than half of the temporary and permanent

Andreas Fliss, Elisabeth Norheim and Fernando Zapata-Bermudez, Archer, Norway, discuss how the COVID-19 pandemic and CO2 emissions have created offshore challenges that are being overcome by technology.

suspension plug operations it has carried out are performed with the IO model. Since the first implementation of IO, the company has conducted more than 1900 remote operations through its IO centres, reducing the POB with the equivalent of 2850 people offshore. That translates into net savings of 92 910 t of CO2 emissions – the same quantity of CO2 emitted by driving a diesel car for 557 million km, according to the industry energy management calculator. Having fewer personnel who are required to travel offshore does not just mean a reduction in helicopter flights from the shore to the offshore location but also a reduction in travel for the personnel from their home location to the onshore location, which is often a long trip crossing perhaps several countries or even continents.

While Archer started with suspension plugs, the company has also recently expanded to other products, such as cementing solutions.

Successful IO have been delivered in Azerbaijan, the US Gulf of Mexico, Guyana, Brazil, Malaysia, Australia, Russia and Canada.

IO value proposition

Archer has demonstrated the integration of their operations through tangible examples from the North Sea, Qatar, Guyana and Canada,

where restrictions on field personnel going offshore due to COVID-19 resulted in remote operations taking place. This has reduced the cost of POB, helicopter flights or additional transport costs and lessened risk exposure for personnel, but most importantly enabled the continuation of operations offshore. Due to the implementation of multiskilling programmes across all their operating divisions, reduced field crews are capable of performing multiple operations that follow the standard operating procedures implemented by the company; these include digital workflows, check lists and a competency assurance process which, supported by IO centres located in two different time zones, are ensuring safe and high-quality operations 24/7.

The IO centres receive real-time data from the rig or platform operations using a sophisticated IT enablement digital workflow, with a secure and redundant connectivity to the offshore installation (data latency usually less than 2 seconds) and onshore application software. In addition, the fully operational IO centres provide a real-time enhanced work execution environment for full remote operations (onshore specialist and offshore rig crew) or in a hybrid IO operation (onshore and offshore specialist) for more complex operations.

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It is critical that the design of new technologies and equipment is done so as to allow the implementation of more complex IO that are also more sustainable and in harmony with the aims of the energy transition: for example, designing new technologies and implementing solutions that reduce the number of metres with tripping of drill pipe and time spent on P&A operations. When combining these technologies with IO, it becomes the ideal way to operate with less CO2 emissions offshore.

IO reducing the CO2 footprint from operations

For IO to support a reduction in CO2 footprint, it is critical that the entire organisation focuses on supporting and further developing a low carbon agenda whereby the industry is committed to contributing significantly to the ongoing energy transition process. Through continuous development of new technologies and solutions that reduce energy consumption from fossil fuels and with enhanced operating models such as IO, Archer is making an impact on the delivery of low carbon operations. With a broad portfolio of products and services within slot recovery and P&A, the company is in a position to deliver lower carbon solutions to the operators. This is being accomplished through more efficient operations and developing cross synergies between business units, as well as employing complementary service providers that are aligned to the same net zero goals. With this operating model the number of POB in offshore

installations is being lowered, reducing rig hours and eliminating multiple trips to the well. This practice directly reduces emissions, reduces carbon footprint and improves industry sustainability in comparison to traditional methods. In brownfield developments, the company is committed to the net zero goals of greenhouse gas (GHG) reductions by supporting the industry with a wide range of technologies that drive short-term operational efficiencies and optimise operational times to generate a much lower volume of emissions into the environment.

The next level of IO

The company’s digital solutions, which today are being used to support the IO model, are moving into the next level of digitalisation by using virtual reality (VR) for more efficient and advanced learning processes in simulated offshore environments. Unlike traditional training methods, VR immerses the learner in the contextual scenarios offshore to help them acquire the experiences needed to respond successfully in a real-world scenario. On the other hand, the use of mixed reality (MR) – where employees are immersed in scenarios that combine physical and virtual environments – is moving offshore operations to the next level through solving more complex tasks and allowing experts to reach offshore operations anywhere and anytime. The MR in the company’s Stavanger and Houston operations delivers an augmented reality experience during offshore remote inspections, equipment verification/troubleshooting and incident management. It is becoming a technical differentiation as the technology addresses the current challenges of cost efficiency and energy transition models.

The company is building digital assemblies and maintenance instructions that can be run on MR, can identify the equipment, components and parts, and display 3D models to facilitate all types of maintenance work. Engineering teams in charge of new technologies are launching them with digital 3D operating and maintenance manuals to align with the company’s vision on digital transformation initiatives.

Case study 1: Caspian Sea Challenge A major international operator requested the company install two V0-rated barrier plugs in one run to optimise the efficiency of the operation and save rig time. Due to COVID-19 the operator challenged Archer to provide a solution to overcome personnel and travel restrictions, without compromising service quality.

Figure 1. The next level of IO.

Solution Archer proposed using the VAULT® dual plug system to set and retrieve two plugs in a single run. Selected for the operation were a 10 in. TIMELOCK® as the deep set and a 9 5/8 in. VAULT as the shallow set plug. In order to meet the barrier suspension criteria, both plugs were pressure-tested. In addition, to overcome travel restrictions on personnel, an IO centre was set up in collaboration with the operator’s remote support centre to receive real-time data from the rig during the operation and communicate directly with the rig team.

Result

Figure 2. The future is digital in the oil and gas industry.

24 | Oilfield Technology Spring 2022

A real-time communication link was established between the operating rig and Archer’s remote support centre in Aberdeen. All pre-job checks were completed according to best practice and the VAULT dual plug system was deployed and run to the planned setting target depth. The actual setting operation was closely monitored and supervised from the IO centre.

The entire operation was conducted without any issues.

Case study 2: Gulf of Mexico Challenge A major international operator challenged Archer to provide a solution to overcome personnel and travel restrictions during the COVID-19 pandemic, while delivering a high level of service in the Gulf of Mexico.

