Oilfield Technology - September/October 2020

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Contents 03 Comment

Sept/Oct 2020

Volume 13 Issue 05

24 A sweet solution Tom Swanson, Solugen, USA, discusses a novel oxidant and sugar derivative, designed to improve saltwater injection challenges.

05 World news 08 Down for the count?

29 Development down under

Oilfield Technology correspondent, Gordon Cope, reports that North American oil and gas has taken a dreadful thrashing, but there are signs that it is already starting to shrug off the worst.

Hans Sturm, Curtiss-Wright EST Group, USA, presents a novel isolation approach designed to bring speed, safety, and security to pipeline valve replacement.

12 On the turn

31 The value of a trusted device

Benoit Deschamps and Nicolas Sluys, Rubicon Oilfield International, explore a new rotational function of the drill string that combines technology developments with a well life cycle solutions approach.

Brent McAdams, OleumTech Corp., USA, explains how well-chosen automatic tank gauging technology can increase the oilfield’s overall production.

17 Encapsulating the problem

36 Flattening the forgetting curve

Dr Ellie Mavredaki and Sam Toscano, SUEZ – Water Technologies & Solutions, investigate the advances in encapsulated treatment technologies that mitigate scale formation.

Eugene Sweeney, Well Control School, USA, investigates the educational methods being used to instil retention-driven well control skills in the workforce.

20 Disrupting traditional tracing trajectories Dr Sudiptya Banerjee, Tracerco, analyses the development of microencapsulated polymer tracer rods.

FLATTENING Eugene Sweeney, Well Control School, USA, investigates the educational methods being used to instil retention-driven well control skills in the workforce.



CURVE Front cover



t does not take much imagination to envision a future where automation and artificial intelligence (AI) make (or at least ensure) many of the critical decisions to maintain proper well control. Such a future remains distant at best however. Until then, robust practices carried out by highly trained, competent people continue to be the most important well control barrier for the foreseeable future. Well Control School (WCS) has developed a system technology to strengthen and ensure this barrier. The newlydeveloped SMART knowledge retention programme combines e-learning with instructor-led training to instil retention-driven well control skills and knowledge training.

Strengthening the well control practice barrier What does a Prussian soldier-turned-psychologist, who died more than 100 years ago, have to do with ensuring healthy well control barriers in today’s fields? More than one would think. While people have long known that the mind is a complex machine, constantly learning, remembering and forgetting information, it was Hermann Ebbinghaus who first quantified some of the most important nuances of how our minds learn and remember. After fighting in the Franco-Prussian War in 1870, Ebbinghaus became a giant in the infant field of psychology and cognitive science. Some of his cognitive paradoxes, such as the example shown in Figure 1, have become familiar to many. Ebbinghaus was also the first to discover the theory commonly known as the ‘learning curve’. Most relevant for the purposes of this article however is his discovery of the ‘forgetting curve’. Most people are familiar with the concept of the learning curve: knowledge is gained over time or a task is learned after repetition. A steep learning curve usually means a task is difficult to learn with rapid progress or knowledge attained at the beginning. The forgetting curve describes the exponential loss of information that has been learned. Figure 2 shows a representation of that loss over time. Ebbinghaus showed that learners forget 50% of what they just learned within an hour, 70% within a day and a 90% in a month. The critical decision-makers, both at the rig site as well as those that direct and engineer actions from the office, comprise the frontline defence for ensuring crews maintain well control and safe operations. This human barrier is critical.

The strength of this barrier is verified every two years through the process of well control certification. Would confirming other critical barriers, such as blowout preventer (BOP) testing, only every 2 years ever be considered? The question becomes even more daunting when the forgetting curve is considered. How can it be known for certain that people are going to make the right critical decision during a high-intensity situation, say 18 months after they have been certified when they may have forgotten more than 90% of what they had learned? Luckily, there is an answer. This knowledge decline can be limited by leveraging another Ebbinghaus discovery, known as ‘cognitive savings’. Ebbinghaus quantified the phenomenon of subconscious knowledge, stating that knowledge is retained in the subconscious even if it is not readily available to the conscious mind. The ‘savings’ mean that when something is relearnt, it is achieved more quickly, i.e. the new learning curve is shorter. This has the additional effect of flattening the forgetting curve when relearning or refreshing memore (Figure 3). Based on cognitive savings, interval repetition becomes the best method for reducing ‘skill fade’.

Using technology to combat skill fade WCS began development of the programme with the specific scope to find the best technological solution to well control learning retention. By doing so, the aim is to ensure that when a critical decision is made or planned even 18 months after an employee has gone through certification, he or she will perform the task with the same skills displayed immediately after successful completion of well control training. The basis of design was to address skill fade while implementing the most effective, proven e-learning techniques. Among these are: Learning platforms with optimal module sizes – studies have shown that brief, targeted learning modules are better retained than longer ones. Optional assessments – users assimilate key takeaways more efficiently through use of assessments. These help to move information from working memory to long-term memory. Cater to different learning behaviours through a multimedia approach – all people learn differently. For example, some retain



Built upon a strong and proven expertise in complex extended reach drilling (ERD) well construction challenges, the RotationABILITY concept opens new perspectives on the value that can be extracted from drill string or casing rotation. Selectively rotating the string offers greater operational efficiency and the potential to significantly increase reservoir exposition capabilities.


39 The sound of safety Yasuyuki Kawasumi, Yokogawa Electrical Corp., Japan, explains why continuous monitoring of noise levels in upstream facilities is a critical step towards improving hearing conservation.

42 Downhole tool review Oilfield Technology presents an overview of some of the recent developments in downhole tool technologies and services that are available to the upstream oil and gas industry.


O 2020 i dd 1

16/09/2020 08 49

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Copyright Palladian Publications Ltd 2020. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

Get CuddAssured™ - Engineering the Future of Well Control In response to the industry’s recognition of the actual cost of gaps in well control practices, we developed CuddAssured, a 21st-century comprehensive well control program that strengthens all your well control barriers, resulting in fewer incidents, at a reduced severity, for safer and more reliable operations. Designed by the premier industry leaders in emergency response, well control engineering, and well control training, CuddAssured provides a comprehensive well control program that ensures crews avoid costly well control mistakes.

| go to cuddwellcontrol.com to learn more.

Comment Laura Dean, Editor


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Editorial Managing Editor: James Little


he three most immediate basic needs for human beings are: food/water, shelter and clothing. Overtime this list has grown to include sanitation, education and healthcare. Depending on the agency being asked, the list of basic needs can vary but one unexpected basic need that has become intrinsic in the modern world, particularly during the current pandemic, is the internet. In May 2020, while lockdown was still in almost full effect here in the UK, I moved house. This move had been pushed back three times in the space of two months, and the primary factor was simply that I was unable to get an internet connection set up in my new residence – something I could not live, or at least work, without. With lockdowns being put into effect around the world, millions of people were forced out of their daily routines and companies had to rapidly adapt their processes in order to allow employees to work from home where possible. Combining the impact of the COVID-19 pandemic with tumultuous oil markets has left cause for concern over the wellbeing of the workforce and the future of oil and gas operations. In order for companies to survive and thrive, safely digitalising procedures within the industry has become essential. The Fourth Industrial Revolution (or Industry 4.0) is the ongoing automation of traditional industrial practices, using modern smart technology. Over the course of the last six months particularly – though it has been used increasing throughout the industry over the last decade – there has been an unprecedented rise in smart technology applications. In September 2020, the World Economic Forum recognised Saudi Aramco’s Khurais oil facility as a leader in the adoption and integration of cutting-edge technologies of the Fourth Industrial Revolution. This recognition was announced one year to the day that the Khurais oilfield was attacked by drones in 2019, demonstrating the significance of this achievement, even under the most difficult challenges. Offshore, Halliburton has been awarded a contract on four of PTTEP’s fields, to design and implement a series of digital transformation projects as part of the company’s Advanced Production Excellence (APEX) Initiative. The project includes short-term production planning and optimisation, flow assurance monitoring and control, sand production monitoring and control, condensate stabilisation optimisation, CO2 membrane optimisation, fuel gas optimisation and processing facilities performance monitoring and analysis. Further west, in the UK North Sea, Neptune Energy have announced their partnership with Eserv, a 3D technology specialist, as part of the ongoing digitalisation of Neptune’s Cygnus gas platform as well as other assets. Using 3D and artificial intelligence (AI) technologies, the companies have created a digital map of all three bridge-linked jackets, enabling asset integrity issues to be detected early, which in turn helped Neptune plan fabric maintenance on Cygnus. Around the world, companies are making extraordinary moves to digitalise their assets in order to ensure their performance even in the most dramatic of circumstances. In this month’s issue, Oilfield Technology contains a range of technical articles on digitalisation within the industry, among other hot topic features. Furthermore, this issue also contains our Downhole Tools review, which presents an overview of the recent developments in downhole tool technologies and services. To read more, turn to p. 42.


