Oilfield Technology December 2021

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Contents 03 Comment

Issue 4 2021

Volume 14 Number 04

32 Continuous improvement wins the race Chris Gooch, Ulterra Drilling Technologies, USA, explains how incremental steps can bring large-scale changes to reliability, efficiency and economics in the drilling environment.

05 World news 10 Market recovery in the Middle East

36 Meeting the challenges of the Haynesville

Priya Walia, Rystad Energy, India, explores what’s in store for the Middle East’s oil and gas market post-pandemic.

Donya Blakney, Drilformance, USA, outlines the impact that meaningful pairing of bit design and cutter geometry can have on drilling performance in over-pressured shale plays such as the Haynesville.

16 More logging, less guesswork Rob Shoup, Justin Boltz, Matthue Ellis and Stephen Forrester, Gyrodata, USA, demonstrate how wellbore tortuosity logging can take the guesswork out of improving artificial lift equipment placement and optimising production.

40 At the sharp end Jarred Koenig and Michael Bouska, International Diamond Services, USA, present the results from applications of new PDC cutter technology in challenging drilling formations.

22 Unconventional times call for unconventional measures

44 Increasing the value of deepwater wells

Bryan Holleyman, Extract Production Services, USA, reports on a new permanent magnet electric submersible pump design created for unconventional wells and stricter ESG requirements.

Kenneth J. Kotow, Steven M. Rosenberg, Nitin M. Kulkarni and James P. Wakefield, Subsea Drive LLC, USA, explain how deepening the structural casing in the riserless section using casing drilling can lead to improved well integrity and economics.

26 Improving drilling performance through drill bit hydration

48 Subsea pipe repair in the Middle East

Duncan McAllister, Karl Rose and Mike Ott, Varel Energy Solutions, USA, and Sebastien Reboul, Varel Energy Solutions, UAE, consider the experiments and modelling used to identify the key elements of a PDC bit design centred on drill bit hydration.

Vincent Ribouleau, 3X ENGINEERING, Monaco, uses a case study from the Middle East to demonstrate how composite wrapping is transforming the pipeline repair industry.

52 Pipeline integrity insights that go deeper Michael Jefferson, Tracerco, UK, explores how pipeline inspection techniques have adapted to the challenges facing pipeline operators.

56 Overcoming difficult geomechanics in Mexico Viridiana Parra, Grupo R, Mexico, and Reinaldo Maldonado and Justin McLellan, Impact Fluid Solutions, show how drilling fluids were successfully deployed at a wellbore offshore Mexico experiencing instability and lost circulation issues.

Front cover Varel Energy Solutions’ HYDRA™ bit hydration philosophy is centered on solving problems specific to optimising PDC bit hydraulics. HYDRA enables an approach for considering all critical factors that influence performance while finding the optimal balance of features using the rig’s available hydraulic energy. Once HYDRA is paired with appropriate bit designs and other key attributes, such as VENOM™ cutters, the proven performance generated is exponential.


60 Autonomous oilfields: closer than you think Dr Helmut Schnabl, Siemens Energy, Austria, examines several ready-to-deploy technologies that can facilitate autonomous oilfield operations.

66 Back to basics Mark Niblett, Weatherford, USA, emphasises the need to return to the basics of safety in a new 2021 paradigm.

70 Protecting against tough upstream conditions M.B. Sutherland, Magid, USA, discusses the importance of safety, hydration and suitable protection equipment when working on oil rigs.

Vof reinforcement learning can help to optimise well placement and field 210x297 Oilfield Technology Hydra Cover Oct 2021 648735-03.indd 1

9/22/2021 12:34:39 PM

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

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Comment Nicholas Woodroof, Deputy Editor


So we beat on, boats against the current, borne back ceaselessly into the past.” The concluding words of F. Scott Fitzgerald’s novel The Great Gatsby seem apt at this moment. As I write, people in England are once again being advised to work from home, in response to the emergence of a new COVID-19 variant. The travel bans, lockdowns and oil price slump – the latter timing unfortunately with the Thanksgiving holiday season in the US – triggered by Omicron’s spread have left many casting their mind back to the onset of the pandemic, rather than forwards as might be expected at this time of year. What (limited) evidence about Omicron’s transmissibility there is makes it difficult to believe 2022 will bring a return to normality. For now, at least, oil prices have stabilised. In its latest short-term outlook, the US Energy Information Administration (EIA) has predicted an average price of US$71/bbl for Brent crude in 2Q22, which represents a decline from its current price but still a far cry from the nadir of April 2020. No prizes for guessing that the report comes with a sizeable dose of COVID-related caveats though. 1 With the COP26 climate change summit that took place in Glasgow having concluded a few weeks ago, now seems like a good moment to assess its impact. Oil and gas escaped the severe scrutiny given to coal, although an agreement on the “phase-out of inefficient fuel subsidies” indicates the direction of travel for those countries, now in the majority, that have committed to net zero. The vagueness of this phrase (as Wood Mackenzie put it, what exactly counts as a subsidy is undefined) should not be used as an excuse for oil and gas producers to prevaricate on decarbonisation.2 True, significant investment is needed in E&P operations following the CAPEX cuts of the past 18 months, but it is also needed in the clean technologies that the industry has the expertise and resources to develop and deliver at the scale required. A 2022 marked by inertia would risk alienating investors increasingly keen to see emissions reductions that help restrict global warming to 1.5˚C by 2050 and represent a huge missed opportunity to adapt. Away from the hurly-burly of markets and international diplomacy, oilfield service companies continue to innovate and evolve their offerings, as evidenced by the articles within this issue. Our cover story from Varel Energy Solutions takes readers through the methodology behind the company’s drill bit hydration approach, and how this has been successfully applied in runs in the US and Oman. Elsewhere, readers can enjoy features covering pipeline integrity, autonomous oilfields and health and safety. I’ll finish by thanking all of our contributors, advertisers and readers this year, and on behalf of the Oilfield Technology team wish you a happy and healthy new year.

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1. US Energy Information Administration, ‘December Short-Term Energy Outlook’ (7 December 2021), https://www.eia.gov/outlooks/steo/report/ 2. Wood Mackenzie, ‘What COP26 means for energy and natural resources’ (1 December 2021), https://www.woodmac.com/news/opinion/what-cop26-means-for-energy-and-natural-resources/

Issue 4 2021 Oilfield Technology | 3

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World news

Issue 4 2021

ExxonMobil aiming for net zero emissions in Permian Basin operations by 2030 ExxonMobil is aiming for net zero greenhouse gas emissions from operated assets in the US Permian Basin by 2030, accelerating and expanding its emission reduction plans for unconventional operations in New Mexico and Texas. The plans are part of an effort to reduce upstream greenhouse gas emissions intensity by 40 – 50% by 2030, compared to 2016 levels. The greenhouse gas emission reduction efforts in the Permian will be supported by electrifying operations, continuing investments in methane mitigation and detection technology, eliminating routine flaring, upgrading equipment and employing emissions offset technology, which may include nature-based solutions. The company plans to electrify its operations with low-carbon power, which may include wind, solar, hydrogen, natural gas with carbon capture and storage, or other emerging technologies. ExxonMobil plans to expand its methane detection programmes utilising satellite surveillance and a network of ground-based sensors for continuous monitoring, and aerial flyovers that identify leaks for rapid repairs. The company plans to eliminate all routine flaring in the Permian by year-end 2022, in support of the World Bank’s Zero Routine Flaring initiative.

TotalEnergies starts up CLOV phase 2

Maersk Drilling awarded one-well contract by OMV

TotalEnergies, operator of Block 17 in Angola, together with the Angolan National Oil, Gas and Biofuels Agency (ANPG) has announced the start of production of CLOV Phase 2, a project connected to the existing CLOV FPSO. The tie-back project will reach a production of 40 000 boe/d in mid-2022. Located about 140 km from the Angolan coast, in water depths from 1100 to 1400 m, the CLOV Phase 2 resources are estimated at around 55 million boe. Launched in 2018, this project was carried out within budget and planned execution duration, despite the challenges associated with the Covid-19 pandemic. Block 17 is operated by TotalEnergies with a 38% stake, alongside Equinor (22.16%), ExxonMobil (19%), BP Exploration Angola Ltd. (15.84%) and Sonangol P&P (5%). The Contractor Group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor and CLOV.

Maersk Drilling has secured a one-well contract with OMV (Norge) AS, which will employ the low-emission jack-up rig Maersk Intrepid to drill a high-pressure, high-temperature exploration well in the Oswig prospect in Block 30/5C of the Northern North Sea basin offshore Norway. The contract is expected to commence in mid-2022, and Maersk Drilling and OMV (Norge) AS are in discussions to add additional services to the scope. The contract includes a one-well option to drill the Eirik exploration well. The contract with OMV (Norge) AS contains an emission reduction bonus scheme based on rewarding CO 2 emission reductions in addition to operational performance bonuses. Maersk Intrepid is an ultra-harsh environment CJ70 XLE jack-up rig, designed for year-round operations in the North Sea and featuring hybrid, low-emission upgrades.

In brief Saudi Arabia Saudi Aramco has awarded in-Kingdom and out-of-Kingdom contracts to extend Worley’s services for Saudi Aramco’s offshore Maintain Potential Program. Under the contracts, Worley will continue to provide project management, engineering, design, fabrication and installation supervision for Saudi Aramco’s portfolio of offshore projects. The term of the extension is 3 years and the services will be executed by Worley’s Al-Khobar and Houston offices.

Brazil PGS is scheduled to start a 4D acquisition survey for Petrobras over the Roncador and Albacora Leste fields offshore Brazil in 2Q22. Acquisition is expected to complete in 3Q22. The contract was awarded earlier and is already included in the company’s reported order book.

UK Maersk Drilling and Petrogas North Sea Ltd. have agreed to exercise a previously agreed exclusive option to employ the harsh-environment jack-up rig Maersk Resilient to drill an appraisal well at the Birgitta field in the UK North Sea. The contract is expected to commence at the end of 2021, in direct continuation of the rig’s current work scope. The contract has an estimated duration of 60 days and a value of approximately US$5.4 million. Maersk Resilient is a 350 ft, Gusto-engineered MSC CJ 50 high-efficiency jack-up rig which was delivered in 2008. It is currently operating in the UK sector of the North Sea for NAM.

Issue 4 2021 Oilfield Technology | 5

World news

Issue 4 2021

Diary dates 31 January – 2 February 2022 European Gas Conference

Vienna, Austria energycouncil.com/event-events/ european-gas-conference/

1 – 4 February 2022 SPE Offshore Europe

Aberdeen, Scotland offshore-europe.co.uk/en-gb.html

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

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

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 ÌÌStena Don drilling rig begins

mobilisation to Anchois gas field

ÌÌOil Search receives shareholder approval for buyout by Santos

ÌÌWinners named for North Sea electrification competition

ÌÌProduction begins from Columbus field To read these articles in full and for more event listings go to:


6 | Oilfield Technology Issue 4 2021

Chevron announces 2022 exploratory budget

Equinor sells stake in Corrib gas project

Chevron has announced a 2022 organic capital and exploratory spending programme of US$15 billion. Approximately US$8 billion is allocated to currently producing assets, including about US$3 billion for Permian Basin unconventional development and approximately US$1.5 billion for other shale and tight assets worldwide. Additionally, US$3 billion of the upstream programme is planned for major capital projects underway, of which about US$2 billion is associated with the Future Growth Project and Wellhead Pressure Management Project (FGP/WPMP) at the Tengiz field in Kazakhstan. Finally, approximately US$1.5 billion is allocated to exploration, early-stage development projects, midstream activities and carbon reduction opportunities.

Equinor has entered into an agreement with Vermilion Energy Inc. for the sale of the company’s non-operated equity position in the Corrib gas project in Ireland. The companies have agreed a consideration of US$434 million, before closing adjustment, with an effective date set at 1 January 2022. Equinor owns 36.5% of the Corrib project, alongside Vermilion (the operator with 20%) and Nephin Energy (43.5%). The Corrib field started production in 2015 and is located 83 km off Ireland’s northwest coast in water depths of almost 350 m. The sale of Corrib means that Equinor will no longer have an active business presence in Ireland, after also deciding to withdraw from an early phase offshore wind project in the country.

Proserv and Trendsetter Engineering pen MoU Proserv Controls and Trendsetter Engineering have signed a Memorandum of Understanding (MoU) relating to the joint marketing and supply of integrated subsea hardware and controls. The mutually beneficial arrangement will see Proserv and Trendsetter utilise their combined expertise and core strengths to develop cost-effective, high-quality solutions for their clients, across both brownfield and greenfield projects. The new MoU will mean that Proserv will now be able to incorporate its energy production control systems and related services, designed to improve the reliability, integrity and performance of critical infrastructure, alongside Trendsetter’s pressure protection systems, including its high-integrity pressure protection system (HIPPS), connection systems and manifolds. It is anticipated that the new MoU will enable the parties to extend their scope of offering for their customers, and to take their proposition into new global markets. The collaboration has already borne fruit with the two parties combining their expertise on the expansion of the Shenzi North field on behalf of BHP in the Gulf of Mexico. Trendsetter will deliver its SIL3 rated HIPPS module, equipped with Proserv’s subsea controls technology. This will enable BHP to use its existing flowlines, risers and topside facilities, significantly enhancing the cost-effectiveness of the tieback to the Shenzi tension leg platform (TLP). One key component of the MoU’s value proposition sees the two parties harnessing the coexistence and backwards compatibility capabilities of Proserv’s subsea electronics technology to supply and retrofit HIPPS and manifold mounted controls on existing systems.

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World news 88 Energy selects location for Merlin-2 appraisal well 88 Energy has announced that the location for the Merlin-2 well on Alaska’s North Slope has now been selected, from three initially permitted locations. The Merlin-2 well location, scheduled for drilling in February 2022 using the recently contracted Arctic Fox rig, is located east and downdip of the successful Merlin-1 well. This location is expected to encounter thicker reservoir sections and higher permeability/porosity sands. The Merlin-2 appraisal well is planned for a total depth of 8000 ft, and is targeting 652 million bbl of oil in the highly prospective N18, N19 and N20 targets that were encountered in the successful Merlin-1 well (drilled in March 2021 to a depth of 5267 ft), which demonstrated the presence of oil in these multiple stacked sequences in the Brookian Nanushuk Formation. The remaining two locations permitted, together with the permitted Harrier-1 location, can be drilled in future years as part of an extended drilling programme to assess the full potential of the Project Peregrine acreage. A production testing programme for the Merlin-2 well has been designed and will be on standby during initial wellsite operations. The production test is contingent upon the wireline programme results, in particular the MDT results, as well as government approvals. The programme and length of the test will be subject to operational, funding and weather window considerations. Permitting and planning for the Merlin-2 well remains on track for scheduled spud in February 2022.

Issue 4 2021

Expro wins subsea well contracts Expro has secured subsea well access contracts in Malaysia and Australia worth in excess of US$50 million. In Australia, Expro has been awarded a contract for the abandonment of 18 subsea wells and the removal of open water production trees. Also in Australia, the company has been commissioned to deliver an integrated programme for a new subsea development. In Malaysia, Expro has been awarded a contract for the provision of large bore electro hydraulic subsea landing string equipment for a new subsea deepwater campaign. Also in Malaysia, Shell has awarded Expro a contract for the provision of a subsea landing string integrated package for the Gumusut-Kakap deepwater field.

Neptune Energy awards Maersk decommissioning contract

Valaris contracted to drill exploration well offshore Australia

United Oil & Gas awarded extension to Jamaica licence

Neptune Energy has awarded a decommissioning contract to Maersk Supply Service (MSS) for the Juliet field in the UK Southern North Sea. Piping spools and umbilicals will be removed using the Utility ROV Services system (UTROV), a remotely-operated tool carrier equipped with multiple attachments for the recovery of subsea equipment, reducing the necessity for multiple vessels and equipment providers to carry out the complex work. The UTROV system will be deployed from the Maersk Forza Subsea Support Vessel. The Juliet facilities comprise two subsea wells tied back to the Pickerill ‘A’ Platform, which is owned and operated by Perenco (PUK). The subsea assets were installed in 2013. Production ceased in 2017 and formal cessation of production was approved in December 2018 by the OGA. The decommissioning work will be carried out in early 2022.