Solution Archer implemented a remote control centre to follow all operational steps in real time and support its operations 24/7.

Result Using IO in Houston, Archer established communications with the rig.

The operator performed offshore checks as per Archer’s guidelines and proceeded to run in hole with the TIMELOCKTM assembly. Upon arriving on the setting depth of 9550 ft, the IO support team was able to oversee and provide real-time support of setting and testing the assembly, resulting in a successful temporary abandonment of the well.

As a result, the customer overcame issues related to: POB. Transport (helicopter flights).

Health and safety (HSE) risks.

Environmental footprint.

� � � �

All of the above were achieved without compromising delivery standards.

Case study 3: offshore Eastern Canada Challenge Operating in Eastern Canada involves facing harsh weather conditions, including the risk of icebergs and severe storms during the Atlantic

hurricane season. A major operator in the Flemish Pass area required temporary well suspension at short notice due to a fast-approaching storm system. In addition, COVID-19 presented a challenge to mobilising personnel.

Solution Archer’s STORMLOCK®, which delivers V0 gas tight isolation while allowing the option to set without the need of hang off weight or, when needed, the capacity off suspending up to 660k-lbs below, was selected. The V0-rated 13 5/8 in. STORMLOCK was mobilised and prepared to run and set without company personnel on the rig. The operation was planned to be achieved with the assistance of the IO team in Houston monitoring the operation in real time.

Result The STORMLOCK was run, set, tested and retrieved successfully according to plan, demonstrating its capability by providing the customer with V0 protection in a harsh environment. The operation was delivered efficiently without POB, proving IO capabilities for the first time offshore Eastern Canada.

Conclusion and summary

IO are a proven way to help the oil and gas industry in its transition to a more sustainable future by reducing the number of people required to travel offshore and be subsequently exposed to the offshore environment. This in turn contributes to a significant reduction of CO2 footprint by limiting travel between home locations and offshore locations. Archer has contributed in the last few years with CO2 emission savings of nearly 100 000 t. Looking forwards, the stage is set to enhance further IO processes so that they are able to cover more complex activities and the majority of all operations.

Figure 3. Customised solutions for every well.

Spring 2022 Oilfield Technology | 25

MAKING STRIDES AGAINST WELL INTEGRITY CHALLENGES Ørjan Frøyland, Expro, considers how annular intervention can offer a solution to well integrity challenges.

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W

ell integrity is one of the biggest challenges facing the offshore oil and gas industry and is a growing concern for businesses. Currently, an estimated 30% of wells around the world experience integrity problems that have the potential to negatively impact both production and the environment.1 As the age of well stocks increases, the need for effective integrity measures to optimise production will grow.

When tackling annulus sustained casing pressure, the traditional way has been to start bleeding down the pressure, followed by a ‘lube and bleed’ operation. Further on, a complete workover is undertaken to cure the sustained casing pressure and return the well to production. However, the costs of deploying such rigs are significant and these have to be weighed against the anticipated economic returns from the well.

Meanwhile, the industry’s continuing quest for economic methods to extend output, regain shut-in and low-producing wells and ensure the sustainability of operations continues to demand advanced technical solutions and processes that can deliver more from less.

To this end, Expro has engineered a solution that allows the intervention of wells through the A, B, C or D annuli which, in turn, enables precision placement of wellbore treatment fluids deep into the targeted annulus. The minimally intrusive equipment allows the remediation of annular issues and reduces fugitive emissions. The system is opening up the potential for widespread annular intervention to resolve a range of well integrity issues and extend the life of wells previously classed as uneconomic.

Solving well integrity challenges through annular intervention

The company’s new OctopodaTM annulus intervention system is the only certified system in the world that allows direct access to live well annuli without the expense of a heavy workover rig and with a reduced environmental footprint.

The first system to enable intervention in an annulus, it provides full well control, assured well integrity and enhanced production without disrupting operations.

The system removes shut-in casing pressure, replacing annulus fluid to increase hydrostatic pressure in the annulus or sealing top of cement (TOC), casing shoe and casing-to-casing communication leakages. It is deployed through annulus valves while maintaining full pressure control, eliminating the need to remove wellhead components before operations.

The system can be rapidly deployed on all types of installations, including onshore and fixed platforms offshore, to maximise operational uptime while reducing overall HSE exposure.

With advanced corrosion protection extending the lifetime of the well, and through enabling the revitalisation of established wells, it can help create a sustainable impact on asset production and revenue.

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Engineering process

The development of the annular intervention system followed the success of another Expro product – the CoilHose Light Well Circulation System, which is a smaller and faster alternative to traditional coiled tubing systems.

CoilHose was designed to be run in the main bore. However, following its introduction, the company received several additional requests for a smaller hose-based system that could be run in the annulus. By using its experience in hose technology, introducing some ideas from other industries and developing several prototypes, the company created a system specifically designed to answer the demand for annular intervention while enabling full well control.

Engineering a solution that could be deployed in a tight wellhead environment was critical to effectively supporting standard wellhead designs. Equally as important was the design of a hose that had the flexibility to bend and immediately straighten once in the annulus. Incorporating an injector and a heavy bottomhole assembly (BHA) into the design ensured the system would reach the required depths.

Following several successful trial projects, including breaking through salt barriers to monitor the pressure in a Southern North Sea gas well, Octopoda was officially launched in 2021 and has been used in locations ranging from the UK, Norway and Thailand to Colombia, Malaysia and Romania.

These deployments include the world’s first project to help Chevron solve a base oil displacement challenge in Thailand and the achievement of record depths for annular intervention – firstly at 300 m in Colombia, then at 574 m in Romania.

Case study: Thailand

Figure 1. Annulus intervention operations in Romania.

Figure 2. The Octopoda annulus intervention system.

28 | Oilfield Technology Spring 2022

The system was recently used on a Chevron well in Thailand to intervene in the A-annulus and replace Saraline base oil with water ahead of resin placement on top of the cement, successfully reinstating production.

Base oil significantly reduces the effectiveness of resin.