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September/October 2020 Oilfield Technology | 3

Organic Oil Recovery The Future of Enhanced Oil Recovery Organic Oil Recovery

organicoilrecovery.com hunting-intl.com titanoilrecovery.com

World news Exploration operations begin at Keskesi East-1 well offshore Suriname Apache Corp. and Total have provided an update to the technical evaluation of the Kwaskwasi-1 discovery well offshore Suriname. Kwaskwasi-1 discovered hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. The well encountered 278 m (912 ft) of net oil and volatile oil/gas condensate pay. The shallower Campanian interval contains 63 m (207 ft) of net oil pay and 86 m (282 ft) of net volatile oil/gas condensate pay. The Santonian interval contains 129 m (423 ft) of net pay. Fluid samples from the Campanian validated the presence of oil with API gravities between 34 and 43°. The Noble Sam Croft drillship has gathered reservoir and other technical data in the Santonian. The company was able to successfully retrieve rotary sidewall cores but was unable to collect representative fluid samples from the reservoir due to conditions caused by cementing operations, which were required to mitigate increased pressure below the base of the Santonian formation. Hydrocarbon shows were observed in the Santonian reservoirs, and the results of the formation evaluation indicate the presence of oil. The Noble Sam Croft has commenced operations at the Keskesi East-1 exploration well approximately 14 km (9 miles) southeast of Sapakara West-1. The Keskesi well will test upper Cretaceous targets in the Campanian and Santonian. Apache holds a 50% working interest in Block 58 and will continue to be the operator through the completion of the Keskesi well. Total holds the remaining 50% working interest.

Neptune Energy receives drilling permit

Petrofac awarded services contract

The Norwegian Petroleum Directorate has issued a drilling permit for well 6406/12-G-1 H to Neptune Energy. Well 6406/12-G-1 H will be drilled from the West Phoenix drilling facility in position 64°1’50.48”N and 6°45’2.89”E once it completes the drilling of observation well 6406/12-H-4 for Neptune Energy in production licence 586. The drilling programme for well 6406/12-G-1 H relates to the drilling of a wildcat well in production licence 586. Neptune Energy is the operator with an ownership interest of 30%. The other licensees are Vår Energi (45%), Suncor Energy (17.5%) and DNO Norge (7.5%). The area in this licence consists of part of block 6406. The well will be drilled about 36 km southwest of the Njord field. The licence is conditional on the operator securing all other permits and consents required by other authorities before drilling activity starts.

Petrofac’s Engineering and Production Services (EPS) business has announced the award of a multi-million dollar Integrated Services Contract with Ithaca Energy (Ithaca). In a new 5-year deal, Petrofac will integrate operations, maintenance, engineering, construction, and onshore and offshore technical support across Ithaca’s North Sea operated asset base. The contract extends Petrofac’s existing working relationship with Ithaca, as well as the duration and breadth of services it provides for the Alba, Captain, Erskine and FPF-1 assets, building on the operations, engineering and support services it has been providing since 2011. Having expanded its in-house capabilities, Ithaca will assume Safety Case responsibility for the FPF-1 asset, whilst Petrofac continues to provide all services and 96 offshore team members for the asset under the new contract.

In brief India Oil and Natural Gas Corporation Limited (ONGC) in India has awarded Fugro a 3-year contract to provide integrated survey services for the fourth consecutive time. Work is now under way on the latest contract, which covers infield developments on the east and west coasts of India. The survey services include pipeline route engineering and rig site surveys using multibeam bathymetric, shallow seismic profiling, magnetometry and 2D UHR, along with rig positioning, current profile measurements and wellhead searches.

Vietnam Pharos Energy has received approval from the Prime Minister of Vietnam for the TGT Full Field Development Plan (FFDP). This represents the last stage of the required process and follows the recent approval of an initial 2-year licence extension to 7 December 2026, as announced in the TGT field licence extension and RBL update on 4 August 2020. Ordering of long-lead items can now proceed to enable the commencement of the drilling of six firm development wells contained in the FFDP in 4Q21 as planned. This infill-drilling programme is targeted to increase gross production at TGT from the present 15 000 boe/d to around 20 000 boe/d in 2022.

Brazil Alfa Laval has won two orders to supply Framo pumping systems for two FPSOs to operate outside the coast of Brazil. The orders have a total value of approximately SEK155 million and are booked in the Pumping Systems unit of the Marine Division, with deliveries scheduled for 2021.

September/October 2020 Oilfield Technology | 5

World news Diary dates 27 – 29 October 2020 SPE ATCE 2020 Online atce.org

09 – 12 November 2020 ADIPEC 2020 Online adipec.com/virtual

24 – 26 November 2020 OSEA 2020 Online osea-asia.com

08 – 11 December 2020 EAGE Annual Conference & Exhibition 2020 Amsterdam, Netherlands eage.eventsair.com/eageannual2020 To stay informed about the status of industry events and potential postponements or cancellations of events due to COVID-19, visit Oilfield Technology’s events listing page: www.oilfieldtechnology.com/events/

Web news highlights Ì Ì Ì

Submission of bid in Nigeria’s 2020 Marginal Field Round Oil falls as market corrects boosted price levels Waitsia Gas Project Stage 2 recommended for environmental approval

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


6 | Oilfield Technology September/October 2020

Hess makes discovery offshore Guyana

Eni and BP make gas discovery offshore Egypt

Hess has announced another oil discovery offshore Guyana at the Redtail-1 well, the 18th discovery on the Stabroek Block, which will add to the previously announced gross discovered recoverable resource estimate for the block of more than 8 billion boe. Redtail-1 encountered approximately 232 ft (70 m) of high quality oil bearing sandstone and was drilled in 6164 ft (1878 m) of water. The well is located approximately 1.5 miles (2.5 km) northwest of the Yellowtail discovery and is the ninth discovery in the southeast area of the block. In addition to the Redtail-1 discovery, drilling at Yellowtail-2 resulted in the discovery of additional reservoir intervals adjacent to and below the Yellowtail-1 discovery. Yellowtail-2 encountered 69 ft (21 m) of high quality oil bearing reservoirs, which comprise the 17th discovery on the Stabroek Block. This resource is currently being evaluated for development in conjunction with other nearby discoveries. In total, the Stabroek Block is 6.6 million acres.

Eni and BP have announced a new gas discovery in the Great Nooros Area, located in the Abu Madi West Development Lease, in the conventional waters of the Nile Delta, offshore Egypt. This new discovery, achieved through the Nidoco NW-1 exploratory well, is located in 16 m of water depth, 5 km from the coast and 4 km north from the Nooros field, discovered in July 2015. The Nidoco NW-1 exploratory well discovered gas-bearing sands for a total thickness of 100 m, of which 50 m within the Pliocene sands of the Kafr-El-Sheik formations and 50 m within the Messinian age sandstone of the Abu Madi formations, both levels with good petrophysical properties. In the Abu Madi formations a new level, which was not yet encountered in the Nooros field, has been crossed proving the high potential of the Great Nooros Area and the further extension of the gas potential to the north of the field. The preliminary evaluation of the well results indicates that the Great Nooros Area gas in place can be estimated in excess of 4 trillion ft3.

Aker BP extends contract for low-emission rig Maersk Drilling has been awarded an additional one-well contract from Aker BP for the low-emission jack-up rig Maersk Integrator. In direct continuation of its previously announced work scope, the rig will move to the Ula field offshore Norway to drill the Ula F – Producer 1 well. The contract has an estimated duration of 85 days and is expected to commence in April 2021. The contract value is approximately US$21.6 million, excluding integrated services provided and a potential performance bonus. Maersk Integrator is contracted under the terms of the frame agreement that Maersk Drilling and Aker BP entered into in 2017 as part of the Aker BP Jack-up Alliance which also includes Halliburton. This alliance uses a shared incentives model, thereby securing mutual commitment to collaborate and drive digital initiatives to reduce waste and deliver value. Contracts under the alliance are based on market-rate terms but add the possibility of an upside for all parties, based on actual delivery and performance. Maersk Integrator is an ultra-harsh environment CJ70 XLE jack-up rig, designed for year-round operations in the North Sea. It was delivered in 2015 and is currently finalising its scheduled Special Periodic Survey offshore Norway. The rig is further underwent a series of upgrades to turn it into a hybrid, low-emission rig before expectedly moving to the Ivar Aasen field for Aker BP in August.