Western Gas has executed a formal contract with Valaris for the MS-1 semi-submersible rig to drill the Sasanof-1 exploration well. The Sasanof-1 exploration well is in permit WA-519-P in Commonwealth waters about 207 km northwest of Onslow, Western Australia. Drilling is scheduled to commence in March/April 2022 following the rig relocating from nearby activities on the North West Shelf. ERC Equipoise Ltd. (ERCE) has determined Sasanof has an estimated 2U Prospective Resource of 7.2 trillion ft 3 of gas and 176 million bbl of condensate (P50), with a 32% chance of success. The high case 3U Prospective Resource estimate is for 17.8 trillion ft 3 of gas and 449 million bbl of condensate (P10). Sasanof-1 will be a vertical well and drilled to a total depth of approximately 2500 m in 1070 m of water. Drilling costs are estimated at US$20 – 25 million.

United Oil & Gas has announced that the request for a 2-year extension for the Walton Morant Licence, Jamaica, has been granted by the Jamaican Cabinet. Pending completion of the approval process, the licence will run to 31 January 2024. An independent evaluation by Gaffney Cline & Associates, announced by the company in December 2020, of 11 high graded leads and prospects indicated the potential for a combined estimated 2.4 billion bbl mean prospective resources. United Oil & Gas started a formal farm-out process for the Walton Morant Licence earlier this year. The company is seeking a strategic drilling partner(s) with a view to drilling the primary 3D seismic defined Colibri prospect, which is estimated to hold mean prospective resources of 406 million bbl. United Oil & Gas holds and operates a 100% equity interest in the Walton Morant Licence.

8 | Oilfield Technology Issue 4 2021




MARKET RECOVERY IN THE MIDDLE EAST Priya Walia, Rystad Energy, India, explores what’s in store for the Middle East’s oil and gas market post-pandemic.

10 |


lobal oil and gas markets are accustomed to the highs and lows of economic cycles, but the slump triggered by the COVID-19 pandemic was unprecedented and hit all parts of the oil and gas supply chain. Fuel consumption and oil demand plummeted, prompting the OPEC+ nations to reduce production and global upstream operators to defer projects worth US$170 billion from 2020, and US$135 billion from 2021. Now that oil prices and activity are picking up again, the projects that were delayed in 2020 and 2021 will be critical to the recovery. Global upstream projects with a greenfield investment value of US$545 billion are expected to be sanctioned between 2021 and 2023. The Middle East, with projects worth US$110 billion aimed at developing 38 billion boe, will be crucial to this global recovery phase (Figure 1). This article will take a closer look at the status of major projects in the region scheduled over the next couple of years. The Middle East has re-emerged as one of the most appealing regions for suppliers, with Middle Eastern nations such as Qatar, the United Arab Emirates (UAE) and Saudi Arabia keen to boost their oil and gas production capacity. The rebound in oil prices is also

expected to spur more sanctioning elsewhere in the region, most notably in Turkey, Oman, Iraq and Iran (Figure 2).


Qatar has maintained its crude oil and gas production levels, even though it has been narrowly overtaken by Australia as the world’s top exporter of LNG. The country is further developing its giant North Field by kicking off projects such as Qatargas’s North Field Expansion (NFE) to boost its gas output from 158 billion m3 in 2021 to a target of 220 billion m3 in 2030. Qatar aims to lift its LNG capacity to 126 million tpy from the current 77 million tpy through two phases of the NFE project (Figure 3). The recently sanctioned first phase includes four new liquefaction trains to raise the capacity to 110 million tpy, with the remaining capacity coming from the two-train second phase, which is currently at the FEED stage. Key facility work for the first phase of NFE is divided into four main packages: � Package 1 for building the four liquefaction trains was awarded to a consortium of Chiyoda and France’s TechnipEnergies in February 2021.

| 11

`` Package 2 for LNG storage tanks, associated pipelines and expansion of loading facilities went to Samsung C&T in March 2021. `` Package 3 for pipelines and utility facilities at the terminal was awarded to Tecnicas Reunidas in August 2021.

Figure 1. Global final investment decisions 2021 – 2023 by region.

`` Package 4 covers the sulfur-handling facilities. Qatar Petroleum has also invited ExxonMobil, Chevron and ConocoPhillips to form a joint venture for the NFE project. Qatar Petroleum is pushing ahead with the second phase of NFE to take advantage of the field’s low breakeven prices and is currently finishing up the pre-qualification process for the initial tenders for offshore jackets. Rystad Energy expects the second phase to get approval in 2023. In addition to NFE, Qatar has also announced further phases of the North Field Sustainability project, worth over US$6 billion, with an award due later in 2021. These developments aim to sustain current gas production levels from the North Field. The first two phases, worth more than US$3 billion, were awarded in 2019 and 2021 respectively. Furthermore, Rystad Energy anticipates a greenfield investment of US$1.7 billion before 2023 in new oil projects, including Idd El Shargi phase V and the third phase of the Gallaf development. The latter project is aimed at maintaining output capacity from the Al Shaheen oilfield at 300 000 bpd at a cost of US$1.37 billion, and was kicked off in July 2021 by operator North Oil Co. The US$340 million first phase of Gallaf was awarded in 2018, followed by the US$240 million second phase the year after. Apart from Gallaf, Rystad Energy estimates that the other developments are scheduled for between 2022 and 2023.


Figure 2. Middle East greenfield investments by country and approval year, 2021 – 2025.

Figure 3. Qatar LNG production outlook. 12 | Oilfield Technology Issue 4 2021

The UAE aims to boost its oil and gas output and has scheduled projects worth approximately US$23 billion in greenfield investments from 2020 – 2023 (Figure 4). Approximately 85% of this investment is planned for projects involving sour oil and gas fields. The Upper Zakum Phase 2 expansion and the Lower Zakum long-term development projects (LTDP) are two of the most significant sour oil field projects. The two projects are worth US$6.5 billion and US$2.8 billion respectively, and are expected to be approved in 2023. Among the biggest sour gas condensate field projects are Dalma (US$1.6 billion) and Umm Shaif gas cap (US$1.8 billion). Dalma is approved in 2021; Umm Shaif is projected to be approved next year, and the long-delayed Hail & Ghasha, worth US$12 billion, with approval currently expected in 2023. Hail & Ghasha is the largest sour gas project being carried out in the Middle East, with resources of 1.3 billion boe. All of these gas projects assume an oil price range of US$55 – US$80/bbl. Even with a breakeven gas price of US$5 – US$6/thousand ft3, a steady pricing environment has opened the path for these projects to be scheduled from 2021 – 2023. However, as Abu Dhabi’s national oil company, ADNOC, is pushing ahead with a tender for revised FEED for Hail & Ghasha to reduce costs, the project could face further delays in the engineering, procurement and construction (EPC) stages and approval timeline. The UAE’s greenfield investment total in 2021 will be nearly US$4.3 billion, mostly comprised of the Shah sour gas debottlenecking project, the Al Dabbiya and

1 . 877 . PDC . DRILL


Belbazem oil developments and the Jebel Ali gas project. ADNOC seeks long-term collaboration with contractors to realise capital and efficiency gains and, as a result, there is a rise in joint FEED-EPC agreements being witnessed. ADNOC has inked accords totalling US$204.4 million with nearly 15 international engineering contractors

for concept and FEED projects, which will support the company in achieving its 2030 goals. During the first phase of the award, in August 2021, ADNOC signed agreements totalling US$1 billion with eight engineering contractors for planned FEED work over a 5-year period, with an option for a 2-year extension.

Saudi Arabia

Figure 4. UAE greenfield investments from 2020 – 2023 and new supply additions.

The key development in Saudi Arabia is the Saudi Aramco-operated Zuluf oilfield – a US$10 billion project aimed at expanding the country’s oil-processing capacity by 600 000 bpd (Figures 5 and 6). After garnering contractor interest in 2019, Saudi Aramco was expected to begin the tendering process in March 2020, but this has been postponed again. Rystad Energy now expects project approval will be moved to 2023, with potential field start-up in 2027. Another significant project is the Jafurah tight gas field, announced by the Saudi government in 2020, with a total price tag of approximately US$110 billion. The state operator cancelled all key tenders during 2020’s price slump in a bid to reduce costs by revisiting the work scope to use existing facilities. International onshore contractors are vying for numerous EPC packages under the umbrella of the Jafurah unconventional gas development project. Bids for up to five EPC packages have just been filed with Saudi Aramco, which expects to award contracts for the mega-project in 2021.


Iraq intends to increase domestic oil output while decreasing its reliance on imported gas. Most of the projects seek to raise oil and gas output from Iraq’s main fields. Rystad Energy forecasts a total investment of US$5.5 billion in greenfield projects from 2020 through to 2023, evenly split between oil and gas-condensate projects. Among oil projects, prominent developments include the Ratawi oilfield redevelopment project and early development of the Eridu field, both with approval estimated in 2023. The key gas-capturing projects at West Qurna-2 phase I and Majnoon phase I are also in the pipeline to be approved around 2023. Figure 5. Saudi Arabia oil supply additions from new projects by approval year, 2020 – 2025.

Figure 6. Production and economics outlook from Zuluf Expansion Project.

14 | Oilfield Technology Issue 4 2021


Despite US sanctions, Iran aims to enhance its oil export capacity. Iran’s oil exports have dropped after the US reimposed sanctions 3 years ago as former President Donald Trump abandoned the 2015 nuclear deal between Iran and leading world powers. However, in early 2021, Iran and other countries started talks to resurrect the nuclear accord and have had several rounds of negotiations that have yet to be concluded. Iran is confident it will be able to recover to pre-sanction oil output levels if US sanctions are eased. Iran has scheduled projects valued at approximately US$7 billion in greenfield investments from 2020 through 2023. Almost 80% of this investment will go into sour oil fields, with the remaining 20% going towards gas field projects. The most significant oil project is the redevelopment of the Azadegan South field, which is expected to be approved in 2023. Among gas projects, Farzad B phase 1 (x-Farsi) was approved in May 2021 and is estimated to hold original reserves of

approximately 800 million boe. Rystad Energy estimates the field’s gas production plateau to be approximately 9.34 billion m3/y. Rystad Energy expects Iran’s greenfield investment to total more than US$3 billion in 2021, led by the Farzad B phase 1 (x-Farsi) project, the Ahvaz development and the Sepehr/Jufair phase 1 oilfield redevelopment.


Oman is continuously working to boost its oil and gas capacity, using both new development projects and considerable work on enhanced oil recovery (EOR) technologies to squeeze all economically viable drops of hydrocarbon from its fields and reserves. National player Petroleum Development Oman (PDO) has become a global pioneer in EOR due to its mature asset base in Block 6 and the complexity and challenging nature of Oman’s geology. Thermal, chemical and miscible high-pressure gas injection are the three primary EOR technologies now in use. PDO expects that by 2030 around 36% of its production will come from EOR projects. Among new developments, Rystad Energy forecasts a total of US$930 million in greenfield investments between 2020 and 2023, almost 90% of which will be oilfield projects (Figure 7). Bisat stations B and C are the most significant, with approval dates in 2020 and 2021 respectively.

the foundations of the Middle East’s oil and gas sector. As the market recovery continues, Rystad anticipate several significant E&P and EPC projects across the region will get the go-ahead – QatarGas Trains 8-11, for example, is the largest project greenlighted internationally this year. Even as the shift to sustainable energy gains traction and peak oil demand approaches, the Middle East’s economies will remain inextricably linked to the oil and gas sector.

Figure 7. Oman’s production and economics outlook.


Turkey strives to enhance its oil and gas production output and has projects worth more than US$3.5 billion in greenfield investments planned from 2020 – 2023. The nation’s Sakarya gas project in the Black Sea is the most significant project under the operatorship of state-owned Turkish Petroleum (TPAO). Sakarya was discovered in 2020 and is projected to have around 400 million boe of original reserves. In addition to engineering and procurement, TPAO is conducting an appraisal and exploratory drilling programme to firm up Sakarya’s resources and locate additional gas fields. The field is projected to have a substantial impact on Turkey’s imports of gas from Russia and the Caspian area. The project was approved in September, and Rystad Energy estimates more than US$1.5 billion in greenfield investments from 2021 – 2023.

Figure 8. EPCI contract awards in the Middle East.

EPCI contract awards in the Middle East

As operators prepare to meet aggressive energy targets, mega-projects are returning to the market, providing EPC vendors with an opportunity to reload their order books (Figure 8). The Middle East’s revenue contribution to EPC firms has expanded considerably over the years, with 40% of 2020 revenues for key engineering, procurement, construction and installation (EPCI) players coming from the region, particularly Saudi Arabia, the UAE and Qatar (Figure 9). A similar pattern is expected to continue in the future, with the Middle East accounting for a sizeable share of backlogs and bid pipelines.


The COVID-19 pandemic slashed crude oil consumption and hit the economies of oil-exporting countries in the Gulf region, but it did not damage

Figure 9. Revenue contribution from the Middle East for major EPCI players. Issue 4 2021 Oilfield Technology | 15


Rob Shoup, Justin Boltz, Matthue Ellis and Stephen Forrester, Gyrodata, USA, demonstrate how wellbore tortuosity logging can take the guesswork out of improving artificial lift equipment placement and optimising production.


ith crude oil prices settling in the high US$60/bbl range at the time of writing, operators in all parts of the world are feeling the pressure to get more value out of their wells and deliver a better return to investors. In past cycles, it was typical to look at times of higher commodity prices as an opportunity to ramp up drilling and production; fortunately, this behaviour has been curtailed with continued calls for financial discipline and the realities of supply and demand. What is more

important than ever now, and what will certainly define how well companies do moving forward, is the ability to get more out of existing wells rather than constantly drilling new ones. Many innovations on the equipment and technology side have aimed to address this need in some form or fashion, but more focus must be placed on wellbore quality if the industry is to advance. The MicroGuide wellbore tortuosity logging system, developed by Gyrodata, is one answer for those operators seeking to better

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place their downhole production equipment and optimise production from their reservoirs.


MicroGuide generates wellbore tortuosity logs in conjunction with a gyroscopic surveying tool, or another service that provides comparable data. The system defines reference lines for the wellbore path based on survey data, and determines displacements of the wellbore path from the reference lines. Through a series of calculations based on this information, the wellbore shape can be represented and visualised in 3D, allowing

an operator to make critical decisions on well development and placement for artificial lift and other equipment in line with areas of low tortuosity. Wellbore tortuosity has a significant impact on the design and installation of artificial lift equipment. The well path and tortuosity is commonly determined from data based on measurement while drilling (MWD) technology and stationary directional surveys at stand-length intervals. By collecting high-density, high-resolution data at 1 ft log intervals, MicroGuide technology reveals areas of high side loading or side force and high friction that would be otherwise invisible. Making decisions on optimised artificial lift system placement with previous solutions involved so many assumptions and so much guesswork that it ultimately resulted in a substantial number of unpredicted failures.

Case studies Bakken Shale

Figure 1. The data from the wellbore tortuosity logs revealed tortuosity spikes in several areas that were undetected with MWD equipment. In addition, the system highlighted an area of helical buckling from 8700 to 10 560 ft.

Figure 2. The wellbore tortuosity analysis revealed elevated side force from 2400 to 6500 ft that was not clear in the MWD data, including an extreme spike at 4000 ft.

Figure 3. The MWD survey had an erroneous azimuth reading at approximately 3220 ft measured depth, causing a spike in calculated dogleg severity when no such spike was present in the well.