Chevron had previously seen a 50% reduction in the impact of the resin when it was added to an earlier well containing base oil using traditional lube and bleed from the surface.

Having reviewed the effectiveness of conventional methods, Chevron was keen to try the new system to achieve base oil displacement at depth.

Deploying the system meant Chevron avoided having to use the production tubing for circulation via a stimulation vessel or coil. This eliminated the need for communication between the production tubing and the A-annulus, meaning the barrier remained intact between the reservoir and the A-annulus.

The base oil was displaced and circulation was established by pumping fresh water through the annulus intervention system. Despite experiencing space limitations caused by control lines, clamps and centralisers, this was done

at 70 m, avoiding the conventional lube and bleed method or the need to punch the well.

This was the first time the A-annulus had ever been intervened using a conveying hose. Furthermore, it proved the efficiency benefits of annular intervention over conventional practices by reducing time, costs and personnel. The operation lasted 3 days compared to an estimated 10 – 13 days for lube and bleed.

The system’s small footprint, when compared to a pumping vessel or unit, reduced lifting risks and required only a two-man crew. The base oil was collected in a closed loop in the system, which meant exposure to the environment was avoided.

Case study: Colombia

Expro also successfully deployed Octopoda to restore annulus pressure integrity and return a well to production in the Piedemonte region of Colombia.

The system successfully reached 300 m in the annulus – a world record depth at the time – and sealed the C-annulus of the well. This removed the risk of casing collapse and gas migration, and enabled the well to produce and significantly extend its production lifespan.

The operation removed the need for a heavy workover rig to allow controlled circulation of annular fluids and the installation of a resin plug at the external casing shoe depth.

This successfully sealed the annulus and enabled production to be resumed from the wellbore.

The client faced the risk of gas migration through the threads of a non-gas tight casing in a gas well. Due to the risk of communication of gas to the C-annulus in a high production gas well, it was necessary for a mechanical seal to be installed at the casing shoe and a hydraulic seal up to the surface.

Before the annulus intervention system was utilised, there was a risk that the inner casing would collapse, which would have led to a hazardous situation and the plug and abandonment of the well.

As the full hydrostatic column was close to the collapse pressure of the inner casing, it was required to work with low densities to perform the operation. There was no information about the physical location of the TOC in the C-annulus or the diameter of the openhole section behind the inner casing, which complicated the determination of the volumes to be pumped even more.

With the full cooperation of the client, a way to calculate the TOC was determined based on calculations of the density gradient and pumped volumes, which allowed control of the density value in front of the casing shoe and the setting of the resin plug.

By pumping from the bottom of the C-annulus, it was possible to reduce the resin pumping time and ensure the correct fluid density distribution of the brine to guarantee the correct setting depth of the resin plug. This is not possible while pumping from the surface as heavy brine becomes diluted in freshwater, generating a uniform density column in the C-annulus.

The C-annulus was fully sealed, ensuring the integrity of the well for the rest of its productive life. All operations were performed while the well was producing. The alternative solution for the well would have been a full workover intervention or well abandonment. The intervention operation was completed at a cost that was estimated to be approximately 25% less than the cost of a conventional workover rig-enabled repair.

Figure 3. The use of Octopeda by Chevron in Thailand saw the first time an A-annulus had ever been intervened using a conveying hose.

Moreover, the operation resulted in significantly lower carbon emissions than the conventional alternative.

Removing the barriers to annular intervention

The development of Octopoda has opened up a wide range of possibilities for annular intervention. Its successful use in supporting well hydraulics, removing salt or other debris barriers is established; likewise, it has also proven to be highly effective in the exchange of fluids.

Further opportunities for annulus intervention include life extension survey operations in the surface casing conductor area, including camera corrosion inspections, cement location and conductor and surface casing wall thickness evaluations. The intention is to establish the potential for reuse of the conductor and surface casing, which would have both significant financial and environmental benefits when completing new wells.

Annulus intervention can also have a significant role to play in well plugging and abandonment. Installing secure and effective barriers in the annulus would avoid retrieval of the entire completion, which once again would generate environmental and financial benefits.

Conclusion

Through enabling an effective way to conduct annular intervention the use of Octopoda can empower operators to return shut-in and low-producing wells to profitability.

Reference 1.

BRUFATTO, C., COCHRAN, J., CONN, L., EL-ZEGHATY, S.Z.A.A., FRABOULET, B., GRIFFIN, T., JAMES, S., MUNK, T., JUSTUS, F., LEVINE, J.R., MONTGOMERY, C., MURPHY, D., PFEIFFER, J., PORNPOCH, T., and RISHMANI, L.,‘From Mud to Cement – Building Gas Wells’, Oilfield Review (Autumn 2003), pp. 62 – 76.

Spring 2022 Oilfield Technology | 29

Over the hurdle

Jonathan Rogers, Martin Shumway and Dr Amir Mahmoudkhani, Locus Bio-Energy Solutions, USA, review the progress that naturally sourced biosurfactants have made in maximising oil recovery in shale wells – for greater profits and a smaller carbon footprint.

G

lobal demand for energy is expected to keep growing – and oil and gas will remain a vital part of the energy mix for decades to come. Even the most conservative clean energy transition scenarios predict that US oil and gas liquids production will need to increase from the 12.24 million bpd average produced in 2019 to 13.3 million bpd by 2030.1,2 Production from shale wells typically declines by 50%+ in the first year. As a result, meeting increased

30 |

demand requires E&P companies to increase production in cost-effective and sustainable ways to both compensate for these steep decline rates and produce additional crude to meet requirements. Adding to the challenge, producers must address evolving ESG requirements and transition to net zero energy production, even as falling operating costs make it cheaper to produce new barrels of oil. According to Rystad Energy, the average breakeven price for tight oil

was US$37/bbl at the end of 2021, down from US$47/bbl just 3 years prior.3 To boost declining production rates and meet growing domestic energy demand, US operators have traditionally employed conventional enhanced oil recovery (EOR) techniques, such as water flooding, chemical flooding, thermal techniques and gas injection. EOR has a proven history of maximising oil recovery in conventional oil

wells, which are drilled into sandstone and carbonate reservoirs with pore sizes ranging from 1 to 100 μm on average. But these same techniques are not as effective or economically viable in many shale reservoirs with pore throat radii in the range of 1 to 200 nanometres (nm). For size comparison 1 μm equals 1000 nm, with human DNA measuring just 2 nm in diameter. 1 nm is equal to 1 millionth of a millimetre.