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Down for

Oilfield Technology correspondent, Gordon Cope, reports that North American oil and gas has taken a dreadful thrashing, but there are signs that it is already starting to shrug off the worst. 8|

the count? T

he world’s oil and gas industry has been taking a beating, and North America’s sector is no exception. The combination of a renewed production war by Saudi Arabia and the coincidental destruction of global energy demand due to COVID-19 has been a devastating one-two punch. Millions of barrels of crude have been shut in, hundreds of thousands of jobs lost and billions of investments written off. Therefore, the question remains if the sector will recover.

Crude The Permian Basin in Texas and New Mexico, US, has been producing from conventional reservoirs for over a century, but it was not until the advent of horizontal drilling and hydraulic fracturing that it truly came to prominence. By early 2020, over 7000 wells were producing 5 million bpd of light, sweet crude and 10.3 billion ft3/d of gas, making it the most prolific basin in the world. Operators were constrained from adding more solely by the lack of pipeline takeaway capacity. As demand fell dramatically, prices tanked into negative territory and operators scrambled to limit production. By the end of May 2020, the Permian’s oil rig count had fallen under 220, a 65% decline from 624 rigs in early March. Some important oil counties had lost much more; Andrews and Culberson counties reported 80% and 100% declines in rig counts, respectively. Companies also began to shut in marginal wells; ConocoPhillips cut production by 200 000 boe/d, and Chevron reduced output by 125 000 bpd. A host of other companies shuttered their most unprofitable fields as crude prices fell into negative territory. By mid-2020, crude output in the Permian was below 4.3 million bpd, and analysts were predicting further drastic cuts if prices did not improve. In early 2020, the offshore Gulf of Mexico was on track to reach 2 million bpd of production by the end of the year when COVID-19 struck. Active drilling rigs shrank and workers were evacuated from platforms to stop the spread of the disease. However, relatively few wells were shut-in. Miles of flow lines on the seabed carry crude ashore, but at these great depths, the fluids have the potential to clog if flow is cut off too long. The Williston basin, which lies below most of North Dakota, is home to the tight, organic-rich Bakken formation. By early 2020, according to the US Energy Information Administration (EIA), production had surpassed 1.5 million bpd. When calamity hit, however, operators were even more exposed than their brethren in the Permian. The Bakken play lies far from consumption and

export points and barrels are usually discounted from West Texas Intermediate (WTI) prices. Continental Resources, the largest producer in the state, went into bankruptcy and others shut in production and slashed drilling budgets. By June, production in North Dakota had fallen to slightly over 1.1 million bpd. Troubles in the oil sands began long before 2020. For the last several years, environmental groups have waged a successful war against ‘dirty oil’, spear-heading the cancellation of major export pipelines and effectively throttling new investment. Super Majors such as Total sold their mining and underground assets, while producers without firm pipeline shipping contracts were forced to accept deep discounts to sell their oil, causing the loss of billions of dollars in revenues. In May 2020, Norges Bank, which manages Norway’s sovereign wealth fund, publicly announced that it would stop investing in four oil sands companies: Canadian Natural Resources Ltd, Cenovus, Suncor and Imperial Oil. The decision was based on a recommendation from its Council on Ethics, which said they were being black-listed “due to an unacceptable risk that the company is contributing to or is itself responsible for actions or omissions which, at the aggregate company level, lead to an unacceptable level of greenhouse gas emissions.” “To be blunt, I find [the decision] incredibly hypocritical,” said Alberta Premier, Jason Kenney in response. “Norway is actually engaged in exploring to develop new massive offshore fields to increase their production of oil, so we are not going to be lectured to by a state sovereign wealth fund 100% of whose primary revenues are generated by oil development.” Offshore Newfoundland & Labrador (N&L) has been host to Hibernia and other fields for several decades. Over 20 billion bbls have been produced, with the prospect of a further 20 billion in potential reserves. The provincial oil and gas industry is in crisis, however. Hibernia suspended its production drilling programme, the development of Terra Nova is paused, and the West Rose project is being deferred. The Newfoundland and Labrador Oil and Gas Industries Association (Noia) says that 70% of their membership has laid off employees. The provincial government estimates that the downturn has the potential to create a loss to the provincial GDP of CAN$61 billion over the next 20 years. By early June 2020, massive production cuts had been made throughout North America. In Alberta (Canada’s largest oil and gas province), producers had cut crude output by 1 million bpd, or 25% of capacity. In the US, an estimated 2.6 million bpd was offline, reducing production from a high of 13 million bpd in early 2020.


Natural gas In May 2020, EQT, one of the major gas producers in Appalachia with an average of 4.2 billion ft3/d, curtailed 1.4 billion ft3/d (approximately one-third of production) in Pennsylvania and Ohio until prices improve. “Like others in the natural gas industry, we are anticipating a significant increase in natural gas prices from current levels in just a few months,” EQT said. At the time, delivery prices were at US$1.65/mmBtu, while the 12-month strip stood at US$2.37/mmBtu. The tight Montney formation in northeast British Columbia and northwest Alberta contains an estimated 450 trillion ft3 of gas reserves. The reserves lie just a few hundred miles from the west coast of North America, making it an ideal candidate to supply Asia. Advanced drilling technology has allowed operators to increase production to almost 10 billion ft3/d, with the intention of supplying major North American consumers (such as the oilsands), and LNG gas projects like Shell’s LNG Canada (a US$31 billion complex designed to export up to 26 million tpy from the port of Kitimat, British Columbia). The viability of export projects such as LNG Canada are being complicated by native protests, however. Coastal GasLink pipeline, designed to deliver over 2 billion ft3/d from northeast British Columbia to Kitimat, set off a round of rail and road blockades across the country when it became embroiled in a dispute with local First Nation traditional chiefs.

LNG As demand in Asia plummeted, US Gulf Coast (USGC) LNG plants suffered. According to the EIA, exports of LNG from US plants fell from 8 billion ft3/d in late 2019 to approximately 3 billion ft3/d by late June 2020, as over half of the contracted cargoes were cancelled. Prices in Asia and Europe were under US$2/mmBtu. Plans for new-build have been thrown into disarray. Shell cancelled its joint venture (JV) with Energy Transfer’s Lake Charles LNG project. Sempra delayed its final investment decision (FID) on the proposed Port Arthur LNG in Texas, US. Paradoxically, in spite of the trade war broiling between the US and China, US LNG imports to the latter state remain remarkably strong. Wood Mackenzie reports that China purchased 10 loads from US suppliers during April and May 2020. Analysts suspect many reasons for the purchases: spot LNG prices are at record lows, China is seeking leverage to drive down long-term contracts with Central Asia pipeline sources, and a spat with traditional LNG supplier Australia has recently heated up. Regardless, China is sticking to its pledge to add an extra US$52.4 billion of US energy supplies over the next two years.

estimates that there are as many as 56 000 orphan wells in the US which pose a potential threat from leaking fluids and methane emissions. The commission, which represents 31 states, is seeking funding from the US Department of Energy. In March 2020, Congress authorised the Federal Reserve to inject trillions of dollars into the ailing economy through loans and bond purchases. The Fed subsequently purchased bonds for ExxonMobil, Marathon and other oil companies. This aid, along with cutting royalty rates on federal lands and opening new regions for leasing, is designed to bolster the US oil and gas sector. The help proved too little, too late for many companies. In late June 2020, Chesapeake Energy, a pioneer in shale fracking, entered Chapter 11 bankruptcy protection. The company will need to work with creditors to drastically reduce its US$9 billion in debt for any chance of survival. By July, Canadian companies were cautiously bringing back about 20% of the 1 million bpd that had been shut-in. Husky returned half of its 80 000 bpd curtailment back online, and Cenovus half of its 60 000 bpd curtailment. Husky cited demand from American refiners for the move.

The future US gas production, which stood at a record 94 billion ft3/d in late 2019, is expected to bottom out at 82.5 billion ft3/d in late 2020. Rystad Energy estimates that most of the 11.5 billion ft3/d reduction will be through natural decline (approximately 10 billion ft3/d), with the rest due to shut-in curtailments. The EIA expects LNG exports to return to 8 billion ft3/d by late 2020, and surpass that mark in 2021. Part of the reason is that many European nations are seeking ways to reduce their reliance on Russian gas; Poland for instance, is not renewing a long-term agreement to purchase gas from Gazprom when it expires in 2022, preferring to import up to 40 billion m3/yr from Cheniere Energy’s US LNG plants to meet demand. Southern Mediterranean states, including Greece and Italy, are taking advantage of low LNG prices to make substantial increases in imports. Ironically, Canada, which had been beset by a shortage of pipeline capacity due to delayed and abandoned pipeline projects, now finds itself with spare capacity after exports dropped by over 1 million bpd. As a consequence, crude-by-rail fell from 412 000 bpd in February 2020, to 156 000 bpd in April. While exports will eventually rise, the 1 million bpd shortfall provides a cushion until new capacity eventually comes online.