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An operator in the Bakken Shale, US, was experiencing repeated issues with rod failures in one of their wells. Though there were several areas of concern throughout the well, the primary trouble spot was in the last 1900 ft, where repeated failures were causing the project to exceed authorisation for expenditure (AFE). To better understand the issue and identify a means of rectifying it, the operator decided to run wellbore tortuosity logs to obtain information on true downhole conditions. The MicroGuide analysis revealed several spikes in side force against the tubing that were not previously visible with MWD data (Figure 1). The analysis showed that the casing was helically buckled from 8700 to 10 560 ft, which was causing the increased side force throughout the section as well as the issue with rods parting. Without the wellbore tortuosity logs, the operator would have had inadequate data on the bottomhole to properly make decisions on the best artificial lift method. In another project in the Bakken, an operator was having issues with their electrical submersible pumps (ESPs) prematurely failing. After trying to determine a better downhole placement based on the existing MWD survey data, the operator realised that they did not have enough information to make this decision. As such, they requested that Gyrodata run its wellbore tortuosity logs to obtain more detailed information on downhole conditions and wellbore geometry. The MicroGuide logs revealed previously unseen tortuosity from approximately 2400 to 6500 ft (Figure 2), allowing the operator to place the ESP in an optimised location without risk of premature failure. The data also showed that in the upper part of the

well there was an erroneous azimuth reading on the MWD survey (Figure 3) that caused an incorrect spike in dogleg severity. Had the operator used this information, they would have incorporated specialised equipment at extra cost to traverse the section, even though there was no reason to do so. To ensure that the operator could quickly shift from ESP to rod lift when production declined, they were also provided with a modelled rod guide analysis.

had no notable tortuosity or excessive bending – but based on completion design, this depth would not be optimal to achieve the highest possible production level. Gyrodata recommended a deeper set depth at 7650 ft (Figure 4) to reach higher production output, noting two areas of significant tortuosity at 7135 and 7535 ft that would make traversing the pump to the new depth difficult. In addition, there was an area at 7557 ft where a 4˚ bend would necessitate Permian Basin cable clamps to pass the pump through. This would have been An operator in the Permian Basin, US, drilled a well and, after impossible to determine with typical MWD data and dogleg deciding to put the well on an ESP for production, determined severity information; significant equipment damage would have a set depth for the pump with the limited information they had. occured had the operator proceeded as normal. The operator and ESP provider intended to place the pump at In another project in the Permian, an operator drilled a a shallower depth – potentially sacrificing production – due to well and used a gyro tool from another company for wellbore their inability to determine a deeper placement with standard surveying. When preparing to put the well on rod lift for MWD data. To help the operator understand true downhole production, the operator requested that Gyrodata perform conditions and place the pump where production would be wellbore tortuosity logging to ensure the accuracy of the existing optimised, Gyrodata performed a comprehensive wellbore gyro surveys and highlight any discrepancies with the placement tortuosity analysis. of the wellbore and tortuosity severity throughout the well. The MicroGuide data revealed that the first 5000 ft of the well The wellbore tortuosity analysis showed that the well was were without tortuosity, but that immediately thereafter there straight down to the kickoff point and that were was no bending were several bends of approximately 1.7˚ each. The proposed down to approximately 4370 ft. The original survey data from ESP set depth of 6958 ft was proven acceptable – as the location the previous gyro provider had more than a dozen incorrect azimuth readings (Figure 5, top), the use of which would have led to the operator taking a costly and unnecessary approach to placing the rod guides. The data also showed a significant variance in tortuosity versus the previous gyro surveys, with the MicroGuide logs revealing incorrect tortuosity spikes in every instance (Figure 5, bottom). With regards to improving wellbore placement for reservoir access, Gyrodata found that there was a lateral discrepancy of 27 ft compared to what the original surveys had stated. In other words, the hole was 27 ft to the north of where the operator thought it was. Such variances, even when small, can have a large effect on reservoir access and Figure 4. At the new set depth of 7650 ft, there were no wellbore quality issues that would impact the production levels. production capability of the pump, and the deeper location allowed greater reservoir access.


Figure 5. The azimuth data from gyro surveys, shown in grey, gave false appearance of tortuosity in the well (top). The analysis showed that the side force measurement calculated with the previous gyro was incorrect. Had the operator used this information they could have wrongly implemented specialised tools to place the production equipment (bottom).

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As the industry trudges through the mire of ongoing pandemic-related troubles, there is little doubt that operators will continue to be asked to do more with less. When it comes to production, achieving the best possible output with the least risk is paramount. Looking at wellbore quality issues and challenges with downhole production equipment placement reveals that there is no substitute for having relevant data presented in a clear, understandable way. By providing operators with clarity on where their ESP or rod lift system goes, artificial lift failures and low production levels will hopefully become things of the past.

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UNCONVENTIONAL TIMES CALL FOR UNCONVENTIONAL MEASURES Bryan Holleyman, Extract Production Services, USA, reports on a new permanent magnet electric submersible pump design created for unconventional wells and stricter ESG requirements.


ince the invention of the electric submersible pump (ESP) in 1918, this pump design has been a bedrock of oil production. But, other than some tweaks in design and materials, it has changed little in about 100 years. For a long time this was acceptable. In conventional wells, decline curves were long and slow, meaning one pump size could work well for years. Wellbore casing remained at 5 1/2 in. – 17 lb/ft, giving the 4.56 in. outer diameter (OD) ESPs plenty of room to operate. And when the times themselves were conventional,

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there were few concerns about carbon footprints involved in electricity use or steel production for a large piece of equipment. But the rise of unconventional wells since the early 2000s has created challenges for the standard design. Decline curves that drop precipitously within 2 years require more frequent pump resizing, as standard ESPs have a narrow operating range. With longer laterals and higher frac pressures requiring thicker, heavier casing too, conventional ESPs began to face efficiency

challenges, as they were required to provide more horsepower in smaller spaces. Longer and more expensive laterals and completions have also stretched completion budgets at the same time that investment money has tightened. This has led producers to seek ways to obtain faster returns on their investments by boosting initial production ahead of steep decline curves. More powerful and efficient ESPs could help achieve these return on investment (ROI) goals. Furthermore, gas locking due to low-functioning gas separators has always been the bane of ESPs, wasting energy and overheating pumps and motors to the point of damage or destruction. Finally, increasing awareness and understanding of climate change and environment, social and governance (ESG) issues since 2019 – 2020 has required the oil and gas industry to find ways to reduce its carbon footprint from the drill pipe all the way to the tail pipe. A substantially new ESP design became a glaring need.

Something needed to change

During the downturn of 2015 – 2016, David Zachariah (now Extract’s Chief Technology Officer) began to see producers move to survival mode. They were cutting drilling costs by drilling fewer wells, but those they did drill had longer laterals to expose the site to more producing rock. Those longer laterals required higher frac pressures. To accommodate those pressures they thickened casing walls, using 5.5 in. 20 lb/ft and 23 lb/ft types instead of the older 17 lb/ft variety. Since the OD remained at 5.5 in., making the casing heavier had the effect of reducing its inner diameter (ID). This, in turn, required ESPs to be reduced to 3.75 in. diameter instead of the previous 4.56 in. At the same time, the longer laterals required more horsepower to increase the flow from the greater exposure to the producing zone. The maximum power that can be squeezed from a 3.75 in. motor is approximately 108 hp – significantly less than the 260 hp available from the 4.56 in. motor. Up to three of the slimline 3.75 in. motors can

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be connected in tandem in order to reach 324 hp. As many as two 4.56 in. motors can be connected to reach approximately 500 hp.

Something had to give

Some companies that tried shaving down the housing and back iron of a 4.56 in. induction motor experienced more loss of speed through slippage. This required more stages to achieve the needed results, which added expense, used more steel and ultimately required more horsepower. In searching for a different solution, Zachariah and his associates landed on a modular permanent magnet motor design that would create more than 400 hp in the smaller 3.75 in. size. With this development, a decision was made to start Extract Production. The company’s first step was to manufacture and sell standard ESPs to create cash flow for developing the high-speed permanent magnet motor now known as SpeedFreq. After 3 years of development the first field trials were rolled out in the autumn of 2019.

Basic design features

Figure 1. The SpeedFreq’s smaller size means it can be installed quickly


The use of permanent magnets allows the SpeedFreq system to deliver up to 10 000 rpm and 400 hp from a package that has a diameter of 3.75 in. and is less than 50 ft in length, as opposed to 3500 rpm from 170+ ft for standard ESPs. With a bottom speed of 3000 rpm, it can accommodate greater decline curves without the need for re-sizing. This short length has the effect of better accommodating wellbore variations in deeper wells. Other advancements include: Uses 20 – 35% less power than induction ESPs. Arrives onsite ready to install rather than in multiple sections, saving time.


Figure 2. Basing the SpeedFreq motor on permanent magnets allows the unit to deliver more power with less equipment than is required by standard ESPs.

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Gas separator operates at 75% efficiency and up to 95% in some cases. This means less gas locking, less opportunity for pump cavitation and damage and longer run-life.

Most importantly, the higher horsepower and high-speed capability helps operators realise greater early production returns when bottomhole pressures begin to drop.

ESG design

Reducing the carbon footprint of production is becoming more important – and more possible as research continues. The system reduces this type of carbon footprint in the following ways: Uses 75% less steel than equivalent slimline induction ESP units. Steel Figure 3. Power use comparison: SpeedFreq versus induction ESP. production accounts for 7 – 9% of greenhouse gas emissions, according to the World Steel Association.1 Smaller size and fewer components means less fuel Table 1. Power usage comparison expended in logistics and inventory handling – lower tailpipe Average KW emissions from fewer miles/trips (Figure 1). Unit Average bpd usage Uses up to 35% less electricity per barrel than standard Induction 200 3194 ESPs.



Case study: energy consumption reduction

Basing the SpeedFreq motor on permanent magnets allows the unit to deliver more power with much less equipment than is required by standard ESPs (Figure 2). A conventional ESP’s equipment includes six pumps, two gas handlers/separators, two protectors and two or more motors. On the other hand, the SpeedFreq includes a single pump and gas separator, two seals and one modular motor capable of up to 400 hp at 10 000 rpm. In 2020 a customer in Texas’s Permian Basin installed the unit alongside a conventional induction unit in a well on the same pad, then compared power usage between the two. For starters, the unit was installed 4.5 hours faster than the conventional pump. Because the wells were in the same formation, on the same pad and of similar depths and flow rates, the test was expected to provide useful information. Figure 3 shows the power consumption comparison at similar pump intake pressures. And, as shown in Table 1, Extract converted KVA into KW usage by utilising the efficiencies of each motor at load. This shows the difference in KW usage, normalising for minor differences in production rates and depths. By converting consumption into a metric for the kilowatts required to lift a single barrel by 1000 ft, Extract demonstrated that SpeedFreq consumed 35.2% less power than an equivalent conventional unit. At US$0.06/KWh, the power savings are close to US$2800 per month and US$33 600 per well on an annualised basis. Exact savings will vary with changes in power costs, and the percentage may vary by field.

Case study: greater upfront production through high-speed operation

With development and completion costs skyrocketing, producers find themselves needing a faster return from each well. SpeedFreq’s motor and horsepower output help speed upfront










production by sustaining higher production rates longer as bottomhole pressure declines. In early 2021, a producer evaluated the unit’s production capabilities in a declining well after replacing a competitor’s induction unit. The previously installed unit’s production had dropped significantly over its final 7 days in use. That pump showed signs of reaching Q-min, where a pump can no longer draw down bottomhole pressure and sustain production rates. On its last day this previous pump’s intake pressure was 1863 psi, producing 2846 bpd of liquid and requiring 250 brake horsepower (bhp). Once the SpeedFreq was optimised for the well, it reached similar pump intake pressure while boosting liquid production to 3541 bpd, a 24% increase. The bhp required was 200 hp, a 20% reduction. The company continues field testing to further confirm these results.


Financial realities and ESG requirements are pushing unconventional producers into ever more unconventional situations, which standard equipment and procedures struggle to fulfill. The days of small tweaks and updates are quickly disappearing. New thinking and ground-up redesigns of many processes and machines will be necessary for the oil industry to survive and thrive.

Reference 1.

World Steel Association, ‘Steel’s Contribution to a Low Carbon Future and Climate Resilient Societies’, https://www.worldsteel.org/en/dam/ jcr:c4532192-07eb-43ba-955c-cec8aead6763/Climate+Change+Position+Pa per+FINAL+WEB.pdf, p. 4.

Issue 4 2021 Oilfield Technology | 25



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Duncan McAllister, Karl Rose and Mike Ott, Varel Energy Solutions, USA, and Sebastien Reboul, Varel Energy Solutions, UAE, consider the experiments and modelling used to identify the key elements of a PDC bit design centred on drill bit hydration.


ptimising hydraulic energy at the drill bit has been a goal for many years. Managing the total flow area (TFA) of a set of nozzles is based on pressure drop needs as well as the ability to pass material, such as lost circulation material (LCM), through the bit. Over time, nozzles have been manipulated to be longer, apply a curved vector to the exit and be directed in towards a specific location. With PDC bits, as rig capacity continues to increase, so more and more hydraulic energy is being produced through flow rate and pressure. To take advantage of that energy, advanced learning around how to apply the current generation of curved nozzles, along with matching a set of PDC design criteria, allows for improved bit cleaning, cuttings

evacuation from the face of cutters and improved cutter cooling. This article will discuss Varel Energy Solutions’ (VES) methodology around drill bit hydration.

Building on knowledge

When VES first launched the HYDRATM design philosophy, development on how to best apply the techniques continued. HYDRA attributes are centred on solving problems specific to optimising PDC bit hydraulics. It provides a way of critically looking at all the factors that influence performance while finding the optimal balance of features using the rig’s available hydraulic energy.

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R&D based on this design philosophy resulted in fresh insights into fluid flow patterns at the cutters and around the bit body. These insights led to experiments with different bit design scenarios and the development of a distinct set of design features. These features make up a system that is balanced to optimise hydraulic energy for the application.

System features

The HYDRA solution applies three bit features: Curved nozzle. Webbed blades. Straight blades.


Curved nozzle The curved nozzle is a feature that continues to see successful runs on standard bit designs as well. With the HYDRA design, it is coupled with blade and bit geometry features to improve the use of the rig’s available hydraulic energy. Curved nozzle geometry has evolved over time to allow more efficient flow paths and to incorporate a new method for nozzle installation. This has

allowed for more accurate nozzle setups for field-based bit installation.

Webbed blades HYDRA design bits have a webbed blade feature that connects each secondary blade to the back of a primary blade to help contain and direct hydraulic force for optimised cleaning and evacuation. Conventional PDC bit designs typically leave this space open. By blocking off the flow path between blade junk slots, it forces the fluid coming out of each jet to remain in the junk slot. This significantly enhances the amount of fluid flowing across the cutter faces. Without them, fluid can be forced to flow into an adjacent junk slot, thus potentially starving a set of cutters of needed flow rate.

Straight blades Straight blades, in comparison to conventional curved blades, enhance hydraulic performance by increasing cutter cleaning and cooling. When the blades are not straight, the fluid is forced to travel further to access the cutter faces. Since the shortest distance between two points is a straight line, a straight bladed bit gives the most direct access for the cutters (especially on the shoulder of the bit) to the directed flow coming from curved nozzles.

Modelling scenarios: shear stress and cuttings evacuation

Figure 1. Hydraulic shear stress modelling.

A study was developed with the aim of improving hydraulics performance to increase rate of penetration (ROP) compared to current bit models. Multiple computational fluid dynamics (CFD) studies identified two key variables contributing to PDC bit hydraulic performance: shear stress and cutting evacuation. Based on this information, various bit designs were modelled to identify the best package of attributes. The model scenarios examined various configurations of blades (straight, spiral and webbed) and nozzles (curved and conventional).

Figure 2. Plot of time versus the percentage of particle evacuation shows how long it takes to move cuttings into the wellbore annulus.