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Table 1. Common classes of biosurfactant used in industrial applications.

Glycolipids are the largest and most diverse class of biosurfactant studied to date.

Class

Glycolipids

Family

� � � � � � � � � � � � � �

Sophorolipids Rhamnolipids Trehalolipids Mannosylerythritol (MEL-A, MEL-B)

With pressure mounting to extract more production from existing assets and deliver new wells in a more cash-constrained environment, new technologies are required to profitably boost production and meet more stringent ESG criteria.

Biosurfactants – an innovative alternative technology

Surfactants synthesised from petroleum feedstocks have been used for decades in a range of oilfield treatment chemicals. In Surfactin chemical flooding EOR operations, surfactants aid oil recovery Iturin by altering the wettability of the formation rock and reducing Lipopeptides Fengycin surface and interfacial tensions – which helps mobilise oil by Lichenysin reducing the drag between oil and the reservoir rock. However, Bacillomycin because these surfactants tend to have high usage costs and carbon footprints, the industry has been actively searching Phospholipids Diphosphatidylglycerol for more cost-effective and environmentally sustainable alternatives.

Emulsan Naturally produced, sustainable biosurfactants are a Liposan Polymeric biosurfactants Mannoprotein novel technology showing promise in shale EOR and hydraulic Poly-saccharide protein fracturing operations. These biosurfactants are amphiphilic complexes molecules produced by living microorganisms and use sustainable raw materials – carbohydrates and natural oils in particular – as carbon sources.

Because they are 100% natural, biosurfactants degrade into byproducts that do not negatively impact the environment.

Biosurfactants come in a diverse array of chemical structures. Glycolipids are the largest and most diverse class of biosurfactant studied to date, thanks in large part to their higher fermentation yields and application versatility (Table 1). Significant work has been Figure 1. Representative structures of a highly complex biosurfactant (right) with many chemically active sites conducted on these glycolipids, and a traditional surfactant (left), which contains few active sites linked to a long carbon-chain tail. with recent advancements focused on use of sophorolipids in oilfield applications.

Biosurfactants have unique structures that typically include multiple chemically active sites – a contrast to the limited number of active sites on traditional surfactants (Figure 1). In both laboratory and field studies, the complex structures of biosurfactants give rise to interfacial properties that allow them to consistently outperform traditional, hydrocarbon-based surfactants in mobilising oil in both conventional and tight/shale formations.

Surface/interfacial tension (IFT) reduction is a key measure of surfactant performance.

In commonly used force Figure 2. IFT measurements are used to screen and identify the best biosurfactants for well treatment. tensiometer studies, some

32 | Oilfield Technology Spring 2022

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high-performing traditional surfactants can reduce the surface tension of water from 72 to 35 mN/m and the IFT of n-hexadecane/water from 40 to 1 mN/m. Studies done by Locus Bio-Energy Solutions have shown that biosurfactants have even greater results, reducing the surface tension of water to 25 mN/m and the IFT of water/hexadecane to < 1 mN/m.

The concentration at which surfactant molecules self-assemble into micelle structures, typically called the critical micelle concentration (CMC), is also a key performance criterion. The CMC value of most biosurfactants ranges from 1 to 200 ppm, a fraction

of the CMC of many traditional surfactants. This significantly lower CMC allows biosurfactants to match the performance of many hydrocarbon-based surfactants, but at a fraction of the dosage.

In a typical study conducted by the company, the efficacy of biosurfactants in reducing the IFT of an oil-brine system was evaluated at various dosage rates as a function of time using a drop shape analysis method (Figure 2). The biosurfactants reduced IFT even at concentrations much less than the CMC, a notable property that supports production enhancement longevity.

These IFT measurements are used to screen and select the best biosurfactants for specific well applications.

The company’s studies have demonstrated that application of biosurfactants at a dosage of only 2 ppm is sufficient to reduce the oil/water IFT and cause oil to mobilise from reservoir rock.

Conversely, many synthetic surfactants require dosages of 50 to 100 ppm to achieve the same level of IFT reduction.

Further studies have shown that in addition to lower CMCs, the company’s biosurfactants form micelles that are less than 3.1 nm in diameter, significantly smaller than the micelles of their traditional surfactant counterparts.

As Figure 3 illustrates, their smaller micelle size and lower dosage requirements allow biosurfactants to penetrate deeper into the smallest nanopores and mobilise oil from even the tightest shale reservoirs. This Figure 3. A comparison of micelle size versus depth of penetration in shale rock pores. With an average micelle small micelle size is critical in EOR size of less than 3.1 nm, biosurfactants can penetrate into the smallest nanopores to mobilise oil that typical applications in unconventional tight frac surfactants and nanofluids cannot reach. formations where pore throats are very small. In the Permian Basin’s Wolfcamp Shale, for example, nanopores range from 3 to 18 nm.

Another benefit of biosurfactants is their stability.

Biosurfactants can be used at high temperatures and pH values ranging from 2 to 10. They also tolerate high salt concentrations of up to 10% (or higher), whereas 2% sodium chloride (NaCl) is enough to render some common synthetic surfactants inactive.

Ready for the oilfield

Figure 4. Microfluidic technology provides a high-resolution simulation of reservoir fluid dynamics. This testing demonstrates that when a biosurfactant is included in the treatment fluids up to 90% more oil can be mobilised. In field applications, the results translate to a reduced need for continued refracking to meet production goals.

34 | Oilfield Technology Spring 2022

Biosurfactants have found successful application in a number of high-end medical and consumer products, including pharmaceutical drug delivery, skin care formulations and environmentally-friendly household detergents.