Conclusion Some light in the gloom In early 2020, the Alberta Carbon Trunk Line (ACTL) opened. The 240 km line is designed to carry pure carbon dioxide (CO2) to a mature oil field in central Alberta, where it is injected underground. The line has an initial capacity of 1.6 million tpy of CO2 (the equivalent of ~300 000 cars), and currently services a bitumen upgrader and a fertilizer plant where CO2 is captured from emissions. Significantly, the ACTL can be scaled up to 14.6 million tpy, about 20% of the oilsands discharge. Oilsands developers have been pursuing lower greenhouse gas (GHG) emissions for decades. The sector as a whole has reduced emissions per barrel by 19% since 2011. As for Norge Bank’s blacklist, Suncor is on track to reduce emission intensity by 30% by 2030, and Cenovus has said it will aim for zero GHG emissions by 2050. Imperial Oil has reduced carbon intensity by at least 20% since 2013, and is developing technologies that could reduce intensities by up to 90% on new production. As part of its COVID-19 economic response, Canada is setting aside up to CAN$1 billion for site-reclamation of ‘orphan wells’, which are defunct assets with no clear owner. The programme, which is designed to clean up the environment and ensure jobs for oilpatch workers, is being touted in the US. The Interstate Oil and Gas Compact Commission

10 | Oilfield Technology September/October 2020

Much of what happens in North America during the latter half of 2020 will be predicated on the price of crude. Many shale drillers can make a profit (or break even) when the price stabilises at or above US$40. As the OPEC+ agreement to reduce production gained traction in mid-2020, prices climbed sufficiently to encourage operators to plan on returning approximately 500 000 bpd to production. The secret to rapid reversals, it turns out, is that many of the wells that were ‘shut-in’ were simply choked back, a relatively simple mechanical procedure that reduces production but does not completely curtail it or create significant reservoir problems. In the long-term, a return to production growth will be complicated by several factors. Banker Goldman Sachs notes that global crude storage now stands at approximately 1 billion bbl, and it will likely take 2 years before that drops to five-year levels. OPEC+ has 10 million bpd of excess capacity, maintaining the potential for a return to production wars. Although demand is once again growing, observers speculate that it will not return to pre-COVID levels for several years, if ever; advances in batteries are giving electronic vehicles ever more range and flexibility. Regardless, North America’s oil and gas sector has shown remarkable resilience against a spectrum of blows, and, in spite of its travails, will continue to thrive for decades to come.

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Benoit Deschamps and Nicolas Sluys, Rubicon Oilfield International, explore a new rotational function of the drill string that combines technology developments with a well life cycle solutions approach.


he oil and gas industry trend moves the needle to ever more challenging wells in terms of measured depths, lateral departure or trajectory complexities, with the objective to maximise the reservoir exposition while minimising overburden costs. Therefore, new methods must be introduced to: Drive operational execution and production efficiency. Improve well construction reliability to decrease further interventions, avoid production deferral or early plug and abandonment. Better manage operational risks.


This needs to be achieved while also reducing both CAPEX and OPEX through the well life cycle. Continuous improvements, targeting increased reliability and operational performance of current methods and technologies are a natural and mandatory focus of the technical teams involved in well planning and design, technology and operations. These are the ‘what else?’ or ‘what more?’ approaches, inherent to sustaining development. There is also value in taking some steps back and revisiting the potential of commonly used or established practices and technologies. In this case, the thought process is primarily fuelled by a ‘what if?’ or a ‘why?’ approach.

The purpose Fundamentally, the drilling, casing deployment, completions and intervention phases of the well life cycle will be achieved through the implementation of three basic mechanical functions provided by the drilling rig, surface and downhole equipment: the pulling, the pumping, and the rotational capabilities. These functions are supported by improved decision-making processes resulting from measurement, communication, interpretation and automation.

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As a critical piece of the well construction phase, the drill string connects the surface equipment to the downhole target. As a continuous component, the drill string or casing string will do the following: Ensure the transfer of downhole weight (such as weight on bit) by managing the surface hookload and the assessment of frictional losses along the string. Drive the fluids circulation, the inherent requirement for pressure related operations. Allow the transfer of the rotation initiated from surface down to downhole equipment. Inversely, torque, resulting from any tangential force applied along the string, will cumulate from the bottom up to surface. The rotational system needs to have enough torsional capability (power and mechanical ratings) to ensure continuous rotation to the string.


When designing the well, from a purely mechanical integrity perspective, the operator will ensure the surface equipment and the drill string components meet the necessary requirements in terms of maximum overpull and compression, torque and burst and collapse in the expected drilling environment (temperature, fluids type, fatigue, casing wear, formation pressure and frac gradient, etc.). The variety of the components (dimension [outer and internal diameters], materials and connections properties) can lead to substantial differences in terms of mechanical ratings along the string and need to be identified by the operator. Analytical methodologies, such as torque and drag analysis, will allow identifying the forces applied on the string and, from there, their cumulative effect in terms of hookload, torque and buckling susceptibility. From a purely operational perspective, the operator will also consider the capability to activate, de-activate, lock, anchor, open, close and release various specific systems through the application of pressure, tension, compression or rotation, at a specific component’s depth, through the manipulation of the drill string. Establishing a proper chronology and analytics assessment of successive specific operational sequences and enabling methods against drill string capabilities is a critical step in the feasibility study. Complexities will occur during the successive operational phases, exposing the operator to specific challenges depending on the well design, geomechanical environment and technical capabilities on location. These challenges can percolate down from the following: Poor wellbore quality.1 Suboptimal drilling performance. Poor weight transfer.


Inadequate hole cleaning. An inability to deploy casing or completions to target depth. Damage to float, stage cementing or production equipment due to excessive or erratic load transfer. Differential sticking. Suboptimal cementing processes subjecting the wellbore to poor zonal isolation and wellbore integrity issues. An inability to implement efficient well intervention operations.

These challenges can either decrease the expected performance (suboptimal technical performance, increased operational time and expenditure) or potentially turn risks into showstoppers calling for contingency or alternative plans, at best. The capability to quickly and effectively react positively impacts the ability to mitigate the problem, and to ensure continuity to the expected return on already accrued significant investments. In real terms, the operator has a limited number of viable options. The continuous string is not homogeneous in terms of loading capability and the operator will either be limited by the weakest point, or will need to potentially put a component at risk to exit the problem. The purpose of the company’s RotationABILITYTM concept is to create an additional degree of freedom and flexibility around the rotational function of the string. By integrating practical innovation and applications engineering fundamentals, RotationABILITY aims to provide rotation capability on a selective portion of the string to overcome planned functional limitations or unexpected challenges throughout the well life cycle.

The genesis

As a typical challenge associated with highly deviated, horizontal or extended reach drilling (ERD) wells, during the ‘conventional’ (non-rotating slack-off mode) completion deployment, axial friction will be generated and cumulated along the string against the borehole. While progressing into the well, the friction will consume (a part of) the available weight from surface. Downhole, the compression of the string can lead to helical buckling and lock-up, preventing any further progress and compromising the entire completion of the well far above total depth (TD). If proper wellbore conditioning and sufficient hole cleaning are the mandatory legacies of the drilling operations ahead of the casing and completion deployment, multiple approaches and technologies can be considered and combined to reduce the friction during deployment. Hydraulic (lubricants additives to the mud) or mechanical solutions can be considered, such as: Providing more weight available from surface (heavy weight drill pipe, tapered working string designs). Reducing the friction coefficient at the contact point with the wellbore (low friction centralisers and subs technologies). Decreasing the weight of the completion to be deployed (floatation, aluminium pipe and casing technologies). Providing reaming and hole cleaning capabilities to the string (reaming shoes). Displacing a portion of the friction from a pure axial drag mode to a torsional component by inducing Figure 1. Illustration of the progressive friction displacement from a pure axial slack-off mode (left string rotation. hand side) to a pure static rotational mode (right hand side).