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Model comparison of shear stress and cuttings The studies showed that greater hydraulic shear stress across evacuation the face of the cutters and front of the blades improves cutter A ranking system was used to compare hydraulic shear stress and cleaning and cooling. In doing this, the position of the curved cuttings evacuation for the various models. Taking the curve out nozzle – particularly its azimuth and nozzle exit points – is an of the blades was a key factor. The top three models for shear important variable. stress were all zero-spiral blades. In terms of cutting evacuation, Efficient cuttings evacuation depends on quickly and the number one rank was the webbed blade model, which had effectively moving cuttings away from the bit and into the nine curved nozzles. Adding the webs significantly improved annulus. Studies showed that blade geometry has the biggest cuttings evacuation. When the webs were used with non-spiral effect on cuttings evacuation. Straight blades showed a significant blades, cuttings evacuation was enhanced. increase in cutting volume. This analysis revealed the three key elements of a HYDRA Hydraulic shear stress modelling provided significant insights design bit: webbed blades, nozzles and straight blades. into how fluid moves across the cutters and blade face. Each bit configuration was modelled and compared to a non-HYDRA Webbed blades standard bit. The analysis was significant in showing the degree to which In Figure 1, the bit blade is shown in dark blue and shear stress cuttings are re-circulated with conventional open blade designs, is indicated by the lighter colours. The standard blade model and revealed a marked difference in how standard and webbed shows hydraulic shear stress confined largely to one section of the blade designs affect fluid flow. blade. However, modelling of the test blade shows shear stress With standard blades, particle movement was localised reaching a larger area of the blade and cutters. Greater shear around the blades in the primary and secondary junk slots, but did stress is indicated further down the blade (circled area) and higher not exit the junk slots. Adding the webbing cut off the flow path up the blade, providing a much greater area of cleaning and around the blades, to help direct cuttings flow out the junk slot cooling. (FIgure 3). Cutting evacuation for various bit model scenarios were plotted using a VES technique to measure and compare cuttings evacuation. Optimally, the cuttings quickly leave the cutter and travel quickly through the slots and into the annulus. In Figure 2, a plot of time versus the percentage of particle evacuation shows how long it takes to move cuttings into the wellbore annulus. The modelled process determines the time it takes for a set number of cutting particles generated at the cutter surface to move through the junk slot and into the annulus. Cutting generation Figure 3. Webflow. Conventional (left) and HYDRA (right). is simulated at the contact point between the edge of the cutter and the formation. Particle model interaction with fluid flow and its transport time to the annulus is calculated. The particles are then individually introduced to the model and their transport is measured over time to determine a percent evacuation time. The various bit models exhibited a wide range of particle evacuation, from 70% to 100% (Figure 2). The best performance was from a zero-spiral model that had a steep evacuation rate that reached its peak Figure 4. Nozzleflow. Conventional (left) and HYDRA (right). very quickly. Issue 4 2021 Oilfield Technology | 29


Figure 5. HYDRA versus Standard – STACK vertical section footage comparison.

The impact of a curved nozzle with regards to cutter cleaning and cutter cooling is significant. It directs greater shear stress across the face of the cutters, and results in more complete cuttings evacuation. Flow models clearly show the curved nozzle produces a strong flow line running across the base of the cutters, and in front of the blade to push cuttings down the junk slot and into the annulus. This is in strong contrast to the conventional nozzle, where flow is much less organised and is restricted in its reach (Figure 4).

Straight blades

Figure 6. 16 in. Oman top-hole HYDRA footage and ROP comparison versus competition.

The three top ranking scores were all bits that had straight blades, because straight blades have more hydraulic shear stress further down the blade. This improves cutter cleaning and cooling, because the nozzle exit is closer to the actual element, in front of the blade and the cutters.

Field performance

To date Varel has successfully deployed HYDRA technology in 5000+ bit runs across the globe. This continued pursuit of applying the technology’s design philosophy to the applications has also resulted in recent successful runs in demanding intervals.

Mid-Continent field data

Figure 7. 12 1/4 in. Oman dull picture with HYDRA.

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HYDRA designs have been successfully utilised in Mid-Continent, US, applications for the past 4 years. The first part of the wellbore that the design showed an impact on performance was in the intermediate section in the STACK region. The technology’s success in this application can be attributed to an improvement in cutter cooling and cuttings evacuation, leading to improved cutter life that in turn results in longer bit runs and better dulls. In an analysis of 269 bit runs in the 8.75 in. vertical ‘drill out’ section across four STACK operators, HYDRA-equipped bits showed a 17% improvement in average footage drilled as well as an average dull grade improvement. The bits maintained an average dull grade of 1.1 – 2.2 (inner – outer) compared to 1.6 – 3.7 (inner – outer) for standard designs. The additional durability that HYDRA-equipped bits provided in this application also led to an increased reliability to make it to total depth (TD) in one run. The bits made it to TD in one run 89% of the time, compared to standard PDC bits that made it 40% of the time (Figure 5).

An expanded use of the HYDRA features has made an impact in many other applications where hydraulic efficiency plays a key role in bit performance. Most recently, an operator in Oklahoma, US, drilled a challenging lateral section. This section is a medium to high compressive strength interval with mixed amounts of heavy minerals, where it is not uncommon to see dulls that are damaged beyond repair. When drilling through these abrasive zones with variable compressive strengths it is important to maintain hydraulic efficiency through the shale sections while maximising cutter cooling in the abrasive zones. An 8.75 in. HAVOX-613 with HYDRA was able to drill the entire lateral at 63 ft/hr, which set a new benchmark for the operator.

Oman field data HYDRA designs have been successfully deployed into operations in Oman to cover several applications. In one application, in shallower wells, the top-hole section is experiencing an increased ROP in 16 in. bits when being drilled with motor performance bottomhole assemblies (BHAs). By allowing better and faster cuttings evacuation at the cutter to rock interface, increases have been realised. This has resulted in optimum efficiency while drilling out relatively soft shale with a base carbonate formation. The jetting action of the curved nozzles, combined with the webbed blade configuration to prevent any cross flow and cutting recirculation, delivered ROPs with a 45% improvement over the average ROP of the best offset runs and an almost 15% increase over the best run to date (Figure 6).

In another deep and very challenging 12 ¼ in. section, HYDRA increased bit durability (Figure 7). This was achieved by directing the fluid directly to the key location of the cutter/rock interface to target the area that has the highest cutter wear rate. This further highlights one of the main advantages of the HYDRA concept. Bringing the fluid directly to the key location of the cutters/rock interface with the curve nozzle (and especially towards the shoulder of the cutting structure, where the highest diamond wear is usually seen) is one of the main advantages of the HYDRA concept. Diamond wear is directly linked to the heat generated and volume of rock removed, which is typically highest on the outer portion of a bit, hence the benefit of cooling down this area by increasing flow distribution. This will slow down the cutter wear and prolong bit life in challenging, long section applications. The 12 1/4 in. VION-616 was used for a challenging 2000 m section to drill into an interbedded formation sequence that includes a shale, carbonate and sandstone formation. It drilled the full section to TD at an average of 30 m/hr, improving the usual ROP achievement by at least 15% due to a sharper cutter throughout the end of the run.


As more projects take place with new concepts being applied, the learnings will continue to grow. It has been shown that using the available hydraulic energy in the drill string can be directed into an efficient pattern around the bit that that results in incremental drilling value. For Varel Energy Solutions, this is defined as drill bit “hydration”.

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CONTINUOUS IMPROVEME WINS THE RA Chris Gooch, Ulterra Drilling Technologies, USA, explains how incremental steps can bring large-scale changes to reliability, efficiency and economics in the drilling environment.

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n the upstream drilling industry, drilling performance is often equated with records and milestones – fastest well, longest section, operator records. News feeds are saturated with these matter-of-fact stories. Few are talking about the incremental gains over time that make up the majority of good, reliable, consistent performance, even though it is this kind of continuous improvement that brings the most success. The best economic outcome, for both the service supplier and their client, comes from continuously improving the tools, equipment and drilling practices. In North American land drilling, this approach has led to the region being one of the fastest, most efficient and economical drilling markets in the world. This article will discuss how incremental improvement resulted in meaningful drilling performance gains in a critical West Texas, US, application.

Well planning in Midland County, Texas

In Midland County, Texas, the typical well plan would complete the vertical section in 12 ¼ in. hole size before drilling the curve and lateral in 8 ½ in. (Figure 1). The curve is difficult, building from vertical to horizontal in typically less than 1000 ft with high doglegs and near-continuous sliding. The same bit and drilling assembly are then expected to continue drilling into

the horizontal as far as possible, with many completing at least half of the approximately 10 000 ft lateral. On some occasions, a single bit and bottomhole assembly (BHA) will complete the entire section in a single run. Penetration rates average above 100 ft/hr – slower in the curve section while executing directional work, but much faster when rotary drilling. There are two primary keys to success in this kind of section: first, a stable toolface in the curve, and the second is to track straight in the lateral. To maintain a stable toolface in the curve, both the bit and the motor must work well together, along with a BHA layout that suits the directional requirement. The motor should deliver consistent torque and have sufficient torque capacity to keep doing so, even when high weight is applied. The bit, in turn, needs to develop a smooth and predictable reactive torque over a wide range of weights and revolutions per minute (RPM). The continuous balance between the driven torque from the motor and the reactive torsional force from the bit keeps a stable and predictable toolface that the directional driller can use to slide easily while drilling ahead. Tracking straight in the lateral section depends on drill bit dynamics and the reaction to drill string orientation because of frictional forces. In a horizontal section, the natural tendency of

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a neutrally balanced bit is to walk right and drop under gravity, unless supported by a near-bit stabiliser. This is counteracted by the BHA and string sitting on the low side of the hole having rolling friction to the right while tilting the bit high as it fulcrums off either a stabiliser or another outer diameter (OD) component. If all these forces are in balance, the rotating drilling system goes straight and there is no need to stop and slide. The goal then is to maintain straight, rotary drilling for as long as possible so that slides are minimised and the overall ROP for the section is increased.

Case study Figure 1. A typical well plan in the subject application.

Figure 2. The final bit design after multiple design iterations.

Figure 3. Average curve drilling times reducing over a 6-month test


Ulterra has been going through a continuous process of tweaking the balance between all these factors in a Midland County application, in conjunction with a particular operator. Over a period of 6 months and more than 30 runs, the positions of cutters were changed and backrakes altered over multiple bit designs. The result was a better-balanced bit, not fully biased to ultimate straight-line speed or extreme durability, but rather more suited to the application overall (Figure 2). This gave the operator a product that drilled smoothly and with a predictable reactive torque, so that they could start to adjust and optimise other factors in the drilling process. By making the entire system more predictable, reliable and cohesive, the operator was ultimately able to reduce curve time and increase overall run distance, which had a significant impact on drilling cost. With Ulterra’s 8 ½ in. curve and lateral application, the operator saw a continuous curve time reduction over 6 months (Figure 3). The average curve time reduced from 14.1 to 12.7 on bottom hours, an improvement of approximately 10% over the 34-well programme. Additionally, the same smooth and more efficient drilling action that was necessary to achieve this also resulted in better durability and reliability. At the start of the campaign, there were no runs where a single assembly drilled all the way from the casing shoe to total depth (TD) of the well. Occasionally, the assembly was pulled out of the hole for bit-related issues; mostly it would be pulled to change BHA configurations for the lateral and the bit would be replaced out of routine. In the last 2 months of this programme, 50% of runs were shoe to TD with close to 11 000 ft total drilled per run, saving significant time on expensive round trips to the surface. This indicates greater reliability, improved directional control in the curve and increased time tracking straight in the lateral, removing the need to change the BHA. Collectively, these changes resulted in the significant increase of 60% to the average run length of these curve-lateral applications, increasing from approximately 4600 ft per run to 7300 ft (Figure 4). Over time – as the improvements were employed across additional runs – operator cost savings quickly compounded, and complete improvements to the bit, BHA and drilling process were implemented.


Figure 4. Average single run lengths increased over the 6-month test


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When assessing factors such as reliability and predictability, single run records and simple one-pad comparisons are not sufficient; instead, multiple runs over time should instead be considered in order to see the true impact. Incremental changes make smaller improvements, but ultimately modest time and cost savings made over tens or hundreds of runs quickly multiply into significant economic improvements; something that is crucial to operators and investors in the current upstream drilling market.

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MEETING THE CHALLENGES OF THE HAYNESVILLE Donya Blakney, Drilformance, USA, outlines the impact that meaningful pairing of bit design and cutter geometry can have on drilling performance in over-pressured shale plays such as the Haynesville.


s the shale market continues to accelerate, so does the need for drilling technology development to keep up so that performance can be optimised and operator costs reduced. Over-pressured shale plays, such as the Haynesville in the US, present a unique challenge. High mud weight and elevated temperatures can wreak havoc on downhole tools, increasing the risk of unplanned trips and non-productive time (NPT). Choosing the proper drill bit and complementary bottomhole assembly (BHA) to address these challenges can provide notable gains in performance. Bit design and ‘fit-for-purpose’ cutter geometry affect bit response. The bit response must be understood in order to identify the appropriate motor configuration and torque output. Meaningful pairing of these two BHA components ensures success.

Drill bit platform

The Badger Drill Bit Platform presents three drill bit options to target specific

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requirements within the application. Design elements include Badger cutters, TruSteer cutters, TruSteer back rakes, a gauge design that enhances lateral stability and hole quality, blade stand-off and a nozzle placement that increases hydraulic efficiency. Operators have used the platform on over 75 runs.

Cutter technology

The Badger cutter is designed for operators drilling over-pressured shales. The cutter’s relieved face geometry is more sensitive to weight on bit, providing better point loading and shearing capability in high mud weight applications. The relieved cutter face reduces the confining pressure of the formation more effectively than a flat face or wedge style cutter. The geometry also reduces friction along the cutter face, changing the cutting’s structure and resulting in faster cuttings evacuation and reduced heat generation at the cutter tip. Lower temperatures

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Figure 1. Badger cutter.

at the cutter/rock interface mean reduced thermal degradation and wear. TruSteer utilises a bimodal geometry that effectively shifts a portion of the rock failure mechanism from a shear failure to that of a compressive failure. When combined with TruSteer bit design elements, the result is improved tool face control and reduced torque fluctuations while sliding, resulting in higher slide and overall rate of penetration (ROP) without compromise. Traditional tool face control mechanisms typically involve overly passive back rake schemes and secondary torque control features that occupy critical blade top area and limit junk slot area. TD cutters are effective with more aggressive back rake angles. These features offer directional drillers the ‘best of both worlds’ in the pursuit of responsive build rates and high rotating and sliding ROPs. Operators using the Badger Bit platform have reduced slide time in the lateral to less than 5%.

Performance results

Figure 2. Badger Bit Platform 6.75 in. DF513, DF613, DF611.

The DF611 and DF613 are designed to maximise build rate capability but continue to drill the lateral effectively. When a trip is required, the more aggressive DF513 can be run to complete the interval. However, all three designs have been proven in both the curve and lateral. A recent DF613 run drilled the curve and lateral utilising the Drilformance Haynesville motor. After drilling 8329 ft at 110 fph, the bit was tripped due to a measurement-while-drilling (MWD) failure and was dull graded a 0-0. The operator then picked up another manufacturer’s 613 and motor to complete the lateral. This second BHA drilled 3253 ft at 40 fph. The bit was pulled and dull graded a 2-2.

Haynesville motor

Figure 3. Drilformance ROP averages versus offset averages.

A motor with a 5.5 in. outside diameter (OD) can be used in order to provide higher torque and flow rate. This OD size can, however, inhibit hole cleaning, potentially create higher drag and present geometry challenges while drilling build sections. In the high temperatures of the Haynesville, the actual operating specifications are reduced. The company’s Haynesville motor is offered in a 5 in. or 5.25 in. OD. The system’s hybrid transmission and proprietary radial and thrust bearing design allows for reliability and longevity in a smaller package. In addition, the motor provides 8.7% faster revolutions per gallon and a maximum flow capability that is 14.3% higher.