However, the application of biosurfactants in the oilfield has been slow, despite decades of research and promising results.

To be more readily adopted in the oilfield, biosurfactants had to overcome hurdles including high production costs, volume limitations, scalability problems and efficacy challenges.

Recent advances in manufacturing technology, championed

by Locus Bio-Energy Solutions, are now making biosurfactants commercially available at the price point and volumes required for widespread adoption in oil and gas applications. The solutions have a near-zero carbon footprint and do not contain any nutrients or living cells.

The oil mobilisation performance of these biosurfactants has been confirmed in both laboratory and field deployment.

In independent laboratory testing, a microfluidic technique was utilised in which nano-sized pores were etched onto a test chip to replicate the inherent nanoconfined geometries of shale reservoir rock (Figure 4). This template was used to reproduce individual reservoir characteristics and compare the oil mobilisation potential of different chemistries. In tests using a Permian Basin crude oil and Pennsylvania Grade crude oil, the microfluidic technique confirmed that significantly more oil (70 – 90%) can be mobilised when a biosurfactant is included in the frac fluid formulation.

Boosting production in declining wells

Biosurfactants are enhancing oil recovery and removing high molecular weight deposits in reservoirs across major US basins.

Analysis on the latest well stimulations carried out in the Delaware and Midland Basins has demonstrated oil production increases ranging from 50% to more than 100%, and increases in gas production ranging from 20% to more than 80%. The results yielded 1.5 to 4 times return on investment (ROI) and treatment cost payback in less than 4 months – with a minimal carbon footprint.

The significant production gains in EOR applications have operators looking at using biosurfactants to build better-designed shale wells with improved performance from the start. In a recent application in the Bakken Shale, the company’s SUSTAIN biosurfactant was used as part of a re-frac operation of a mature well. The biosurfactant’s performance, as measured

by cumulative oil produced, was compared with the performance of a hydrocarbon-based surfactant used to re-frac two analogue wells (Figure 5). In the first 75 days after recompletion, the well that was re-fracked with a traditional surfactant produced 21 874 bbl of oil.

The well that used a biosurfactant in the completion fluids yielded 25 413 bbl of oil, a 16% increase in production that translated to more than a quarter of a million US dollars of revenue – revenue that would not have been realised without the biosurfactant.

Ensuring higher production from the start

In new well deployments in the Permian Basin, the SUSTAIN biosurfactant helped increase oil production by over 30% in the first 30 days and reach peak oil faster compared to frac jobs with traditional surfactants. The biosurfactant boosted well production by more than 6200 bbl compared to the analogue wells, and at one-third the application rate of hydrocarbonbased surfactants. The treatment paid for itself three times over within the first month.

Conclusion

As the industry continues to embrace new technologies to meet growing global energy demand, biosurfactants are a technology innovation whose time has finally come. By boosting production rates from new and declining wells alike, biosurfactants provide cost-effective solutions to the challenges of optimising production of low-cost, low-carbon barrels and recovering more oil from the reservoir. These low-dosage, robust and ESG-friendly products are gaining recognition as a sustainable way to move the industry forwards in innovation, environmental stewardship, safety and cost.

References 1.

2.

3.

U.S. Energy Information Administration, ‘U.S. crude oil production grew 11% in 2019, surpassing 12 million barrels per day’, https://www.eia.gov/ todayinenergy/detail.php?id=43015 (2 March 2020).

U.S. Energy Information Administration, ‘Annual Energy Outlook 2022’, https://www.eia.gov/outlooks/aeo/data/browser/#/?id=11-AEO2022&cases=r ef2022&sourcekey=0 Rystad Energy, ‘As falling costs make new oil cheaper to produce, climate policies may fail unless they target demand’, https://www.rystadenergy.com/ newsevents/news/press-releases/as-falling-costs-make-new-oil-cheaperto-produce-climate-policies-may-fail-unless-they-target-demand/ (17 November 2021).

Figure 5. In a re-frac operation in the Bakken Shale, the use of the biosurfactant resulted in greater oil production and higher revenue compared to a re-frac job using a traditional surfactant.

Spring 2022 Oilfield Technology | 35

INVERTING THE STATUS QUO

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C

Matthew Offenbacher and Richard Toomes, AES Drilling Fluids, USA, explain why industry scepticism meant a different approach was required when developing an invert emulsion lubricant.

reating an effective invert emulsion lubricant that provides sustained lubricity is an objective of many drilling fluid technologists. Producing a cost-effective additive that delivers performance to drill further and faster has remained elusive for several reasons.

Oil and gas wells continue to push technical limits to improve economics. Longer laterals extend reservoir contact, maximising production across fewer wells. With longer laterals, challenges with torque and drag increase, reducing pipe life, compromising directional control and reducing the rate of penetration (ROP).

At the margins of what is feasible, a few hundred feet of lateral length can make the difference between achieving or failing to meet well production targets.

Water-based drilling fluids with supplemental lubricants are an option, but invert emulsions are the standard for greater lubricity in these challenging environments. The inherent lubricity of the oil in the oil-continuous phase and the oil-wet environment provides consistent and predictable torque reduction.

When torque is an issue with a properly maintained invert emulsion system, there are few options. Invert emulsion lubricants, seeking to replicate the torque reduction potential of water-based additives, have a mixed performance record.

In many cases, the invert emulsion lubricant fails to provide any torque reduction whatsoever. In other cases, the effect is temporary, lasting less than a few hours.

The complex environment in which an invert emulsion lubricant must perform is a seemingly insurmountable challenge.

Customers continue to demand a solution, trying any additive rumoured to provide a benefit. Drilling fluid companies’ research and development teams approach the task with scepticism, given the number of materials that have failed.

In the drilling fluid technology domain, any discussion of invert emulsion lubricants is treated as producing snake oil.

Many products come and go. Even with promising laboratory data, the results simply do not appear in the field. Product development is laden with scepticism as claims of a new product are repeatedly met with a failure to deliver results.