14 | Oilfield Technology September/October 2020

Depending on the application specifications and operator objectives, some of these options might not be applicable or not provide acceptable improvements due to their limitations (additional installation time, cost, design complexity, safety risks, etc.). The string rotation, by displacing a significant portion of the friction from the axial to the torsional component, together with the scale (distance) on which this effect is applied, provides the most significant impact in drag reduction, string compression limitations and increased available hookload (Figure 1). During the string deployment, friction will develop at the contact points of the string with the wellbore, where side forces are generated. Friction will develop in the opposite direction of the motion direction. In pure slack–off mode, the string motion is purely axial. Friction will then be fully oriented against the axial motion and seen as drag, which will result in hookload reduction (left hand side of Figure 1). In pure static off–bottom rotation mode, the friction will develop on the tangential direction exclusively. Frictional torque will then develop, cumulating along the string up to the surface (right hand side of Figure 1). With both axial and rotational motion, friction will be split between two components, axial and tangential, respectively seen on the axial hookload and the torque. Their respective contributions will be driven by the axial (tripping) speed vs tangential (rotational) linear speeds at the tubular/borehole contact point. In the case of axial drag reduction, the higher the rotational speed and the lower the tripping speed then the lower the drag component will be, but the higher the frictional torque will get. Operational limitations will come from the torsional capability of the full, continuous, string. Several factors, such as premium connection cost, fatigue concern and sensitive completions equipment, have caused most operators to stay away from full string rotation.

pins when setting up the tool on surface. The string is pressurised using the liner hanger/packer setting ball, meaning that no time is lost converting the tool. This downhole swivel technology is fitted with sets of rotating and sliding type seals and its pressure rating matches most of the ERD and horizontal deployment applications requirements. All tools are pressure tested in-house to 150% of their operational pressure rating as standard practice. In order to meet increased operational requirements and new applications configurations, functional upgrades and new variances have been developed, such as: The CasingSWIVEL technology, where the swivel is incorporated in a sacrificial casing string. The Mechanical SwivelMASTER, where the clutch is mechanically activated, ensuring swivelling mode on right-hand rotation and locked mode on the left-hand rotation. The TerraSWIVEL, which is a simple and robust big bore continuous swivel, specifically designed for wellbore clean-up operations or rotating-free logging operations. The TornadoSWIVEL, designed to sustain extreme drilling and impact loads, and provide rotation capability to fire a jar above a stuck bottom hole assembly (BHA) in a complex well design environment.


Depending on the application, complementary solutions can be integrated on the string design, such as: EzeeGLIDER/OptiMIZER fibre reinforced polymer centralisers, which provide centralisation, stand-off and a lower coefficient


Selective string rotation But what if only a portion of the string could be selectively rotated? In such a configuration, RotationABILITY will be enabled through the integration of SwivelMASTER® technologies within the string. This integrated technology will allow the selective rotation of the string above the tool (upper string), while preventing the rotation to be communicated to the string below it (lower string). Established for more than a decade in the most complex ERD deployment operations, the Single-Shot Hydraulic SwivelMASTER is the pioneering configuration of the product line. Conventionally, the tool is run in ‘swivelling’ mode, meaning that the clutch mechanism is unlocked, decoupling the rotation from the upper string to the lower string. The tool features heavy-duty compression and tension roller bearings that are capable of pushing and pulling high loads for extended periods at rotational speeds of up to 80 – 100 rpm. The clutch is hydraulically activated through differential pressure applied through the tool. When activated, this can permanently lock the tool at total depth to allow for the contingency mechanical release of the service tool if required. The conversion pressure is simply set by adding or removing shear

Figure 2. 16 500 ft 6 5/8 liner deployment. Model vs actual hookload data. Effect of RotationABILITY to ensure deployment to TD.

Figure 3. Expanding deployment and reservoir capabilities. Model vs actual data.

September/October 2020 Oilfield Technology | 15


of friction, resulting in lowered compressive force on the lower completion string. Advanced reaming shoe or indexing shoe technologies, such as BridgeBUSTER or NaviSHOE, to facilitate the string to navigate across localised obstructions or doglegs.

This comes with the added value of risk mitigation, operational efficiency, increased deployment and reservoir exposition capabilities. The following case studies briefly explore the value added by the RotationABILITY concept at different stages of the well-life cycle.

Case study 1: Ensuring production string deployment to TD in challenging ERD well design2 In this application, a 16 500+ ft long 6 5/8 in. pre-perforated liner was expected to be run to target depth in a sub-horizontal, extended, 8 1/2 in. open-hole section (Figure 2). The pre-job modelling indicated that the production liner would be in position to reach TD if the overall friction factor would remain below 0.3. The pre-perforated liner was run smoothly, in conventional slack-off mode down to 27 839 ft measured depth (MD). From that depth, drastic hookload reduction was observed, ultimately leading to the completion string, including multiple swell packers, to be stuck 2738 ft above TD, compromising the full completion of the well. The selective rotation of the ‘upper’ string (drill pipes and blank 6 5/8 in. liner joints), with a CasingSWIVEL located 12 900 ft above the shore, and low Friction Centralisers EzeeGLIDERs placed on the production string, provided substantial gain of available hookload (100 000+ lbs in this case), allowing the production string to overcome localized challenges. Upper string rotation was maintained for the remaining 2700 ft, securing the production string to be deployed to target depth.

EzeeGLIDERs on the production screen, together with the SwivelMASTER located at the bottom of the landing string. If the low friction centralisers provided a substantial gain in hookload, selective rotation of the working string was mandatory to complete the last 3278 ft of the deployment in the reservoir.

Case study 3: Operational efficiency The use of ball as a sealing method for a pressure-activated conversion system in a deep offshore environment is common in well construction and completions operations. The ball will be dropped into the drill string internal diameter (ID) and be pushed form the flow to land on the tool seat. Naturally, ball transit time can quickly escalate in high inclination applications. Additionally, the ball can also face issues in engaging in ID restriction at pipe joint or at the transition of tapered strings. The results here were recorded during a deep-offshore development campaign. In average, conventional ball transit time was estimated to 390 minutes (Figure 4). By inducing slow rotation to the pipe while circulating the ball, transit time were drastically reduced, ranging from 22 – 55 minutes in this campaign, driving significant US$234 000 savings per well.

Case study 4: Protecting and enhancing logging tools applications Located couple of stands above the pipe conveyed logging tool, the TerraSWIVEL allows deploying the drill pipe conveyed logging system in ERD well by allowing upper string rotation while preserving the logging tool from potential damages, shock and vibration caused by the pipe rotation. Finally, the logging quality is improved by ensuring a smooth, steady and accurate displacement of the string.

Case study 2: Expanding deployment capabilities and reservoir exposition

Case study 5: Combining multiple sections in wellbore clean-up operations

The feasibility study completed for this 6182 ft long 5 1/2 in. screens deployment highlighted that conventional working string design and deployment method (slack-off ) would run out of weight in surface far above the target depth, basically when entering the open-hole section (Figure 3). Integrated at the well planning stage, the RotationABILITY solutions incorporated the use of low friction centralisers

First combined 7 in. and 9 5/8 in. wellbore clean-up (WBCU) operations have been also successfully performed in single-run operations in the Middle East. In these applications, the string rotation is necessary to deploy the 7 in. section WBCU bottomhole assembly (BHA) in a long horizontal section. The string rotation is also drastically enhancing the WBCU efficiency in the 9 5/8 in. intermediate section but prohibited in the non-cemented 7 in. liner. By integrating a SwivelMASTER in between the 9 5/8 in WBCU BHA and the 7 in. WBCU BHA, effective rotation is applied appropriately, preventing these operations to be completed in two independent runs.

Conclusion Built upon a strong and proven expertise in complex ERD well construction challenges and fuelled by continuous technology and applications engineering improvements, the RotationABILITY concept opens new perspectives on the value that can be extracted from the drill string or casing string rotation. Offered all along the well life cycles, these perspectives range from risk mitigation and operational efficiency cycle to significant potential increase in reservoir exposition capabilities.

References: 1. 2.

Figure 4. Setting ball deployment time in deep offshore applications. Transit time reduction with pipe rotation.

16 | Oilfield Technology September/October 2020

DESCHAMPS, B., ‘Looking below the Tip of the Iceberg’, Oilfield Technology Magazine (March/April 2020), pp. 41 – 44. RYAN, J. T., ALVAREZ, J., CLEWS, M., REICHLE, M., Szary, T., DESCHAMPS, B., ESPELAND, K., ‘Casing Swivel Tool Greatly Expands Liner Deployment Capability in the Giant Offshore Oil Field Abu Dhabi Resulting in a World Record Single-Run 6-5/8 Inch Lower Completion’, Rubicon Oilfield International, ADIPEC (November 2017).