Figure 4. Drilformance footage averages versus offset averages.

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All rock removal begins at the drill bit. In an over-pressured formation, the drill bit should complement the mud motor to fracture rock with optimal depth of cut to maximise rock and cuttings removal. This is achieved with collaboration when designing the motor configuration and drill bit. Bit design and cutter geometry, along with motor speed and torque output, are crucial variables to consider. Meaningful pairing of these two BHA components ensures greater control, less sliding and higher ROP. Choosing the proper drill bit, complementary motor and BHA design for a specific drilling environment provides significant performance improvement.

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At the sharp end Jarred Koenig and Michael Bouska, International Diamond Services, USA, present the results from applications of new PDC cutter technology in challenging drilling formations.


ver the past 2 years International Diamond Services (IDS) has focused on accommodating changes in the PDC cutter market, the demands of the customer and the challenges of the application. In doing so IDS has tested, developed and successfully commercialised three product series: All-Terrain, Tactical and Elite. Each of these were developed through field trials and new proprietary pressing methods. The All-Terrain series – with an updated press sintering method – has been specifically designed to tackle three performance aspects: thermal, abrasion and impact. Achieving a delicate balance between these three characteristics is crucial to successful downhole performance. With a new press monitoring system, the Tactical series is designed with an emphasis on thermal, abrasion or impact while not ignoring the other key performance elements needed in a PDC.

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Development of the Elite series entailed substantial hours of engineering and internal tests. The product line also includes a proprietary pressing method.

Case study: West Texas, US

For decades, West Texas has proven to have some of the most difficult drilling formations in the world. During a run in Midland County a customer was drilling the intermediate-vertical section of the well using the EL003 (Figure 1). While reaching total depth (TD), the customer also saw a rate of penetration (ROP) improvement of over 15% versus recent offsets, with a dull grade of 0-0-BT-G-X-I-CT-TD.

In Pecos County, a customer was drilling the deep-vertical section and also achieved notable results with the EL003 (Figure 2). The cutter is not just an improvement on thermal and abrasive characteristics, it has proven to hold together and stay sharp while drilling through conglomerates and challenging interbedded formations. This run not only drilled over 7000 ft, but also delivered an ROP improvement of just under 25% versus the incumbent cutter. The dull grade for this run was 1-1-BT-G-X-I-WT-TD.

Case study: Algeria

This case study highlights the capabilities of the AT004 cutter, which utilises a diamond table that is thicker than 3 mm. The customer was looking for a cutter that could meet the challenge of drilling a formation that consisted of dolomite/shales/sandstone/pyrite but could also be economically viable. In this run, the customer saw a ROP of +90% versus field average and +20% versus best performer. The dull grade for this run was 1-1-WT-A-X-I-NO-TD.

Case study: Canada

Figure 1. ELOO3, Midland County, West Texas.

A customer was struggling to find a cutter that was able to maintain structural integrity from the diamond layer through the carbide. The rigorous drilling conditions in the oilsands left many cutters unusable after one run, due to extreme carbide wear and undercutting at the diamond interface. IDS set out to design a carbide substrate that would overcome these obstacles. The end product was the AT005 cutter. The results of its application are further documented elsewhere.1 Following this success, the AT005 diamond layer and newly designed substrate were adopted across the company’s entire fleet of products. Coupled with a proprietary feed blend, IDS was able to create a cutter that was not only erosion and corrosion-resistant but had the propensity to withstand severe impact damage when the bit was introduced to any type of lateral, axial or torsional vibrations. The impact toughness not only translated into longer lifetime of the drill bit, but customers were also able to utilise this component in other areas of the drill string, such as rotary steerable pads, reamers, hole openers and, most recently, plug drill out bits and casing exit mills.

New shapes on the horizon

The standard PDC cutter cylinder is not the only shape for cutters on the market today. Shaped PDC cutters are evolving in every aspect of the drilling arena, with options available for operators looking for increased ROP, optimised cooling, better depth of cut and formation engagement, or better overall secondary cutting elements. The TC005 and TC010 are two possible shapes that could assist in multiple drilling applications by delivering higher depths of cut, while also allowing less heat build-up on the PDC diamond table. This could allow for a more aggressive approach downhole without jeopardising drill time.


The drill bit is an ever-evolving tool that is the working end on every bottomhole assembly (BHA) in every well drilled. As customer needs evolve, drilling practices change and materials advance; it is the task of PDC cutter developers to continue to deliver products that can remove rock efficiently and economically.

Reference 1.

Figure 2. ELOO3, Pecos County, West Texas. 42 | Oilfield Technology Issue 4 2021

WONG, A., BELL, A., WILLIAMS, M., ISNOR, S., and HERMAN, J.J., ‘New Material Technologies Reduce PDC Drill Bit Body and Cutter Erosion in Heavy Oil Drilling Environments’, SPE-181196-MS, https://onepetro.org/SPELAHO/proceedingsabstract/16LAHO/2-16LAHO/D021S010R002/208081

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Increasing the value of deepwater wells Kenneth J. Kotow, Steven M. Rosenberg, Nitin M. Kulkarni and James P. Wakefield, Subsea Drive LLC, USA, explain how deepening the structural casing in the riserless section using casing drilling can lead to improved well integrity and economics.


significant improvement in deepwater well integrity and value can be accomplished by deepening the structural casing creating its dual functionality. This results in the structural casing providing both axial and bending loading requirements and having a stronger casing shoe strength to drill any subsequent shallow drilling hazards. This, in turn, reduces at least one casing string in the riserless section to place the high-pressure wellhead housing (HPWH) casing significantly deeper than is possible with conventional methods. The result is fewer casing strings to reach planned well depths with placement of larger casing diameters with larger annuli deeper than current practice allows (Figure 1). This improves the likelihood of attaining the deepwater well objectives by enabling larger drilling operating pressure windows to minimise the risks associated with the loss circulation/well influx cycle. The method proposed for deepening the structural conductor is casing drilling technology utilising the Subsea Drive Casing

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Drilling System. Casing drilling technology facilitates drilling casing to deeper depths than are currently possible with the practice of jetting, while mitigating the hazards of shallow drilling with a single trip. Casing drilling on land or offshore is not new, having been applied frequently to improve drilling operations through greater drilling efficiency and mitigation of drilling hazards. However, casing drilling has never been used in a subsea environment since the technology was not available. Subsea Drive, LLC has developed the concept to deepen the structural casing to improve deepwater well design, using casing drilling as the means to achieve the objectives. The deepened structural casing is part of a specially designed system – which includes casing with high torque capacity connections, casing bit, cementing inner string and a running/drilling tool – called the Subsea Drive. On top of the casing of this system is the low-pressure wellhead housing (LPWH), which is out of the torque path. This system is run on drill pipe to the seafloor with rotation

provided by the rig’s top-drive, drilling to the required depth of approximately 1500 to 2000 ft below the seafloor. This is much like a liner installation, due to the depth of the water being greater than the casing string. Drilling continues with circulation of the drilling fluid as in current riserless operations through the drill pipe, cementing inner string and returns on the outside of the casing to the seafloor. This technique uses a sacrificial ‘heavy’ drilling fluid with returns to the seafloor in a process known as ‘pump and dump’. This is a dual gradient operation of the heavy mud in the annulus and the seawater above. The density of the heavy drilling fluid is determined for the dual gradient drilling density to be slightly higher than the prevailing pore pressure. It has been established by global casing drilling experience that if the casing diameter is about 80 to 90% of the hole diameter the narrow annulus created is ideal for plastering and grinding the drill cuttings into the wellbore as they are circulated up to the seafloor. This phenomenon

mitigates shallow hazards, such as gas and water flows, by decreasing the effective permeability in the wellbore area. The ‘plastering effect’ increases wellbore formation strength, mitigating wellbore instability which is prevalent in the shallow offshore formations. The principal benefit of this well design approach of significantly deepening the structural casing, the first casing, beyond current practice is decreasing the total number of casing strings required to reach planned depth. This allows for larger casing-to-formation-annuli, which increases the drilling operating pressure window between pore pressure and fracture pressure gradients. Deepwater environment operating pressure windows are narrow, causing significant drilling problems and often leading to failure to reach well objectives. A secondary, but also valuable benefit is the improvement in drilling efficiency, since fewer casing strings equals less rig operating time, with casing drilling technology the means to mitigate shallow drilling hazards.

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The application of casing drilling in the riserless sections has the following advantages: Facilitates simultaneous drilling and running the structural casing to significantly deeper depths. Improves drilling efficiency by drilling and running casing in a single trip. Wellbore strengthening. Mitigation of shallow drilling hazards with a single trip. Better cementing and zonal isolation, as casing can be cemented immediately upon reaching setting depth.


Drilling and running of structural casing to deeper depths Conventional drilling practices are not suitable for drilling and casing offshore shallow formations due to inherent wellbore instability, which does not allow enough time to drill and then run and cement the casing; there is high potential for hole collapse. Drilling with casing mitigates the wellbore instability and allows for immediate cementation upon reaching casing setting depth, thus eliminating the time off bottom where hole instability is problematic. The easily drillable nature of offshore shallow formations lends itself well to the application of casing drilling and the use of PDC drillable casing bits. It is the soft and unconsolidated nature of the shallow offshore and deepwater environments that made the jetting practice common for placement of the first casing. However, it has a technical limit of between 200 to 300 ft below the mudline for penetration. It is this shallow setting that is an impediment to deepwater well design improvement as proposed by Subsea Drive, LLC. It is hoped that the Subsea Drive system, using casing drilling, will replace jetting as the industry standard.

Wellbore strengthening Wellbore strengthening resulting from casing drilling is a well-known phenomenon, sometimes called the smearing or plastering effect. There are many examples illustrating the quantitative value. One such example is in the Alaskan Kuparuk field, which clearly indicates a significant increase in effective fracture gradient from 12.7 ppg before to 14.4 ppg after casing drilling. This phenomenon can mitigate or prevent circulation losses while drilling and cementing. It has been estimated that formation strengthening is most effective when the ratio of casing to hole diameter is approximately 0.8 to 0.9.

Mitigation of shallow drilling hazards Figure 1. Reduction of casing strings.

Rotating the casing while drilling has significant advantages for mitigation of drilling hazards such as shallow water and gas flows, gas hydrate flows and wellbore instability. The smearing or plastering effect caused by the rotation of casing grinds and smashes the return drill cuttings into the wellbore, hardening the wellbore and plugging off permeability to mitigate loss of circulation, shallow water and gas flows – improving wellbore stability. Once the drilled casing reaches the required casing setting depth the cementing operation is initiated immediately.

Better cementing and zonal isolation

Figure 2. Subsea Drive system.

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Cementing the conductor and/or surface casing strings in regions of shallow water flow is potentially one of the biggest challenges of deepwater drilling. During the transition stage, the hydrostatic pressure of the cement slurry can decrease to the density of mix water. This reduction in hydrostatic pressure can allow water and gas from geopressured zones to flow and disturb the cement before it sets up, causing uncontrolled flows of massive amounts of formation water to the seafloor. The wellbore strengthening from the casing drilling smearing

effect could minimise or even eliminate this concern, due to the creation of a strengthened and less permeable wellbore.

Subsea application

The use of casing drilling for the installation of the deepwater structural casing is an innovative application of this proven technology in the subsea environment. The technology will support the axial loading requirement for the 800 000 lbs structural casing and is capable of applying more than 50 000 ft-lbs of torque to rotate the casing for drilling. The casing would be run like a liner on drill pipe with a purpose-built subsea drive tool. This subsea drive tool allows the use of existing LPWH systems without any modifications, since the tools inserts engage the structural casing internally below the LPWH. This takes the wellhead assemblies out of the torque path. The casing is drilled to the depth placing the LPWH just above the seafloor. This system uses a custom-built PDC casing bit, in which the bit’s drill-out path is made of PDC drillable material for easy removal with a PDC or roller cone bit that is suitable for drilling the next hole section. A dedicated drill out trip is not required. Due to the large casing volume, an inner string is required to efficiently circulate the cement in place once drilled to planned depth. Subsequent hole sections could be drilled as per current practices by drilling through the casing bit or with continual use of the subsea drive tool with a bottomhole assembly (BHA) inner string. This would be similar to current casing drilling practices. The concept of the system is illustrated in Figure 2, indicating the main required components and functionality of the assembly. This technology is an extension of existing casing bit and casing running technology, allowing for easy adaption by the industry to a subsea riserless drilling environment.

The deepwater Subsea Drive system will be deployed from existing floating drilling rigs to be run in a manner similar to current liner deployment methods. Once the first structural casing is drilled into place and cemented, the drilling operation will continue with current conventional practices to set each subsequent casing as per the pore pressure and fracture gradient environment.


The current limitation of structural casing setting depth is predetermined by the jetting practice, which is at its technical limit for setting depth. Subsequent riserless casings are set above shallow geological hazards for the utilisation of sufficient drilling fluid density for mitigation of shallow geological hazards (e.g. shallow flows, faults, wellbore instability) in the riserless interval. This practice in itself is self-defeating. The deepwater well design is based upon the ‘Top-Down’ casing design approach, where the diameter and setting depth of the first casing determines the number of subsequent casing strings and the resulting diameter of the wellbore annuli. The deeper the first string is set, the fewer casing strings are required and the wider the drilling operating window becomes. The proposed casing installation process takes advantage of the rapid increase of the overburden and fracture gradients of shallow formations, allowing for the optimisation of riserless casing seats with casing setting depths predicated on pore pressure and fracture gradients. The result is fewer casing strings, larger wellbore (casing/annular) geometries with lower equivalent circulating densities, leading to a higher probability of reaching well objectives with improved well economics.

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the Middle East

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Vincent Ribouleau, 3X ENGINEERING, Monaco, uses a case study from the Middle East to demonstrate how composite wrapping is transforming the pipeline repair industry.


aintaining offshore assets or subsea pipelines to ensure that the extraction and production of oil and gas is carried out effectively is one of the key challenges that petroleum engineers have faced over the years. The use of inappropriate technology or difficulty in procuring the right solution (especially in response to an emergency situation) often leads to a rise in the cost of maintenance, loss of production and even delays in the delivery process. This necessitates the introduction of innovative technology that can enable workers to perform their duties in harsh environments, as well as increase the longevity of various parts of a facility for maximum usage. Subsea pipelines often experience harsh conditions that lead to quick deterioration, whether from the chemical composition of oil, gas, chemicals or water, the sea /seabed conditions or other activities (e.g. anchors, drag force, pipelines crossing etc.).

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Subsea challenges

Today, for many pipeline owners, the challenge is no longer how to expand their subsea pipeline network but rather how to maintain in service an ageing subsea pipeline network. What strategies are available to extend the life of a network by reducing the time of maintenance and reducing the risk and cost of heavy equipment mobilisation?

Composite repairs are now a mainstream solution in the oil and gas industry, with an extensive track record onshore and offshore. The benefits of composite repairs for the industry have been proven to a level where the major oil and gas companies have standardised and integrated the use of this solution. They extend the life of assets by providing strength, corrosion resistance, a light weight, design flexibility and durability. The requirements of the emergency pipeline repair systems (EPRS) divisions of the major oil and gas companies have converged on the development of a solution that has to be on shelf, ready to be used with a standardised design, applicable on any geometry and has a minimum impact on service and production. A new product is now able to reinforce a pipe experiencing external or internal corrosion, a dent, a leak, a weld defect, a crack, a delamination and much more, regardless of the diameter, geometry, operating condition or environment.

Case study

Figure 1. Composite wrapping in progress using subsea handles (control room screenshot).

Figure 2. Subsea repair performed by trained and certified divers (illustrative picture).