The primary challenge surrounds the complex chemistry of an invert emulsion drilling fluid. Emulsifying surfactants maintain the water-in-oil droplets while wetting agents oil-wet drill solids, weight material and other additives. Emulsions are inherently complex, and introducing another surfactant can, at worst, destabilise the system and, at best, adsorb onto surfaces and fail to reduce the coefficient of friction.

Given this complexity and repeated attempts to meet customer demand, AES Drilling Fluids attempted a new approach. When the COVID-19 pandemic crippled oil and gas activity, product development initiatives were launched to maintain commercial momentum once the market recovered (Figure 1). An invert emulsion lubricant project was identified as potentially having a high impact for customers.

Knowing the implicit bias and general scepticism around potential success, the research and development team knew a different approach was necessary for any breakthrough. In this case, an outside researcher with a strong chemistry background but no specific drilling fluid knowledge was given the task of overseeing the project. This ‘fresh set of eyes’ approach brought every option back on the table. The research and development team still provided design criteria and test methods but avoided introducing bias into candidate chemistry selection from their past experience.

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Development

Figure 1. AES laboratory technician working on new product development through the COVID-19 pandemic.

Figure 2. Illustration of surfactant-based lubricants adhering to solids and internal-phase droplets over time.

Figure 3. Image of the modified LEM and syringe pump during a lubricity test on an oil-based

fluid.

38 | Oilfield Technology Spring 2022

After a literature survey, the researcher worked with the team to secure samples of any number of additives used as lubricants across a variety of industrial applications. The materials fell into two categories: solid lubricants and liquid lubricants. Solid or particulate types, such as graphite, are often utilised with varying degrees of success in the field. These particulates work via a ‘sliding’ mechanism where the lubricating material compresses and deforms between surfaces. Glass, ceramic, polymeric or carbon-based beads typically provide lubricity through a ‘ball-bearing’ mechanism, retaining mechanical integrity to reduce the contact area between surfaces.

Most solid lubricants require continuous addition due to constant removal at the shaker screens. Finer materials, such as nanoparticles, may not be large enough to reduce the contact area. Other factors contribute to performance limitations, such as the material resiliency and risk deformation as friction is applied.

Solid lubricants typically require oil-wetting agents to ensure system compatibility in an oil-based system.

Surfactants, such as strong wetting agents, are the most common liquid lubricants for invert emulsions. While these products often show an initial improvement in lubricity, they often rapidly deplete during the drilling process. Figure 2 shows how surfactants tend to move from metal surfaces and attach themselves to other solids. In addition, the lubricant-surfactant membrane seeks to attach itself to the non-continuous droplets (internal ‘water’ phase) – leading to a precipitous drop in performance.

The screening process included a wide range of experimental products and chemistries, such as graphite-based solid particles, nanoparticles, surfactants and various blends.

A lubricity evaluation monitor (LEM) and common lubricity tester were used to generate standard lubricity coefficient tests for each candidate. The LEM allows for the test fluid to be circulated while applying force. Additionally, the LEM within the company’s laboratory in Houston, Texas, US, has been modified to include a syringe pump (Figure 3), allowing candidate products to be automatically injected into the test fluid at pre-determined concentrations. Data gathered from the LEM is then output in real time using an attached computer running equipment-specific software.

Results are reported as a percent reduction in coefficient of friction versus the untreated drilling fluid.

As candidate chemistries were tested, the selection narrowed down based on lubricity results. Products showing promise were

tested for fluid compatibility – an important step in the evaluation process which verifies the chemistry does not cause any detrimental changes to fluid behaviour.

Many of these candidate chemistries can interfere with the existing emulsion, resulting in dramatic thickening/thinning once subjected to downhole conditions.

After numerous iterations, one chemistry stood out after testing – showing significant initial reductions in coefficient of friction (Figure 4). The additive demonstrated a high level of repeatability across several invert emulsion fluid systems of different density.

Finally, the last key metric was sustainability. Could such a promising material provide lubricity beyond its initial treatment? Systems were treated with the new additive and a significant coefficient of friction remained. This was the last piece of the puzzle to introduce a new additive – one that had never been utilised in drilling fluids before.

Full product and validation testing was performed ahead of a field trial opportunity.

To effectively measure the performance of the experimental product, certain field success criteria were established.

Criteria included a significant reduction in torque and drag, improved weight-on-bit, zero effect on drilling fluid properties and general feedback/anecdotal commentary from field personnel.

Figure 4. Results indicating significant reduction in coefficient of friction of various field invert emulsion fluids using an experimental lubricant blend.

Figure 5. Torque reduction observed in the field using GLYDEX.

Field application

It did not take long for yet another request for an invert emulsion lubricant application.

Figure 6. Image of GLYDEX sample.

An operator in New Mexico, US, was attempting to drill a 15 000 ft lateral section with an oil-based mud. Issues related to poor weight-on-bit and excessive torque values were limiting ROP and increasing the risk of over-torquing drill pipe. After no improvement was seen using a solid lubricant (graphite), the experimental invert emulsion lubricant (EXPL 9050 – an experimental name designation) was added to the drilling fluid system at 3% by volume. An immediate 15% reduction in rotary torque was

observed (Figure 5) – and >20% reduction in torque versus modelled torque was captured at well total depth (TD).

This torque reduction promoted better drilling parameters, optimising ROP and delivering the well on schedule.

This product, today known as GLYDEXTM (Figure 6), has now been used on a number of wells with similar success.

Operators and directional companies alike continue to note the sustained performance from this chemistry.

Spring 2022 Oilfield Technology | 39

New heights below sea level Alexandre de Rougemont, MAN Energy Solutions, Switzerland, shows how new subsea compression systems are facilitating more sustainable and efficient production from deepwater gas fields.

S

ubsea compression is helping oil and gas operators reduce energy use, increase efficiency and become more sustainable. The shift away from topside solutions reduces safety risks as well as the OPEX and CAPEX needed for the traditional manned production platforms. As a provider of compression technology solutions, MAN Energy Solutions is working on future subsea projects, safe in the knowledge that the world’s first subsea compressor system, at Equinor’s Åsgard gas field, has run for over 100 000 operating hours.