Dr Ellie Mavredaki and Sam Toscano, SUEZ – Water Technologies & Solutions, investigate the advances in encapsulated treatment technologies that mitigate scale formation.


ne of the most common causes of flow assurance upsets in oilfields is inorganic scale formation within produced water. The scale has the tendency to precipitate and/or deposit in the formation, production string, process equipment and re-injection facilities, resulting in production challenges and equipment failures. Mitigation of scale is typically achieved through continuous or batch injection of liquid scale inhibitors in the aqueous phase.

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Continuous injection of scale inhibitors is accepted as the most effective method for produced water treatment on a global basis, even though the volumes of the scale inhibitors required for comprehensive scale control are usually considerable. Often, more cost-effective application methods are required, mainly due to: Lack of equipment, such as pumps, especially for brownfields with a high number of producing wells.



High CAPEX for multiple scale inhibitor injection points (greenfields). Additional costs for transporting chemicals to producing fields located in remote areas.

Deployment of encapsulated scale inhibitors offers a more cost-effective solution for scale mitigation, as there is no need for surface pumps or power supplies. The application involves direct injection of the encapsulated product as an aqueous suspension (slurry) into the rat hole (Figure 1) by applying it either down the production tubing or the backside of a packer-less well (Figure 2). The product slowly releases the active scale inhibitor by a diffusion mechanism, providing continuous inhibition of scale in the well tubular and pumping equipment. By selecting this type of application, the key benefits are: Protection of the tubular and equipment starts immediately as there are no time delays for the chemical to reach the target zone. The risk for chemical undertreatment is minimised as the chemical has the tendency to remain in the aqueous phase rather than adsorbing on the formation. The risk of missing chemical treatment due to transportation delays or weather conditions is minimised, as encapsulated scale inhibitor treatments are required less frequently. The site personnel deal with fewer toxic chemicals as the application requires fewer handling operations.

Ì Ì Chemical ConcentraƟon Gradient

Ì Ì Encapsulated Product

Figure 1. Placement of encapsulated product in the well.

Encapsulated scale inhibitors are highly beneficial when successfully applied. To provide assurance that the application of these chemicals will be effective, both the operator and the chemical vendor need to consider the production and operational conditions. For such treatment to be applicable, it is necessary that either wells are packer-less or that tubing can be used directly for guiding the solid pellets to the rat hole. When it comes to encapsulated scale inhibitor treatments, decision-making is further supported by: Desktop thermodynamic modelling, for predicting the scale types that have potential to precipitate and to what extent. Field deposits collection, analysis, and evaluation. Downhole temperatures profile, for chemical inhibitor thermostability check. Rat hole dimensions evaluation. Cost comparison of encapsulated scale inhibitor treatment vs conventional continuous chemical injection and/or vs squeeze treatment.


Several operators are currently deploying encapsulated scale inhibitors for crude oil and/or gas-producing wells. The products have also shown efficiency in completions and fracturing operations, providing a long-term resolution to production challenges. Considering the tight legislation on produced water treatment and freshwater consumption limitations, applications of encapsulated scale inhibitors are expected to increase by 20% on a global basis.

Case study

Figure 2. Encapsulated application.

18 | Oilfield Technology September/October 2020

A conventional oil and gas operator, producing approximately 700 m3/d of crude oil formation with water reaching 1700 m3/d, experienced multiple production well fractures at a depth between 3100 m and 3450 m. Scale precipitation occurred within the reservoir fractures as well as within the electro-submersible pumps (ESPs) located between 2900 m and 3100 m. To mitigate the production

challenges caused by scale, the operator performed well interventions that resulted in high operating and lifting costs. The desktop analysis revealed the potential for calcium sulfate (CaSO4) precipitation at a temperature above 120˚C. At higher temperatures, scale precipitation was expected to be more severe, indicating an increase in scale deposition potential within the ESPs where the motor skin temperature was above 145˚C. Further analysis of the produced water, as received from different wells, highlighted potential incompatibilities among the mixed waters. Inspection of the pumps and production tubing highlighted scale formation in the internal and external areas of the equipment, with most of the scale deposited in the motor areas. Deposit analysis confirmed CaSO4 as a principal type of Figure 3. Intervention duration life for wells 1 and 4. scale, with calcium carbonate (CaCO3) present to a lesser extent. To provide effective, long-term control of the scaling Moving forward, the focus will be on improving encapsulated tendencies of the water throughout the production system, a scale inhibitor chemistries and optimising treatments to achieve strategy to treat the water with an encapsulated product, as it was even longer scale control within produced water. produced from the reservoir, was selected. Each of the wells was Encapsulating a wider range of chemistries – including but treated with an effective encapsulated scale inhibitor. The product not limited to corrosion inhibitors, biocides, wax inhibitors, was applied downhole to each well individually. and foamers – is being explored. Some treatments have already Calculations for each individual encapsulated treatment were been successfully applied, while other treatments are currently performed based on the space available at the bottom of each undergoing field trials. well, the well’s daily production and the duration of the desired treatment, which was 1 year. Following the treatments with the encapsulated product, the frequency of the failures in the wells decreased drastically and productive well operation time increased significantly. In some of the wells, the failure frequency dropped by as much as 80%. Figure 3 shows the last six interventions for wells 1 and 4 respectively. Only the last intervention was under treatment with the encapsulated scale inhibitor. Once the encapsulated product was applied, the pumps’ run-life increased to more than 500 days. By monitoring the inhibitor residuals, SUEZ has been able to review the progress of the treatment and determine when it is necessary to apply the next encapsulated treatment. Monitoring was carried out via phosphate residuals measurements from produced water samples collected periodically from surface sample points. MICRO AND NANO CONNECTORS FOR EXTREME ENVIRONMENTS Residual values indicated that the volume of the encapsulated scale inhibitor initially injected in the rat hole was enough to control the scaling tendency of the water. THE PETROLEUM-INDUSTRY T Considering the cost of each intervention and the MICRO AND NANO SIZED loss of profit during the well shutdowns (2 – 3 days), CONNECTORS ARE the operational savings per well were estimated at S SPECIFICALLY DEVELOPED US$40 000. The application of the encapsulated scale F THEIR SMALL SIZE AND FOR inhibitor also generated operational improvements in R RUGGEDNESS, TO PROVIDE lifting equipment. H HIGH TEMPERATURE, HIGH

Conclusion Encapsulated scale inhibitors have exceeded expectations in both treatment duration and cost-effectiveness.


Disrupting tracing Dr Sudiptya Banerjee, Tracerco, analyses the development of microencapsulated polymer tracer rods.

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traditional trajectories T

hough non-radioactive chemical tracers have been in use since the 1940s, new options become available every year, designed to expand the detection limits, increase longevity in the reservoir, and explore the fundamental underpinnings of oilfield tracers in new ways. One novel breakthrough for oilfield chemistry was the introduction of the microencapsulation of tracers. Microencapsulation is a process that enables the controlled loading and release of tiny particles or droplets from within hollow particles, typically between 1 – 1000 µm. Embedded within a homogenous or heterogeneous matrix, these microparticles can encapsulate a variety of solid, liquid, or gaseous substances; as the core material gradually diffuses through the capsule walls, the microparticles offer controlled release of the encapsulated material under desired conditions. Microencapsulation has been used across numerous industries as a method of controlled delivery, spanning a variety of fields including pharmaceuticals, food and nutrition products, and cosmetics. Its rapid adoption is due to the myriad advantages microencapsulation provides, such as protection of the encapsulated agent from chemical or biological degradation, accurately controlled release rates of the incorporated product, control of volatile evaporation or losses, and oftentimes improved handling or manipulation of the product. However, its application to the oilfield is still relatively novel with speciality manufacturers encapsulating only a limited selection of oilfield chemicals. Some common remediation products, such as scale inhibitors, antibacterial agents, and chelating agents may be purchased in a microencapsulated form, but no microencapsulated tracers are not currently in use within the industry.