What is the performance of this product? And what are the benefits of using composite wrapping in the repair of a subsea pipeline? These questions can be answered by the review of a project carried out in response to the bursting of a 32 in. subsea gas pipeline due to hydrogen-induced cracking (HIC) in the Middle East. Subsea inspection identified two cracks, including one opened through wall that initiated a severe gas leak of 1160 psi (80 bar). Of particular importance for the client was sealing the leak from the crack, stopping the crack propagation and, finally, rehabilitating the original integrity of the pipeline in order to operate it again at the design pressure. The major challenge was to seal the cracks in situ at the given depth with non-metallic material that was resistant to corrosion and had sufficient strength to sustain mechanical and structural stresses. This particular repair performed by 3X ENGINEERING used computer software based on ISO 24.817:2017 and ASME PCC-2, as well as finite element analysis (FEA), to define the length and the thickness of REINFORCEKiT® 4D SUBSEA (the company’s composite wrapping solution) required for the project. Composite layers are produced from the impregnation of an aramid fibre with an epoxy resin to achieve the mechanical and structural rehabilitation of the original integrity. In this particular project, the 70-m depth required saturated diving in order to be convenient for operations. Before the main work could begin, excavation underneath the laid pipeline at the defect’s location – to generate a 40 cm clearance area – was required. Removal of the concrete coating, in order to reach the bare metal, was also performed through water jetting.

Stages of installation

Figure 3. Surface preparation (illustrative picture).

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Preliminary operations involved the achieving of a desired surface profile through the means of sand blasting, with a roughness of between 60 µm and 100 µm needed in order to conform with the bonding requirement. This was a crucial stage, with all axial and circumferential mechanical efforts borne by the REINFORCEKiT 4D SUBSEA. Adhesion between the composite and the substrate was one of the key points. The second step was to stop the crack propagation. This was a mechanical operation performed by drilling the edges of the cracks using a pneumatic driller.

The two cracks then had to be sealed with the application of epoxy filler in addition to a factory-made composite plate. Epoxy filler is the most appropriate substance for such a task, as it ensures the surface regains its original conformity and the pipe regains its original geometry. Once the cracks were sealed, the next step was to restore the original integrity of the pipe by bringing the necessary strength from the composite wrapping to compensate for the weakness of the defective pipe. Epoxy primer was applied on the whole surface to be repaired. The primer was used to ensure that proper bonding was achieved between the surface of the pipeline and the composite to be wrapped. Application of the composite layers was carried out by the divers during the wrapping stage. Composite was pre-impregnated on the diving support vessel (DSV) with an impregnation device and sent to the divers through a messenger cable. This task was facilitated with the use of a dedicated coil fitted with controlled tension handles. The final step was linked with the curing of the composite. As a bi-component material, the product is entirely reliable when full polymerisation is achieved. Chemical composition and temperature are the two main factors to be considered during this process. A Shore D durometer was used onsite to evaluate the hardness during curing. When the hardness reached the specified minimum value, the resin was considered cured and the composite repair was able to sustain fully mechanical stresses. As a result, the client received the repaired pipeline after a fast mobilisation, as a composite application does not require the manufacture of a specific structure – such as a metallic clamp or a spool replacement – in advance.

Next steps

3X ENGINEERING is testing the development of its solutions with reputed third-party laboratories to ensure they are safe to use and deliver the expected operational results and necessary standard requirements. The subsea environment is challenging for composite repair, as many factors have to be contended with, such as the temperature of the water and pipe, salinity and depth. With each case being unique, so the solution must be as versatile as possible. The epoxy components are chosen carefully to be the least sensitive to water aggression during polymerisation. Studies in a hyperbaric room under a hydrostatic pressure of 300 bar have been performed to simulate the deep offshore configuration, demonstrating the good performance of REINFORCEKiT 4D SUBSEA. The bonding of the primer is critical to transferring the loading to composite. It implies the primer needs to be able to wet properly the substrate, polymerise at a specified temperature and, once cured, transfer the loading to composite. Even when applied in seawater, the shear adhesion strength of the solution is twice (10 MPa) that of the minimum requirement of the applicable standard (4 or 5 MPa). Epoxy curing is followed up by checking thermal and mechanical performance simultaneously, using dynamic mechanical analysis (DMA) or a combination of a tensile bench and differential scanning calorimetry (DSC). Epoxy chemistry is governed by the Arrhenius equation, meaning that a higher temperature leads to faster curing. The challenge now is to bring this experience to the next level of depth, from shallow (0 to -100 m) to deepwater areas where the constraints will be the key factor in an important transformation in the maintenance market.

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Michael Jefferson, Tracerco, UK, explores how pipeline inspection techniques have adapted to the challenges facing pipeline operators.

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s economical oilfields in shallow waters have depleted over time, operators have turned their attention to more challenging fields. The challenges facing these operators vary but typically include deepwater fields, low flow rates, high risk of hydrate formation and high pressures. These pose a particular problem for the inspection and maintenance of pipelines, given that modern pipeline systems are required to operate in more and more challenging conditions, resulting in complex design solutions and previously unencountered corrosion and failure mechanisms. To ensure the ongoing safety and integrity of these pipeline systems, advanced inspection techniques have been developed. One such technique is Tracerco’s DiscoveryTM, a computed tomography (CT) scanner that was developed to tackle such challenges and designed to ensure it is compatible with pipeline integrity management systems.


The scanner was specifically designed to provide operators with an enhanced understanding of a pipeline and its coating together with the process fluid, all whilst the pipeline remained operational. The principle behind Discovery is relatively straightforward – the CT beam passes through a material and the density of this material can then be calculated by how much the beam is weakened, known as the attenuation coefficient of the material (Figure 1).

The advantage of CT over other inspection techniques is that it can generate information about the pipeline wall thickness and integrity, the product flowing conditions and the condition of any coating applied to the pipeline, all in a single scan. This information can then be fed into a combined integrity management system, where an operator can view the actual condition and operation of their pipeline network. This, in turn, can help to improve the future integrity of the pipeline. Discovery is similar or better to tolerances achieved by other non-destructive testing techniques, such as magnetic flux leakage (MFL). MFL is the most used method of pipeline in-line inspection (ILI). Operators using the scanner for local scan inspections are therefore confident that the results are as accurate as those that can be achieved by other, traditional inspection techniques. In addition, the scanner provides a direct measure of the wall thickness available, which is a simple process to compare results produced by other inspection techniques – for example, as part of a corrosion growth assessment. The standard tolerances according to the defect classes, as laid out by the Pipeline Operators Forum ‘Specifications and Requirements for Intelligent Pig Inspection of Pipelines’, are provided in Table 1.

Fast screening technique

A continued difficulty facing operators is the amount of useful inspection data available to them. In many systems, conventional

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inspection techniques, such as ILI, may not be practical or even possible. In such cases, operators may be forced to limit themselves to performing localised inspections at potential ‘hotspots’. Depending on the results of inspections performed at these ‘hotspots’, further inspections may be required, which can be a costly process. Building on experience whilst working with similar technologies, Tracerco was able to determine that defects or damage in a pipeline wall had a unique characteristic that is typically identifiable within a minute of the scan commencing (Figure 2). If this characteristic is not present, then the scan can be terminated and moved to the next position. The advantage of such an approach is that it helps maximise the amount of useful data collected whilst minimising the overall

project time and therefore cost. The overall reduction in scan time is generally between 50% and 80%, depending on the extent of any damage in the pipeline. This technique, known as ‘fast scanning’, provides swift defect identification during CT scanning, allowing operators of deepwater systems to obtain the maximum amount of valuable data from a single inspection campaign (Figure 3). The area to be scanned is split into separate sections and a suitable interval for full duration scans is determined. These full duration scans will be performed irrespective of the presence (or lack of presence) of any anomalies or defects, and are to enable general wall thickness measurements and deposit assessments to be performed. For the remainder of the section, quick screening scans are performed. Provided no anomaly characteristics are identified, Discovery moves on at the end of the fast scan time. However, if an anomaly is identified, the scan is extended to a full duration scan to enable accurate sizing of the anomaly.

Asset integrity inspection Preferential weld corrosion Case study

Figure 1. Density measurement. Table 1. Comparison of calculated data and field data Discovery Minimum depth (at 90% PoD)

2 mm

Depth accuracy (at 80% certainty)

-1 to -2 +/-1.5 mm

Width accuracy (at 80% certainty)

3 to 8 +/- 13 mm

Length accuracy (at 80% certainty)

+/- 15 mm (considered = to CT slice thickness

As part of a life extension programme, the scanner was deployed to determine the integrity of a concrete weight-coated pipeline. The pipeline was approaching the end of its original design life and a physical inspection of the pipeline was required. Prior to the campaign, the operator located the highest risk of failure areas to inspect as it was aware of several potential failure mechanisms, such as preferential weld corrosion. Also, the operator worked with a restricted timescale due to various operational issues. Due to the limited timescale, Tracerco agreed with the operator that its Discovery ‘fast screening’ technique (Figure 3) was best suited for this campaign, as it can reduce the overall scan time by a factor of five. During the campaign, it was quickly identified that corrosion was occurring inside the pipe close to the seam weld. As there are no mechanical updates needed to change the scanner from a ‘fast screening’ to a full duration scan, it was possible upon identification of a defect to continue the scan to determine the defect sizing (Figure 4). Consequently, the scanning campaign was successfully completed within the timescale available, resulting in a project time saving of almost 80% and a cost saving of approximately 35% for applying the ‘fast screening’ technique. With valuable information collected by the scanner, the operator has been able to perform the necessary measures to ensure the pipeline can continue to operate safely.

Wall loss detection Case study

Figure 2. Detail of a ‘fast screen’ performed by Discovery, showing characteristic defect traces. 54 | Oilfield Technology Issue 4 2021

The scanner also uses a wall loss feature in which wall loss can be detected in the inner surface of one of the outermost pipes in a pipe-in-pipe system. It is only since Discovery was released to the market that operators now have the tools to enable them to easily inspect the inside of the external pipe of a pipe-in-pipe system, making the identification of previously unknown features in a pipeline easily detectable. An example of a typical wall map produced by Discovery is provided in Figure 5. In this image, an area of slightly reduced wall thickness – likely due to preferential weld corrosion – is visible.

Additionally, general bottom-of-line corrosion can also be seen across the entire scanned section.

Flow assurance Internal deposits An operator of a pipeline system utilised the scanner in a combined integrity and flow assurance project. The operator required accurate wall thickness measurement as part of a life extension programme, and had identified three areas where they expected the highest level of corrosion or most extreme operating conditions would be. These areas were: Close to the pipeline end termination (PLET): identified for inspection as it had the highest corrosion potential. At the riser base: identified as it is the area where liquid most likely accumulates. On the riser: the thickest pipe wall.


These areas were the same as areas where volumetric wall thickness measurements had been obtained 1 year previously by using pulsed eddy current (PEC). However, clarity on the actual wall thickness values was now required. Most of the findings from the inspection were positive; the most significant wall loss in the scanned locations was found to be localised corrosion up to 14% wall thickness at the PLET. On this basis, the operator’s integrity management team was able to conclude that there was no evidence of accelerated corrosion and the life extension would be safe. The inspection, however, identified one additional and unexpected threat to the pipeline’s integrity. Material with a density consistent with barium sulfate scale had formed inside the pipe and was reducing the bore (Figure 6). Following the completion of the Discovery inspection campaign, this diagnosis was confirmed when routine maintenance was performed on the choke – which also identified a thin build-up of barium sulfate. Working with a chemical vendor, the information provided by Discovery helped the operator to identify the most suitable inhibitor for the line, to remove the costs of ineffectual remediation, reduce the build-up and help prevent new growth.

Figure 3. Discovery fast scanning.

Figure 4. Metal loss identified by fast screening, sized by full scan.


As pipelines are now required to operate in extreme conditions, the challenges facing these pipelines can be outside what is possible to inspect using conventional pipeline inspection techniques. These challenges range from high-temperature operations resulting in localised coating failure to corrosion developing under previously unknown deposits. Consequently, pipeline inspection techniques have been required to adapt to inspect them. Technologies, such as Discovery, have been developed to provide operators with valuable inspection data on the entire pipeline. This information can be used as part of a combined integrity management strategy, helping an operator to refine and improve their existing pipeline models as well as develop improved inspection and monitoring strategies, all of which can improve the operational efficiency of the pipeline.

Figure 5. Sample wall thickness map produced by Discovery.

Figure 6. Flow assurance results from the riser, riser base and PLET (left to right). Issue 4 2021 Oilfield Technology | 55

OVERCOMING DIFFICULT GEOMECHANICS IN MEXICO Viridiana Parra, Grupo R, Mexico, and Reinaldo Maldonado and Justin McLellan, Impact Fluid Solutions, show how drilling fluids were successfully deployed at a wellbore offshore Mexico that was experiencing instability and lost circulation issues.


ellbore instability issues are all too common for operators drilling high-profile deepwater wells in mechanically weak formations with depleted zones and high differential pressures. These challenging conditions can not only disrupt the drilling process – increasing costs and non-productive time (NPT) – but also limit ultimate recoveries. As a result, operators are increasingly recognising the need to take a preventative approach when drilling in environments, such as high-pressure, high-temperature (HPHT) intervals, where wellbore stability may be at risk. In a new field offshore Mexico, an operator experienced significant lost circulation while drilling an exploratory well. This prompted the operator to revisit its geomechanics strategy and drilling fluid formulation. After assessing potential solutions, the operator deployed a fluid additive that shields the wellbore during drilling to address instability issues proactively.

New field development

As part of Mexico’s 2013 energy reforms, the country’s hydrocarbon commission (CNH) has been implementing a new field development strategy designed to boost Mexico’s oil production. The primary goal was to increase reserves in shallow water basins southeast of Campeche Bay. The region is approximately 30 km (19 miles)

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northwest of the Dos Bocas marine terminal, and has an estimated sea depth of 32 m (105 ft). The new field, the Xikín field, will be referred to as the XK field in this article. Wells there were programmed to drill from the recent Pleistocene to Jurassic formations, with measured depths (MD) of more than 7000 m (22 965 ft), temperatures greater than 170˚C (338˚F) and pressures exceeding 17 000 psi.

XK field

Figure 1. XK field well review with the 14-1/2 in. openhole area in amber.

Figure 2. Comparison of drilling fluid densities in XK field.

The main characteristic of this field was the transmission of pressure into the sands, as determined by modular dynamic testers (MDTs) in surrounding fields and in Well XK-1, where optical analysers were used to measure pressures and identify fluids. The recorded pressure gradient in Well XK-1 was 0.46 psi, which is comparable to a density of 1.07 g/cm3 (water). Pressure values as high as 4158.80 psi were reached at 1700 m (5580 ft) total vertical depth (TVD). Using a one-dimensional geomechanical model of the field, also known as a mechanical earth model (1D MEM), an investigation of the drilling events in the offset wells identified the key stages of severe lost circulation, water influx and stuck drill pipe due to differential pressure (Figure 1). It was necessary to perform a sidetrack and run a contingency casing in the offset wells, resulting in 10 to 15 days of NPT per well for well control, in addition to increased equipment costs and contingency materials. The range of fluid densities in adjacent wells was also investigated. This work established the optimal drilling fluid density of 1.74 g/cm3 (14.52 lb/gal.), which would control water influx by pressure and reduce fluid loss into the formation (Figure 2).

Wellbore instability

Figure 3. Log comparison between three wells drilled in the same area.

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The design stage included an analysis of the zones with the highest risk of wellbore instability, a condition that occurs when an openhole interval fails to retain its gauge size and form and structural integrity over time – due to either mechanical or chemical issues. In the XK field, wellbore instability was found to be causing lost circulation in the intermediate section, characterised by interbedded layers of carbonates, shales and sand. Even minimal lost circulation issues should be monitored and evaluated to ensure they do not signal the beginning of more serious problems that could result in significant fluid losses, operational difficulties and NPT. To mitigate losses

efficiently and economically, it is important to assess various factors, including: Magnitude of fluid loss, ranging from seepage to significant fluid loss or even entire loss of drilling fluid. Rate of fluid loss, including any increase or decrease which – in the worst-case scenario – may signal a kick or loss of well control.