300 m beneath the surface of the North Sea, approximately 175 km west of Karmøy in Norway, the company’s subsea compression system is pushing gas and condensate from a

40 |

wellhead to a semi-submersible processing platform some 40 km away. Operated by Equinor (formerly Statoil), the Åsgard project marked the world’s first deployment of a modular subsea compression technology, which emerged from a collaboration between MAN Energy Solutions and system solution provider Aker Solutions.

Having now achieved well over 100 000 hours of cumulative operation and design performance figures of 99% availability after 6 years, the two subsea compressor systems support production at a significantly lower carbon footprint than a comparable topside installation. The beneficial characteristics of operating close to the wellhead mean the subsea compression

| 41

solution is extending the reservoirs’ productive life by another 15 years. This is adding around 306 million boe to the recoverable reserves.

In 2021, Equinor awarded MAN Energy Solutions a new contract to supply an additional subsea compressor unit, which will be deployed at the actively producing field in order to extend its lifetime. The existing compression modules at Åsgard are being upgraded to accommodate a higher compression ratio and thus maintain output and enhance recovery as the pressure in the gas reservoir naturally declines.

The benefits of shifting subsea

Shifting compression technology closer to the wellhead yields significant sustainability benefits through big gains in efficiency.

The reductions in power consumption directly result in lower CO 2 emissions. Compared with a conventional topside platform, subsea compression installations can achieve emission savings of approximately 60%. The size and weight of the subsea solution is significantly smaller than a platform infrastructure, thereby reducing the requirement for materials such as steel.

In addition, improved production characteristics support enhanced performance and better economics, even at potentially marginal wells. Not only do these conditions equate to higher production and enhanced hydrocarbon recovery, but they also enable significant life extension.

With no maintenance requirements and being completely unmanned, subsea technology also eliminates a wide range of potential costs and safety concerns while coinciding with the growing trend towards de-manning of platforms and shifting control and operations to far lower cost onshore facilities.

Figure 1. Subsea HOFIM motor-compressor unit for Equinor’s Åsgard gas field.

42 | Oilfield Technology Spring 2022

However, the benefits of using subsea equipment can only be realised through extremely robust engineering and high reliability, as well as key requirements like remote operability.

At the heart of subsea compression

The core technology behind subsea compression is the high-speed compressor that was initially developed 30 years ago by MAN Energy Solutions. In use by the gas transport and storage industries for decades, HOFIM® (High-Speed Oil-Free Integrated Motor-Compressor) machines have been developed and improved to extend their capabilities across a wide range of scenarios. In the oil and gas sector, these include deployment in numerous upstream production applications as well as in subsea environments.

Hermetically sealed and oil-free, the system uses seven axes active magnetic bearings and a high-speed motor. This design means a large number of components – including the gearbox, lubrication oil system, instrumentation and valving – are not required, unlike conventional compressor trains. This improves reliability while simultaneously minimising maintenance.

The core HOFIM compressor unit is integrated into the subsea module architecture with just a few interfaces and therefore can be easily recovered if required. The single casing also reduces complexity while the footprint of the compressor system shrinks by 60%. At the same time, the weight of the compressor is reduced by around a third when compared with conventional designs. Featuring a variable frequency drive, this design offers a number of efficiency advantages during part-load operations. The low starting current also benefits those operators concerned with creating grid disturbances

when starting under a heavy load. While the Åsgard compression module features two 220 bar compressor trains, a range of capacities is available, with a power range of 3 to 18 MWe and discharge pressures of up to 303 bar (4395 psi).

Strong reliability and performance characteristics were also behind the selection of a single HOFIM unit as the export compressor at the Ivar Aasen topside platform. Pushing gas from Ivar Aasen to the Edvard Grieg platform for further processing and onward export, the compression system is the sole production asset. Clearly, any zero-redundancy strategy will have a significant impact on CAPEX. Furthermore, although the Ivar Aasen platform was designed as a manned installation, controls for the platform are now moving onshore as part of a de-manning policy by the operators. The remote operability of the HOFIM technology is a key enabler of this.

Expanding the boundaries of subsea operations

This shift to subsea technology ties in with the trend towards exploration and production in more challenging waters well over 1000 m below the surface, where the benefits of subsea operations potentially become even more substantial.

In 2021, the company was commissioned to supply five subsea compression units for the Jansz-Io Compression (J-IC) project, located around 200 km off the north-western coast of Western Australia at water depths of approximately 1400 m.

Three subsea HOFIM compressor systems will be installed into the subsea modules at the Chevron-operated field, while two more will serve as spare units. The subsea compression stations will boost gas recovery and form a key part of the installation to supply gas to the 15.6 million tpy LNG processing units of the

Gorgon project on Barrow Island. Gorgon is one of the world’s largest natural gas developments projects.

The Jansz-Io project marks an important milestone for subsea compression technology, and is the direct result of the technological developments achieved by Subsea Alliance partners Aker Solutions and MAN Energy Solutions.

Next-generation subsea compression

With the latest generation of subsea equipment becoming more standardised, simpler and smaller, HOFIM systems are also being optimised. Current designs feature a further 50% reduction in size and weight and, by reducing the number of modules needed, around 8000 t of CO2 is removed from the construction and installation phases.

Standardised and simpler designs are indicative of lower CAPEX and OPEX, while the modular approach helps to deliver predictable, repeatable quality and accelerated delivery times. The modular configuration also supports operational flexibility, allowing compressor train capacity to change as a field matures and its production characteristics evolve.

In forging long-term partnerships to achieve those essential goals, MAN Energy Solutions and Aker Solutions are advancing next-generation subsea systems. Over time, these subsea compression solutions are becoming smaller, lighter and more cost-effective with improved performance and profitability. Pioneered in Europe, this technology is now forging a path to more sustainable and efficient production for some of the deepest gas fields worldwide.

Figure 2. The installation of the world’s first subsea gas compression module at Equinor’s Åsgard gas field. Courtesy of Equinor.