The value of microencapsulation to inflow tracer studies Though non-radioactive tracers come in a variety of different forms, a common application is the use of polymer tracer rods to quantify the inflow production profile of a well. This type of tracer study is achieved by casting a phase-specific tracer (e.g. oil, gas, or water) within a polymer matrix, usually with the shape of a bar or rod. Once the carrier polymer hardens around the chemical tracer, the cast polymer tracer rods can be cut and

shaped to size and installed into the well completion, typically within the drainage layer of a sand control screen. When the completion is run in-hole, the polymer tracer rods begin to elute their unique chemical marker upon contact with their corresponding fluid phase. A typical well, before being brought online, is usually in contact with oil along the wellbore and continues to contact oil over the lifetime of the well, allowing the oil polymer tracer rods to elute their oil marker. When water breakthrough occurs, installed water polymer tracer rods begin to elute their water markers. By capturing samples of the produced fluids at surface at different time intervals, it becomes possible to measure the concentration of each unique chemical marker and quantify where along the wellbore and at what rate the different fluid phases are being produced. As a diagnostic method to understand fluid production and how a wellbore is interacting with the reservoir, these polymer tracer bars are an exceptional tool. They benefit from being a low-cost, passive system, which does not require the installation of secondary tool systems, wires, or cables, and is able to avoid restricting the inner diameter of the well. However, they suffer from a significant limitation in effective life; installed within the drainage layer of sand control screens, there is a limited working space to place tracers and once the implanted tracer is consumed, there is no mechanism to replace or replenish the installed polymer bars. For this reason, traditional tracer bars rarely exceed a working life of two to three years under real world conditions, a significant barrier to long-term studies of wellbore performance. However, by creating a distribution of microparticles with different cell wall thicknesses, microencapsulated polymer tracer bars overcome the limitations of traditional tracer rods with their rapid matrix diffusion rates and instead prolongs tracer release. Unlike their traditional counterparts, a microencapsulated tracer rods can only allow a portion of the enclosed tracer to diffuse out of the rod when contacting the markable phase. As these tracers are produced, new volumes of embedded tracers become exposed to in-situ fluids as their microparticles breaks down, essentially ‘replacing’ the spent rod passively and without any intervention from surface. In optimising this release response, microencapsulated tracers may provide threefold improvement or more in working life in

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real world applications over current inflow tracers, constrained only by the limits of detection of the tracer itself.

Long-term laboratory testing of microencapsulated tracers As a result, Tracerco has developed an advanced synthesis method to encapsulate their suite of oilfield tracers. For its suite of commercial

Table 1. An estimation of tracer life based on achieved elution rates (assumes a well production 5000 bbls of the targeted production fluid and 250 standardised Tracerco tracer bars installed) Targeted tracer concentration, ppb

Required tracer release rate, mg/cm2/day

Expected release life, years
















Figure 1. 2 years of elution data for a microencapsulated polymer tracer


tracer offerings, a microencapsulated polymer product can be tuned to elute tracers at any rate between 0.001 to 10 mg/cm2/day. By having a tunable release rate, the microencapsulated polymer tracer rods can be adapted to meet any client demand from initial production confirmation and quantification to long term monitoring of reservoir dynamics. Two release profiles have been developed for commercial use: the first has a large initial release of tracers, followed by a lower steady-state release that is ideal for quantifying inflow production profiles while the second maintains a consistent linear release rate over the entirety of the polymer tracer rod life. In Figure 1, 2 years of elution test data is provided for a microencapsulated polymer tracer rod designed for a 3-year lifespan. Unlike a traditional polymer rod, a microencapsulated polymer tracer rod has an observable linear release over its extended lifetime. This rate of release can be modified for tracer studies ranging from 2 months to potential decades, always with a repeatable, consistent and linear release. In Figure 2, the same tracer was tweaked for different desired study lifetimes. Though the tracer release rate proved adjustable, the consistent linear release rate was preserved. The consistent linear release of tracer allows for the microencapsulated product to achieve working lifetimes. Consider a typical polymer tracer rod deployment within a well producing 5000 bbls of fluid a day with a reservoir temperature of 60˚C. Depending on the analytical limits of detection for the chemical tracer, laboratory testing thus far indicates that a microencapsulated tracer can produce a measurable signal over decades of well life rather than months or years. In the development of this product, Tracerco has created effective microencapsulated tracers for wells ranging in temperature from 60˚C to 120˚C with the same consistent, repeatable tracer performance. Nevertheless, no matter how promising laboratory data is, new technologies need to be proven in the field. The company’s microencapsulated offerings now also have documented long-term performance from multiple trial wells. One early field trial deployed microencapsulated tracers into an oil well in late 2018. Exposed to reservoir temperatures of 90˚C (194˚F), microencapsulated tracers have been successfully measuring the zonal distribution of the 9000 bbls of oil produced daily with steady-state tracer concentrations still in excess of 10 ppb after more than 2 years of production. Per the operator’s feedback, this has been their best experience with deployed tracers to date as all other ‘long-term’ tracers they have run have failed to live up to their advertised lifespan. The next generation of microencapsulated products, whose development is already underway, will expand the technology in three critical ways: the creation of tracer-releasing microencapsulated ‘proppant’ that might be pumped as part of a hydraulic fracture treatment, rapid expansion of the number of tracers that can be microencapsulated, and finally expanded the technology to non-tracer chemicals. Soon this technology may be used for target delivery of a host of oilfield chemicals, ranging from biocides to chelating agents, from hydrogen sulfide scavengers to surfactants, or any other chemical treatment that would benefit from long term, targeted release in the well.


Figure 2. Customising the microencapsulation process to achieve different tracer release rates.

22 | Oilfield Technology September/October 2020

Though still in a field-trial stage of development, microencapsulated tracers are a potentially disruptive technology to traditional well inflow diagnostics. Maintaining all of the advantages of tracer studies to date, including low-cost, the lack of well intervention, and operational simplicity, microencapsulated polymer tracer rods take a technology proven outside of the oilfield and achieves new limits to the lifespan of tracer studies. By controlling the distribution of microparticle sizes and rate of tracer release, microencapsulated tracers promise a customisable solution to reservoir diagnostics.

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A SWEET SOLUTION Tom Swanson, Solugen, USA, discusses a novel oxidant and sugar derivative, designed to improve saltwater injection challenges.


il and gas operations rely on the ability to process produced water economically and responsibly. Some of the common methods for produced water handling involve reuse in oil and gas operations and, when required, at the end of the lifecycle is disposal. The oil and gas industry utilises a network of salt-water disposal wells which are regulated by state and federal agencies and are designed to inject spent produced water deep into the earth, beyond usable water tables. Oklahoma’s Scoop and Stack Basin, US, produces large amounts of water from high water cut wells. This produced water is used in oil and gas processes

until the chloride levels are beyond reuse purposes. Commercial saltwater disposal systems in Oklahoma play a critical role in accepting used produced water from centralised locations and utilising methods of sterilisation and pre-treatment before injecting into deep wells.

Saltwater disposal Saltwater disposal (SWD) operators are faced with a myriad of challenges, including the precipitation of metal salts, which can be found at high concentrations in the saltwater and known to precipitate and block flowlines and tubing systems.

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In some SWD operations, water is prepared for injection through a process of forced precipitation which involves the use of oxidisers. The oxidisers chemically convert the metal salts into precipitating oxides and hydroxides which then can be separated from the water and disposed of in environmentally acceptable landfills. The remaining water is then conditioned with additives to prevent the residual dissolved solids from forming scale within the tubing or reservoir to which they are injected. Scale formation can reduce the life of the saltwater injection well and add higher operational costs to the overall process to remediate damage or, in extreme cases, damage the injection well beyond economical repair. Although oxidiser precipitation is a common practice, it is almost never a complete process due to atmospheric exposure, incomplete mixing, and inadequate chemical concentrations to match the volume and chemical makeup of the arriving water from various sources. Table 1. Ionic makeup and water analysis and scale prediction Brine composition pH


Calcium (Ca), mg/L




Iron (Fe), mg/L


Specific gravity


Magnesium (Mg), mg/L


HCO3, mg/L


Sodium (Na), mg/L

10 911

Chlorides - CL, mg/L

17 000

Barium (Ba), mg/L


Sulfate - SO4, mg/L


Strontium (Sr), mg/L


Probable mineral composition Calcium bicarbonate mg/L


Magnesium bicarbonate mg/L


Calcium sulfate mg/L


Magnesium sulfate mg/L


Calcium chloride mg/L


Magnesium chloride mg/L


Figure 1. The furthest left corrosion coupon is the BioChelantTM tested in neat form vs other chelants. Table 2. Injection performance data Product


Injection pressure (psi)


Hydrogen peroxide combined with corrosion and scale inhibitor




Biochelant and oxidiser combination product




Biochelant and oxidiser combination product




Biochelant and oxidiser combination product




26 | Oilfield Technology September/October 2020

Enzymatic oxidation To address the issue of oxidised induced scales, advances have been made in bio-chemical manufacturing with enzymes and renewable organic feedstocks. These new bioreactors use corn sugar and enzymes in a process called enzymatic oxidation. The process starts with a renewable feedstock, such as corn sugar, which is enzymatically converted into oxidised sugar with a byproduct of hydrogen peroxide. This chemical reaction is unique in that the oxidised sugar is co-existing with the oxidiser in a chemically stable form making its use as a single product viable. Economics are favourable for this combination chemistry due to the low cost of the available feedstock and manufacturing process. This unique process is also carbon negative compared to other chemical manufacturing processes. The oxidised sugar has benefits in oil and gas as it has exceptional performance in solubilising metal ions, thus preventing them from forming precipitating scale in the salt-water disposal operations. Additionally, the oxidised sugar can be deployed with an oxidiser in one product thus reducing the costs of maintaining and acquiring additional chemical injection systems. Furthermore, the required concentrations are lower than traditional chemistries due to the non-neutralising effect of the oxidiser on the secondary product.