Wellbore stabilisation mechanism

To address wellbore instability and lost circulation issues, the operator evaluated available options, including managed pressure drilling (MPD), running a sacrificial casing or deploying an additive in the drilling fluid based on performance gains seen in similar sections in nearby wells. During the technology planning stage for Well XK-5, the operator was confident it had discovered the solution for drilling the intermediate section: a novel mechanism that was tested during the XK field’s exploration phase. The wellbore stabilisation technology (WST) was associated with the particle size distribution Figure 4. Drilling progress comparison of XK-5 with WST versus offset wells (without). (PSD) used in the drilling fluid formulation to seal the formation. However, it was demonstrated early in the development phase (Wells XK-3 and XK-4) Table 1. ROP comparison that PSD was not the only relevant consideration, as the nature of the particle material mattered Well Total length drilled in 14-1/2 in. openhole (m) Rig days ROP (m/d) as well. Given the constant transition zones that XK-1 2321 172 13.5 must be traversed during drilling operations, it was XK-3 2181 13 167.7 established that the particles must be adaptable to the formation’s pore openings. XK-5 1959 10 196 Based on performance tests and data obtained at the development stage, the operator decided to With the WST stabilising the wellbore and enabling drilling use the WST and deployed it successfully during the exploration within a narrow fracture gradient window, Well XK-5 experienced stage. The additive contained a blend of flexible materials no wellbore instability issues in the intermediate section. It was capable of sealing a wide range of fractures from 1 to 3000 μm, the first well in the area to experience zero drilling fluid losses, and used in low concentrations to reduce the effect on the compared to the typical 5 to 10 m3/hr lost in the intermediate equivalent circulating density (ECD). section during the exploration stage. The operator and fluid The WST operates in the ‘background’ as a low-dose additive additive provider worked together to use best practices and in the drilling fluid system. It seals each new fresh rock being deploy the WST to overcome geomechanical weakness and HPHT drilled in real-time, preventing the transmission of fluid and conditions for problem-free drilling in that complex interval. pressure that can later weaken the formation and cascade into serious wellbore instability issues. Unlike particles used in stress Conclusion caging, the WST does not penetrate the formation. Additionally, According to the drilling fluid data, no wellbore instability was the particle size is unaffected by the shearing effects of the observed, in contrast to extremely difficult scenarios for offset drilling fluid, minimising the amount of product required to wells targeting the same reservoir. Field-proven technology, such maintain the drilling fluid system. as the wellbore stabilising fluid additive, can be incorporated Result into drilling fluid systems to improve wellbore stability when According to the operator, stuck pipe in an offset well led to the confronted with varying geological formations and challenges. loss of more than 2200 m3 (13 837 bbl) of oil-based drilling fluid The industry faces increasing drilling hurdles when new and significant NPT. Well XK-1 exhibited apparent fluid invasion hydrocarbon sources are identified in more geologically along the entire section, as shown by the resistivity log, and the complicated and remote reservoirs. If unstable formation same behaviour was found in Well XK-3. behaviours are not considered at the planning stage for future For its part, Well XK-5 did not reveal any evidence of fluid drilling, wellbore integrity may be jeopardised. invasion in the same area. That corresponds to the physical Furthermore, the method added wellbore strength to weak events that occurred at the surface, as no drilling fluid was rocks, allowing the drilling operation to proceed as planned. As reported to have been lost during the drilling of that section a result, the operator significantly reduced the NPT associated (Figure 3). Notably, Wells XK-3 and XK-5 were just 30 m apart with lost circulation, stuck pipe and well instability, allowing for from each other (Figure 4, Table 1). the delivery of a high-quality producing well.

Issue 4 2021 Oilfield Technology | 59

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Dr Helmut Schnabl, Siemens Energy, Austria, examines several ready-to-deploy technologies that can facilitate autonomous oilfield operations.


hen the global COVID-19 pandemic induced the ‘Great Pause’ in transportation during the spring of 2020, oil and gas prices fell to historic lows. Once again, after suffering a sharp price drop in 2016 – but not nearly as precipitous as 2020 – producers were reminded of the imperative to drive cost out of their operations; ultimately, they will need to achieve the lowest cost production possible, especially in mature fields where their wells are operating under artificial lifts. How will they do this? With technology, of course. Or (more descriptively) with sustainable, fully autonomous, closed-loop operation of their fields, using technologies that enable them to keep production wells operating most efficiently and that all but eliminate manual oversight and interventions (Figure 1). Of course, autonomous oilfield operations will not happen overnight. Instead, they will occur in a step-wise evolution as a number of key technologies come together to make this

operating model viable. These technologies include edge and cloud computing, data analytics, computer vision and the use of trained machine learning (ML) and artificial intelligence (AI) algorithms to conduct soft sensing of an operating well’s key performance indicators (KPIs) in real-time over Internet of Things (IoT) connectivity. Innovative and cost-effective digital solutions for field operations, such as that which the intelligent combination of these technologies makes possible, can improve production, lower maintenance costs and reduce intervention and repair costs. This article will explain how operators can achieve these benefits via autonomous well control (AWC), virtual flow metering (VFM) and visual well surveillance, and show how these technology solutions are available for deployment today, not some far-off tomorrow. In this article, the major components of this concept will be highlighted.

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Operationally, the AWC solution combines situational awareness, autonomous optimisation and effective real-time interaction with human operations personnel as a means for sustainable production efficiency and optimisation. Soft sensing is instrumental in the technology’s operation. Essentially, it derives an SRP’s KPI values from measured parameters. For example, it is possible to calculate load and inclination values of the crank arm from Figure 1. Closing the loop from field to enterprise – optimising production towards business targets. the effective power consumption and voltage values of the pump motor. It thus enables sensorless monitoring of surface dynacards. Other examples are detecting a slipping belt or deriving a well’s multiphase flow composition from existing well sensors instead of installing additional instrumentation for those purposes – in effect, using VFM seamlessly integrated with AWC.

Modular hardware and software – ready for greenfield and brownfield The AWC solution can be deployed as a plug-and-play solution, including the complete electrification, smart automation and edge computing components in one single cabinet or integrated with existing components (Figure 2). Furthermore, because of its modular nature, it can also be integrated (e.g. as a panel solution) with existing equipment. As such, it can address greenfield, brownfield and brownfield retrofit scenarios. Smart motor control or VFD: this includes motor management, safety and automation functionality, and power measurement. Edge computing: the iPC provides for data gathering, soft sensing, AI-enabled analytics, smart alarming and a communications interface. The local real-time processing enables real-time control and optimising of the pump. Connectivity and OT/IT integration: an autonomous well’s controls can connect to a SCADA system for monitoring and to a data historian while also connecting to the edge iPC.


Figure 2. AWC cabinet with industrial PC, smart motor control and other components shown.


Autonomous well control

Siemens Energy has taken the first step towards autonomous oilfield operations with several successful pilot AWC installations at a major European producer’s fields, using most of the aforementioned technologies. So far, these pilot deployments have focused on sucker rod pumping (SRP) models because they predominate in providing artificial lift to mature, low-pressure onshore wells. However, there is confidence that the application can be adapted to other artificial lift technologies, either onshore or offshore. The company’s AWC solution is available with little or no installation disruption to existing SRP well infrastructures and on a pay-as-you-go subscription basis, thereby eliminating CAPEX and the costs of maintenance and upgrades.

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Autonomous operations concept SIWELL provides a comprehensive operations concept that integrates smart alarming, root cause analysis, pump off control and speed optimisation for monitoring and optimising the pump. Based on the analysis of a current situation – including measurements from instrumentation, soft sensing and the classification of dynacards – the AWC action layer can take autonomous action or even inform the operators on necessary interventions via smart alarming that includes root cause analysis (Figure 3).

IoT-enabled user interface SIWELL comes with a web-based user interface (HMI) that can be installed on any mobile device, laptop or standard PC. By having an appropriate, secure network structure in the back it is possible for an operator to access their wells from wherever they are (Figure 4). With this concept, it is no longer necessary to apply traditional screens or panels on the cabinet (although they can still be installed and connected to the nanobox in parallel to the remote HMI). This offers operator personnel secure remote access to all well/lift data and KPIs, whether they are working in a central control room or remotely.

Figure 3. Moving from hardware-driven measurement to soft sensing.

Quantifiable benefits The AWC solution was designed with a clear focus on reducing cost and improving the efficiency of pump operations. It was found that the system could potentially improve four critical areas of operations, as shown in Table 1.

VFM for continuous multiphase flow measurement

Accurate multiphase flow rate measurements of Figure 4. The IoT-enabled HMI allows monitoring and control of a pump from any location. individual production wells are indispensable tools Table 1. Four areas of potential operational improvement via autonomous well for production optimisation and accurate production back control allocation in oil and gas fields. Currently, there are two primary, Business drivers/improvement Potential industry-accepted solutions for providing such measurements. Expected benefit lever improvement One is using test separators, fixed or mobile models. The other is Increased production, using multiphase flow meters. Production optimisation (boe) 0.5 – 3% reduced cost per barrel While each of these approaches has pros and cons, they Increased availability, both require hardware installations that can require regular MTBF increase (hrs) increased production 10 – 20% maintenance and periodic calibration to ensure the integrity of over year their data. This can limit the applicability of physical metering Reduction of production Operator reaction time (hrs) 5 – 15% devices due to possible transportation issues, available losses installation space, security considerations and high costs, both Well intervention/roundtrip Reduced number of well CAPEX and OPEX. 3 – 5% optimisation interventions, roundtrips Simply put, a VFM is a soft sensor that detects multiphase flow composition and volume using existing instrumentation data (Figure 5). Today’s VFM concepts are mainly deployed in flow rates (estimating rates at the current time instant) but also to back-up roles. VFM models can be classified as hydrodynamical forecast future flow rates. or data-driven. One crucial difference between hydrodynamical Recent developments, however, could change the future and data-driven VFMs is the ability of the latter not only to predict of VFMs, thus changing the future of the industry. For example,

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Siemens Energy successfully implemented a data-driven VFM pilot project to prove the concept for primary flow metering in wells using both electrical submersible pump (ESP) and SRP artificial lifts. The results show that AI algorithms used in the VFM solution can be

taught via ML to derive a correlation between well test flow rates and wellhead measurements. This enables the AI algorithms to calculate production rates at any time between well tests within an accuracy of +/- 5% for each fluid phase – oil, gas and water.

From regular well tests to continuous flow measurement and optimisation of production In short, optimising well production continuously means the well must be constantly monitored and its flow measured. VFM data-driven measurement methods are fast, so they can be applied in real-time with AI-based analytics conducted at the edge (i.e. the well site). With a network of VFM-facilitated wells, an E&P operator can also gain enterprise-wide visibility of all wells by uploading relevant KPIs to the cloud from the edge. It has been shown that VFMs can overcome the difference of well test and flow line conditions and predict sufficiently accurate rates. Operators can gain greater visibility as well as analytic capabilities while saving the CAPEX and OPEX of physical metering.

Video surveillance for continuous well monitoring and early leak detection

Figure 5. Moving from hardware-driven measurement to soft sensing.

Health conditions of SRPs, often scattered in remote areas, are traditionally monitored with lease pumpers visiting each well pad, typically once a day. The problem with this

Figure 6. Production optimisation dashboard with an integrated view on multi-well, multi-phase virtual flow meter.

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manual approach is that any issue arising after the visit will have to wait until the next day’s visit to be detected and mitigated, or remedied. For example, consider a common scenario: a pump stops working shortly after a site visit. This will not be noticed for at least 24 hours, causing a loss of production. An even worse consequence could be spillage at the stuffing box shortly after a site visit, an incident that might result in substantial clean-up costs, potential environmental compliance infractions and reputational damage for the operator. So how can these challenges be addressed using technology? Siemens Energy has introduced an easily installed, low-cost Vision4SRP video surveillance system that offers operators an affordable way to visually monitor their remote SRPs using their smartphones, tablets, laptops or desktop PCs. It combines modern IoT technologies, computer vision and 3G or 4G connectivity. Its components include a solar-powered, battery backed-up camera; an edge data processing device with minimal power consumption that reduces data traffic by preprocessing at the edge; and an intuitive cloud interface for the user. Installation is simple. No site wiring is required; the camera just needs to be mounted in the safe area where the stuffing box and perhaps some gauges can be monitored. Because lease pumpers are intended to be the primary users of this solution, essential features have been designed to provide them with the essential operating SRP information while making the Vision4SRP interface intuitive to use with actionable data displayed. Key features include: Leak detection algorithm: stuffing box leaks are detected with high confidence by analysing the degree of oil contamination on the polished rod applying computer vision technology.



Edge processing minimises bandwidth and data transmission costs while improving alarm integrity. Health monitor: by monitoring the pump’s frequency and ‘reading’ existing analogue gauges, the health and integrity of the well site can be confirmed. Photo request: to double-check an alarm raised by the leak detection algorithm or health monitor, pumpers can request a most recent photo for their own visual inspection. Intuitive pump fleet overview: regardless of the web browser or smartphone in use, pumpers will always have an overview of the pump fleet at their fingertips.

Leveraging the power of modern cloud systems, such as Microsoft Azure, and web-browser capable end-devices, all information is available at any time to the user. Access rights ensure that data is only accessible by the operator’s authorised personnel. For example, if Vision4SRP detects a deviation in the nodding frequency of a pump, a warning sign appears for that specific pump on the overview screen.

Next steps towards autonomous oilfield operations

In mature oilfields where artificial lifts are in use and boe daily output is often measured in single or double digits, the economics of technology-enabled, fully autonomous operations can be compelling (Figure 6). Relevant technologies, such as those discussed in this article, can be combined in ways that not only can help E&P operators to cost-effectively optimise and monitor conditions of SRP-equipped wells but also to provide fleet management and enterprise-wide operational visibility. While fully autonomous oilfields may still be on the roadmap for operators, solutions are becoming available that can make autonomous operations a reality today.

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Back to basics

Mark Niblett, Weatherford, USA, emphasises the need to return to the basics of safety in a new 2021 paradigm.


he COVID-19 pandemic caused significant changes regarding health and safety, which everyone endured. On top of all the precautions already observed, companies such as Weatherford now have strict procedures regarding even the simple things, such as riding an elevator, for example. COVID-19 protocols included new workspace and office procedures, but also covered safety in the field, business continuity, a work-from-home policy and the return-tothe-workplace policy. This was all followed by the return of

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working-from-home policies – all part of ‘the new normal.’ Unchartered territory was an understatement. And no matter what was pre-planned in the playbook, this was all new, very real, and all on a new playing field no one had ever seen. However, through all these changes, companies have not only survived, but they have learned a few things. And now, it is time to get back to the basics of improving employees’ well-being and operational safety, as well as better supporting the mental fatigue being witnessed throughout the industry. Before the pandemic

changed the landscape, some would have struggled to appreciate some of the advancements that have been made with seemingly basic protocols around contagions and the measures people would take to protect themselves; e.g. the wearing of masks during travel or while in heavily populated areas.

The new (ever-changing) norm

Attempting to keep up with and adhere to all the new policies that have been written around the pandemic can be confusing,

overwhelming and frustrating. But what it should really boil down to is common sense – it does not need to be overthought or made more complicated. As an example, expecting people to comply with anything extraordinary in an already disrupted daily routine can be a considerable challenge. Simply telling people to just ‘do it’ is not enough – it needs to be expressed why these measures are important, whilst always keeping people’s well-being at the forefront of any decision. The reality is that simple basic safety

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policies protect and save lives. Following the mask mandate, for example, may seem like a simple change in a routine for a few days, but continued systemic behaviour change is difficult. However, the pure fact is that these precautions work, and it is the job of safety professionals to ensure everyone complies.

the leaders? In the safety world, it means pragmatism – leading by example, communicating best practices and fundamentally making safety a top priority of the corporate culture. If leaders are not demonstrating passion and comprehensive buy-in, it is unrealistic to expect a culture to flow deep into all facets of an organisation.