Spring 2022 Oilfield Technology | 43

SMART AND SPEEDY Peter Chronis, Winters Instruments, Canada, examines the network options available to operators requiring smart instrument measurement for better pressure and temperature monitoring.

E

ffective pressure and temperature measurement of process media ensures efficiently run facilities and the production of premium products. A key component in high-quality measurement is the implementation of smart pressure and temperature transmitters, with leading edge functions, for high-speed network communication.

Historically, transmitters in industrial and process environments would rely on an analogue output variant to send pressure ratings or temperature information further upstream to a programmable logic controller (PLC) or process automation controller (PAC).

A common output type, which is very widespread, is 0 – 10 VDC. This communication type is very simple to implement, readings are very easy to take and 0 – 10 VDC input devices are mainstream and embedded in many electronic devices. However, when it comes to durability, the preferred choice amongst automation specialists is a milli-amp signal, typically 4 – 20 mA output. Again, the installation architecture is simple to implement, however its

44 |

overwhelming advantage is that it can travel long distances without causing signal degradation and is very robust against electrical noise (often induced by surrounding electric equipment).

Fieldbus networks

However, as we now consider a communications landscape that is more integrated and includes the Internet of Things (IoT), digital platforms will need to be considered for full integration of field devices. Of the many options available, the fieldbus network with the longest legacy and its open infrastructure is Modbus RS485 (Modbus protocol defines the messaging structure used in the data exchange, while RS485 defines the physical level of electrical signals and wiring between the host and the field devices). This protocol has many advantages: Very wide global acceptance with low cost of implementation.

This serial communication is very tolerant and forgiving to electrical noise.

� �

� � �

Lengthy cable runs, up to 1200 m (approximately 4000 ft).

Capacity for multiple field devices on a single rung (up to 32 nodes can be connected on one network or up to 127 devices on a multi-drop network).

Offers a fast data transmission speed, e.g. up to 10 Mbps.

Another popular fieldbus network, and the one that is most installed across the process world in fact, is HART® (Highway Addressable Remote Transducer). This is a hybrid analogue and digital open protocol that can communicate over an existing 4 – 20 mA communication platform; this feature allows the user to upgrade to a ‘smart’ protocol without the cost of rewiring. Other advantages of implementing HART include: Simplicity with programming and network set-up.

Speeding up the time for troubleshooting between identifying issues and solving them.

Real-time detection of connection problems in device and/or process.

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� � �

The use of remote diagnostics to reduce unnecessary field checks.

Improve regulatory compliance as sophisticated diagnostics increase the amount of safety integrity level (SIL) with automatic safety shutdown.

Seamless and continuous integration, allowing existing process plants to be continuously expanded.

Once the communication network has been determined, there are a plethora of application opportunities for these smart transmitters to be integrated into.

Type of communication output

The specific industry, location and ambient conditions of the installation will often dictate the type of communication output that is selected.

For newer greenfield process installations, the default network is typically HART, due to the many advantages already mentioned.

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However, installations that are often missed are those in remote areas of a region. For example, in the oil and gas market it is quite often the case that well pads, pump jacks and compression stations (to name a few) are not considered in overall networking scheme as they typically operate as decentralised systems. These installations are typically interfacing both analogue and digital signals at remote sites and communicating through remote terminal units (RTUs) by radio, telephone lines, cellular signals, microwave and satellite to a central controller, typically a Supervisory Control and Data Acquisition (SCADA) station. As these remote locations have challenging environments, with the potential for transient electrical noise and lengthy distances, the legacy network most often requested is Modbus RS485. With the cost of implementation and large number of allowable field devices, once this network is installed (especially in a remote location) it is very difficult to convince a field operator to upgrade.

Figure 1. 4 – 20mA communication with PAC.

Power consumption considerations

Further to the discussion of remote locations, upstream oil and gas facilities often generate their power through renewable energy e.g. solar, wind, or geothermal. These sources are often sufficient to power small e-houses but have limited power supply; the power consumption of all installed devices therefore needs to be carefully considered. Standard smart transmitters with 4 – 20 mA analogue signal outputs, or even the RS485 models with digital protocols, rely on large amounts of power consumption. In these types of installations, the better choice is a low voltage 1 – 5 VDC analogue output. This will ensure continuity for the remote location while adhering to the stringent and allowable power consumption requirements.

Heat exchangers

A classic application found in both commercial and process segments is a heat exchanger. A heat exchanger is a device that allows heat from a fluid (or gas) to pass to a second fluid (or gas) without the two having to mix together. This critical piece of equipment, with age or misapplication, can experience leaks through cracking or blockages and clogs due to the lack of regularly scheduled maintenance. If either of these issues arise, the heat exchange equipment will not properly perform, resulting in inferior quality product or unregulated climate control or even personal harm. The installation of a smart differential pressure transmitter will allow for proper monitoring of the inbound and outbound pressure and display any critical differences on its LCD screen, while sending the analogue or digital information further upstream to the control room for proper processing and control.

Figure 2. RS485 network.

Transmitters

Winters Instruments’ WinSMART™ family of pressure, differential pressure and temperature transmitters offer a combination of analogue and digital communications. The LY16 Series offers pressure ratings from Compound up to 14 500 psi, with all stainless steel wetted parts. The LY36 Series is the differential pressure transmitters rated for inches of water column 1450 psi. The TY52 Series is a temperature transmitter with a PT100 RTD sensor and an array of stem length options. All configurations include 4 – 20 mA, 4 – 20 mA+HART, 1 – 5 VDC or Modbus RS485 communication options, enabling connection to any PLC or PAC device. With CSA approval for hazardous locations and Intertek listing for intrinsically safe areas, WinSMARTTM can fulfil operators’ process automation requirements.

Figure 3. HART network.

Conclusion

In summary, there are a number of network communication options that are available, from the basic analogue type to the highly sophisticated digital world. An operator’s selection will depend on the existing network and hardware they already have in place, while looking ahead to determine the future requirements of their process and organisational needs.

Spring 2022 Oilfield Technology | 47

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