Back to basics

Making the most of remote work: breaking new barriers

At Weatherford, the company is not only focused heavily on returning to the simple essentials of safety, but it is following through with this concept: ‘Safety starts with management.’ The company believes, whether it is COVID-related or not, that safety policies are in existence because they work. Fundamentally, basic safety is everyone’s business. However, how does one get everyone to really believe in safety policies and follow them? Staying accountable is one thing, but it must not be forgotten that driving systemic behavioural change and the understanding of accountability is all about leadership. Furthermore, safety starts, but never ends, with management and the organisation’s top bench. But what does that truly mean to

Many industries have fully embraced working from home, while others (such as the oil and gas sector) could take advantage of evolving technologies by assimilating them further into their everyday actions. This time represents an outstanding opportunity for the oil and gas industry to rethink the values of remote access. Traditionally, oil and gas is a hands-on industry. And it seems there is a notion that remote work is impractical or slow to adopt any field operations to a remote setting. This outlook contends that it would be difficult to imagine all rig and drilling procedures being performed remotely; never mind that it is slow to adopt change – especially new processes. Other reasons operators may think twice about switching to remote operations are concerns over consistency and safety during an emergency. Any deficiency in a direct response to risk could be construed as a larger problem if there is complete reliance on a remote arrangement. However, it is true that the oil and gas industry has been performing remote operations for many years. Centralised control rooms have already successfully removed hands from the dangers of rigs and its equipment. In many cases, moving forward to a fully remote system could be as simple as adding an additional internet connection.

An ever-changing environment Figure 1. By applying artificial intelligence at every stage from pipe

manufacturing to well installation, Vero improves connection make-up efficiency and eliminates the inevitable errors associated with human judgement during the connection process.

One thing that is certain is that the COVID-19 pandemic has emphasised that every aspect of the oil and gas industry must improve its flexibility and stamina. The continuously shifting circumstances have forced operators to rethink almost every aspect of how they perform any task. It is during times of ambiguity that decision-makers are driven to not only re-evaluate production strategies, but also consider any logistic effects triggered by the circumstances around them. Of course, in regards to the pandemic, social distancing policies have impacted personnel workflows across the board. Remote operations have further reduced onsite personnel in hazardous areas with the introduction of many digitalised and automated processes that allow 100% hands-free activities which once required large crews on the platforms. In terms of accepting remote controls and communications, it is often believed to hamper work progress. However, remote access can often be more effective than in-person communication. Remote access allows teams to gather from many locations – allowing access to experts and teams with specific knowledge for unique circumstances that emerge infield. This not only increases precision but also speed – enabling operators with better decision-making and improved operational efficiency for a wider array of situations.

Advancements in remote technology

Figure 2. AccuView is an integral part of the company’s drive for industry-wide digitalisation to save time, add value and increase profitability for any well.

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As the industry has continued adapting technologies to these new safety precautions, one thing is becoming clear – some of these innovations and offerings have really come into their own through COVID-19. Several examples have revealed tremendous value as well as safety advantages, while following social distance regulations and travel restrictions imposed by the pandemic.

Case study: Kazakhstan Weatherford technologies, such as Vero® automated connection integrity, have delivered over US$500 000 in rig time savings while making up over 15 000 connections in Kazakhstan. This technology has also enhanced safety by decreasing the number of personnel at the rig site and removing numbers from the red zone.

Case study: Australia In Australia, Vero also eliminated exposure and reduced personnel on board, thus mitigating the risks associated with conventional tubular running. Furthermore, automated makeup and evaluation software enabled operations to continue, even during the most challenging conditions.

Case study: Yemen Weatherford remotely deployed a 9 5/8 in. whipstock system in Yemen using its AccuViewTM real-time remote-support system. The sidetrack was installed without the need for personnel during ongoing COVID-19 travel restrictions. This technology allowed the customer to successfully conclude workover operations while avoiding additional delays and associated rig costs due to the pandemic restrictions.

Case study: Bengal, India The benefits of AccuView were also realised in the deepwater Bay of Bengal, off the shore of India, where Weatherford liner-running experts in Houston and Abu Dhabi managed the installation of a close-tolerance liner system using around-the-clock support in order to maintain strict compliance with social distancing, as well as other COVID-19 restrictions.

Case study: Colombia In Colombia, the Weatherford ForeSite® production optimisation platform boosted production by 5% during its Phase-One rollout. The result was US$3.25 million/yr in incremental revenue, all while reducing personnel at the rig site by way of intelligent algorithms and remote monitoring. At the same time, the operator was able to avert a major issue when their asset was impacted by a power outage. They were able to restart all their wells remotely using ForeSite without going to the field.

of fully remote-operated oilfields. Until then, operators should begin considering solutions currently offered and begin employing remote improvements in the interim. Furthermore, some remote technologies are easier to implement for certain processes. Solids management, for example, is more consistently produced and transported, which consequently makes monitoring and transport performance easier without dependence on sensors, and therefore simplifies a transition to remote processes. These systems provide low-profile, low-cost modifications that are easily applied to existing wells. Operators now have proven solutions that can improve and sustain production performance using fully digital, fully remote applications.

Accountability If one fails individually, the organisation fails as a whole. There is no question the last 2 years have presented challenges that are difficult to navigate. However, front-line safety leaders should be all be urged to get back to the basics, put on their personal protective equipment, walk the yards and rig sites, engage in the operational environments that they work in and be the example. They should encourage all their teams to deny complacency, adopt the applicable accountability matrix and exercise individual rights of commitment intervention. Safety leaders can empower workers and drive a new safety culture by reminding employees of their Stop-Work authority and assuring them that it is OK to be curious and ask “Why?” Together, employees can be made to feel safe, supported and encouraged to do so themselves within their peer groups. Everything starts with a company’s culture and its management being committed to supporting its global strengths and people – safety is not a suggestion.


Going forward, especially in the wake of changes caused by the COVID-19 pandemic, the remote control improvements outlined in this article can inspire and accelerate safer, hands-free improvements toward a more productive oilfield environment – spawned by a more interconnected, digitalised oil and gas industry that includes the amazing abilities of remote control.

Case study: North America ForeSite Edge, the company’s next generation controller for production, was utilised by an operator in North America to run their wells autonomously to boost production by 6%, reduce wellsite visits by 70% and reduce failures by 15% in the first 6 months of deploying the solution. It is clear that the digitalisation of oil and gas operations offers many advantages for the industry. Improvements include more than production efficiencies and safety improvements. But what can operators do to take advantage of these features and move to remote applications faster?

Implementing remote application Baby steps Every day, new and more advanced remote technologies are advancing the capabilities of the oil and gas industry. However, it will take many years for the successful adoption

Figure 3. The ForeSite production optimisation platform delivers insight that enhances production, maximises uptime and improves personnel efficiency.

Issue 4 2021 Oilfield Technology | 69

Protecting against tough upstream conditions

70 |

M.B. Sutherland, Magid, USA, discusses the importance of safety, hydration and suitable protection equipment when working on oil rigs.


ife on an oil rig is dirty, risky and hot. Whilst many of the risks have long been considered part of the job, new impact protection technologies – as well as clearer guidelines for heat safety and better body cooling personal protection equipment (PPE) technologies – are making it easier to keep workers safe.

Impact protection in an oily environment

The Bureau of Labor Statistics reports that ‘struck by object’ injuries are the most common in upstream oil and gas work, followed by ‘caught in object’, ‘equipment’, or ‘material injuries’. As teams of workers carry out the rapid work of connecting lengths of pipe, threading, bolting, cooling and generally handling heavy objects in a slippery environment, hand injuries are a constant danger. The first step to protecting workers’ hands is proper training and safety reminders, but the availability of better equipment may also be a difference-maker in reducing the number of injuries. The advent of more flexible and comfortable impact-resistant gloves (along with impact standards from the American National Standards Institute [ANSI] that make it easier to understand how protective a glove may be) have made oil extraction workers safer from pinch, crush and impact injuries. However, issues with poor grip and gloves lasting as little as an hour before becoming completely saturated – along with skin irritation from working with wet hands – remain a problem. The foam nitrile coatings traditionally used on impact gloves have been useful to deflect oils and coolants, but this often made for

a slippery grip. Sandy nitrile absorbed oil and liquid, although this absorption went through to workers’ hands, keeping them wet and uncomfortable and compromising grip from inside the glove. Today, new technology from Magid combines the best of both worlds with a nitrile base that deflects oil to keep hands dry, followed by an outer layer that absorbs oil to maintain grip. This combination also provides 54 – 61% higher abrasion resistance than standard coatings, which may cut down on frequent glove replacement. Adding a layer of flexible, impact-resistant thermoplastic rubber (TPR) on the back provides a level of protection that is fit for work on an oil rig.

Plan ahead for safety in a hot environment

While it is important to focus on the obvious upstream hazards posed by heavy objects, moving parts and working at heights, there is another far less visible danger that must be taken seriously: heat. Temperatures on an oil rig can reach well above 100˚F (37.7˚C), making them prime locations for heat illness, including deadly heat stroke. This too-common injury is 100% preventable, which is particularly tragic given that the Bureau of Labor Statistics estimates 11 workers are seriously injured or die from heat stroke every day, disrupting thousands of lives and costing businesses an average of over US$54 000 per incident. The key to keeping people safe is preparation. This can take several forms, all of which rely on one another to make a real difference on a rig.

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Heat measurement, acclimatisation and mitigation


Measurement – relying on the weather report to gauge jobsite conditions may provide an inaccurate idea of the heat workers will experience. A small and inexpensive piece of equipment called a Wet Bulb Globe Temperature (WBGT) monitor can be used to measure the real temperature on jobsites, otherwise



Figure 1. New coating technologies for oil grip and better abrasion resistance.

known as a site’s microclimate. A microclimate may vary from area to area on the same site depending on humidity, hot equipment, heat from direct sun exposure and the amount of wind an area gets. A WBGT monitor helps to account for high humidity, which slows down the natural process of sweat evaporation and prevents the body from cooling properly. However, temperature alone is not the only measure to consider. Many also fail to realise that, if the work is hard enough, heat stroke can happen even on a cloudy and warm day; it does not have to be hot and sunny for issues to occur. Acclimatisation – the US Occupational Safety and Health Administration (OSHA) reports that nearly 50% of heat-related deaths happen on a worker’s first day at work and more than 70% happen within their first week. Many of these deaths might be prevented through heat acclimatisation, so a worker’s day could be shortened to just a few hours and time could be gradually lengthened in the first week, rather than starting full-time. This would allow a worker’s body to develop physiological defences to the heat, such as a lower heart rate and an increased rate of sweating. Mitigation – even for acclimatised workers, heat mitigation strategies are an integral part of preventing heat illness. This means increasing break times for particularly hot days and making sure air-conditioned or at least shaded areas are provided for breaks and rest periods. The hotter the environment, the more frequently rest and hydration breaks need to be provided.

Heat illness training and reminders For individual workers, proper training is the base on which a heat safety programme can be built. Teaching workers to understand heat illness – including how they can prepare themselves for hot conditions, the signs of heat illness to look out for in themselves and each other, and what to do in case of heat illness – are the first steps to keeping everyone safe in the heat. This includes formal training classes, but it should also take the form of regular reminders such as posted instructions and short safety videos that can be shown across the jobsite. Checklists for prevention and treatment, or flyers in bathrooms that allow workers to gauge their hydration level through urine colour, are all simple ways to keep heat safety at the forefront of everyone’s minds.


Figure 2. New coating technologies combined with impact resistance (shown Magid TRXDXG49).

Figure 3. Posted reminders keep safety lessons on workers’ minds.

72 | Oilfield Technology Issue 4 2021

Many consider hydration as something to do when thirsty, but for workers toiling on a hot jobsite all day, drinking when thirsty is not enough. It is important to ensure that employees know that they need to:


Pre-hydrate the night before their shift. Hydrate thoroughly throughout their workday. Hydrate after work.

Alcohol consumption and medications for conditions such as blood pressure regulation, depression, and colds and allergies may make heat illness more likely by impairing the body’s ability to regulate core temperature. Proper hydration can be encouraged by providing icy cold water and electrolyte-replacing beverages close to work areas at all times. Icy cold drinks are important, as even a thirsty worker might not drink enough to stay hydrated if the water is warm and unpalatable. Cold drinks also help to lower body temperature, staving off heat illness as a result. However, it is important to remember that hydration alone does not prevent heat illness. Even a fully hydrated worker can experience heat illness up to and including deadly heat stroke if they are working hard through the day and their bodies are unable to release heat faster than they are producing it. This is where body cooling PPE comes in.

Light PPE and body cooling gear for the heat PPE that is heavier than necessary should be avoided, and each worker should be outfitted with the lightest PPE possible to discourage the removal of gear to cool off during the job – the PPE must, of course, still protect them properly. It is important to remind workers whose jobs require PPE that may trap heat against large parts of their bodies – such as overalls, jackets, or protective sleeves – to be especially vigilant about hydration and to watch for signs of heat illness. Body cooling PPE has come a long way in the last few years. Chemically treated towels and bandanas that become hot moisture traps after just a short while have been replaced by new cooling technology. For example, Magid Cool® powered by Mission® HydroActive™ wear utilises a special fabric weave to harness the power of natural evaporation. These garments can be activated with any temperature of water – even very hot water that has been sitting out in the sun – yet they cool down to as low as 30˚F below average body temperature in less than a minute, and they stay cool for as long as 2 hours. The power and portability have immensely increased options for cooling workers on the job, as these garments allow them to cool down anytime with almost any water source and not just when they have access to cold water.

Emergency preparation Even with all of these measures in place, it is still possible that workers will push themselves too far, the heat will be more intense

than realised or a worker will have an underlying heath condition that makes them more susceptible. Many factors may result in efforts to avoid heat illness on the jobsite falling short. For these cases, it is critical to have an emergency plan that every worker knows, and to have the proper measures in place to save a life. Heat stroke is much more damaging than many know. When a worker suffers heat stroke, they have 30 minutes to reduce their core temperature down to a safe level before permanent organ damage and even death can result. According to Dr Douglas Casa, CEO of the University of Connecticut-based Korey Stringer Institute (KSI), heat stroke can damage different organs in different people. Some people may experience kidney or liver failure; some have massive muscle issues or brain damage; some are left permanently unable to stand hot conditions. In any of these cases, a healthy person may become disabled with permanent and life-altering complications. Many often call the emergency services and wait for help to arrive when a worker is suffering heat stroke. Whilst this is the correct thing to do, it is important to also start lowering the worker’s body temperature immediately. If proper body cooling has not been administered, it is possible for the affected person to suffer damage or death from heat stroke either while waiting for an ambulance or whilst on the way to the hospital. The ideal way to do this is through cold water immersion and continually adding cool water and ice to bring down the worker’s internal temperature. If this is not practical on the jobsite, KSI and the National Heat Safety Coalition recommend keeping ice boxes on hand full of towels, water and ice that can be applied all over the worker’s body, rotating in new towels from the ice box in order to keep applying the coldest ones possible whilst waiting for help to arrive.


There is no one solution to preventing heat illness on the job or anywhere else, but consistently using all of the measures mentioned here will make it much less likely that workers will suffer heat illness. None of it is especially difficult or costly, particularly compared to the potential consequences of not taking these precautions. The proper combination of training, reminders, body cooling gear, increased breaks and hydration and good emergency preparation are all integral parts of an effective heat safety strategy. Whether protecting workers’ hands from pinches and impacts or battling the dangers of heat illness and anything else that can be hazardous in the tough job of oil extraction, innovations in PPE are advancing all the time. It is important to stay informed about the newest products and technologies to keep workers as safe as they can be, no matter what the conditions.

Figure 4. Different cooling garments protect in different applications.

Issue 4 2021 Oilfield Technology | 73

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