Case study An opportunity to test this new chemistry in the Scoop and Stack Basin in Oklahoma was of interest due to the known challenges of injection pressures due to scale and the wide use of oxidisers. The candidate facility was at a saltwater disposal facility processing and disposing of approximately 30 000 bpd of water. Water was being trucked into the facility and pumped to an open earthen lined pit for processing. During the transfer, hydrogen peroxide or peracetic acid was applied to neutralise hydrogen sulfide gas and begin the oxidation of metals from the water. Throughout the continuous process, the calculated retention time in the pit for the water was measured at over 24 hours. After treatment in the pit, water was transferred to a series of serge tanks where corrosion and scale inhibitor were injected and finally the saltwater was then pumped into the disposal well. The disposal sources of water contained high concentrations of prevalent metals which were predicted to form scales of calcium, magnesium salts without further oxidation and iron oxides/hydroxides when hydrogen peroxide or peracetic acid were deployed as the primary oxidiser (Table 1). Furthermore, the pH of the source water was near neutral (7) and therefore posed additional risks to the solubility of salts in general. The operator of this facility noted that injection pressures were increasing over time, which increased concern that scale was forming in the injection tubing. The primary injection of hydrogen peroxide (34%) averaged 200 – 300 ppm depending on the concentration of hydrogen sulfide and content of the metals in the arriving water. The scale inhibitor deployed on this location was a phosphonate and the corrosion inhibitor, was a quaternary amine at a total combined dose rate of 30 ppm based on the total volume of water. There were two injection sites for both products since they could not be combined due to chemical compatibility. Prior to recommending changes, an investigation was performed regarding the performance of the scale inhibitors in the presence of the oxidiser. A water sample was obtained and tested on a MilliporeTM filtration apparatus at 20 psig, 0.45 micron filter paper, and 1 l of water. Various dosage rates were evaluated with similar results. The filters were evaluated with wet chemistry techniques and it was determined that there was appreciable iron, calcium, and magnesium-based oxides and hydroxides present. Due to the fact these scales were present and water analysis predictions indicated that these scales were expected



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to form, the next phase of the project was to look at oxidiser compatible scale and corrosion inhibitors as suitable replacements. In this process, oxidisers are required to sterilise the water and neutralise hydrogen sulfide. Therefore, attention was turned to available oxidiser compatible sequestrants (also known as biochelants from the process and feedstock from where they are derived). These biochelants are the oxidised sugars from the process previously described to produce hydrogen peroxide. The unique property of biochelants, is they have binding sites for metals and create a water soluble, not precipitating form which is suited for these types of applications. A second function of the biochelant is its ability to inhibit corrosion in oxidised water. The biochelant’s carbon backbone contains a series of hydroxyl groups which when applied in aqueous systems prevent oxidation at the metal surface due to concentration gradients at the metal surface. Additional laboratory testing on these biochelants were conducted in high concentrations at 150˚F for 72 hours and the corrosion rate was calculated at less than 2 mpy (Figure 1). As noted in the carbon steel coupons, there was no signs of pitting or surface deformation when compared to oxidise water without biochelant present. Based on this knowledge, a formulated hydrogen peroxide and biochelant blend were prepared for testing and evaluated using Millipore filtration. Post filtration of the treated water, it was noted that the filters were absent from metal oxides and hydroxides which remained soluble and passed through the filter material, therefore it was deemed as a viable test chemical for this system. The formulated product referred to as an oxidising biochelant and was used to replace the 34% peroxide and multifunctional corrosion and scale inhibitor at similar dosage rates to compare differential injection pressures over time.

It was noted that after 24 hours the injection pressures began to reduce which was in alignment with the filter’s absence of iron precipitant. Overall, the differential pressure was reduced by 175 psi, allowing additional water to be injected without concern regarding the integrity of the tubing cleanliness (Table 2). The reversal of pressure under similar conditions was a key factor in assuring that scale formation was not attributing to the potential early failure of the injection well. Post test data indicated that an optimum dose rate would be pre-determined by the ionic makeup of the source water and presence of hydrogen sulfide with this combination product. The prevailing component was hydrogen peroxide with secondary component of the biochelant which required lower overall concentrations. Additional optimisation steps were taken to further refine the application, but the concept of combining an oxidiser and scale/corrosion inhibitor proved to be successful as a combined product with performance and economic advantages.

Conclusion Biochelants derived from oxidised sugars are an economical solution for salt-water disposal systems, which are plagued by metal scales as a result of the oxidation process. These biochlelants can be produced from a renewable source and offer economical solutions for oil and gas operations where low environmental risk is needed and to maintain flow assurance in salt-water disposal systems. Future areas of interest for produced water in the future are the re-purposing of water beyond disposal where additives will need to be non-toxic and have a low environmental impact for future considerations.

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DEVELOPMENT DOWN UNDER Hans Sturm, Curtiss-Wright EST Group, USA, presents a novel isolation approach designed to bring speed, safety, and security to pipeline valve replacement.


hen a pipeline valve needs to be replaced, safety and speed are key considerations. However, when the pipeline cannot be fully drained of its contents and depressurised, these considerations take on a whole new sense of urgency. This was the case for an oil and gas operator working off the coast of Australia. The operator needed to replace a blowdown valve on a spool filled with hydrocarbons on one of its offshore platforms. They wanted to avoid the conventional process that requires flushing, purging, and then drying the entire spool volume prior to performing the changeout, all of which would add a great deal of time and money to the project. Further complicating the process, the valve changeout had to be done while ensuring that the spool was completely isolated at all times. There could be no oxygen ingress to the line and no release of hydrocarbons into the atmosphere.

Field-proven solution Curtiss-Wright EST Group proposed a solution that previously proved successful for the operator in other ‘tie-in’ applications, such as installing new flanges

into existing pipework: the double block and bleed (DBB) test and isolation plug. The DBB is widely used to isolate and monitor potentially explosive vapours from upstream gases or hydrocarbon fluids in a vessel or pipeline during modifications or repairs requiring hot work. The plug’s dual-cavity port creates a completely air-free, positive pressure barrier between its seals, allowing isolation for welding activities and hydrotesting of new weld connections to be performed with the same isolation tool. Traditionally, this plug is used to increase the safety for welding activities and gives the operator the ability to hydrotest the new weld between the seals with less than one gallon (3.785 l) of water. This reduces fill times, waste water, and treatment expenses while facilitating testing in remote areas of the facility. The dual port system also allows water to be circulated between the seals for improved cooling during pre- and post-weld procedures. The standard plug’s seal is pressure rated to 2250 psig (155 barg), with upstream pressure rated to 10 psig (0.7 barg). Higher pressure ratings can be achieved with special plug designs.

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The plug’s lightweight, predominantly aluminium construction makes it significantly lighter than other plugs. An 8 in. schedule 80 plug, for example, weighs just 36 lbs (16.3 kg) while similarly sized plugs typically weigh in excess of 100 lbs (45.4 kg). This allows operators to avoid the use of cranes or other heavy lifting devices, which are often in high demand during plant turnarounds.

A novel installation approach While the operator was confident that a standard DBB would effectively isolate the line during the valve changeout, the installation process presented some challenges. The valve would have to be opened to allow the plug to pass through to its set point, which would expose the system to oxygen. Working in collaboration with its Australian distributor PipeServ, EST Group developed a customised plug and installation strategy, with the ultimate goal of making plug installation as efficient, seamless, and risk-free as possible, without adding to the operator’s maintenance budget. The solution included a custom launching spool assembly that housed a specially designed, hydraulically actuated DBB test and isolation plug (Figure 1). The launching spool and DBB were designed to safely isolate the valve during changeout through the following installation process. First, the spool assembly was attached to the valve flange. Then, the DBB was inserted into the spool assembly with a lanyard and the chamber was sealed with a flange. Nitrogen gas was introduced between the flange and the DBB plug to displace all oxygen from the system. With the launching spool closed off and no oxygen present, the valve was then opened to allow passage of the plug. The DBB was pushed out of the launching spool assembly, through the valve and extended into the line with a long push rod to isolate the valve flange while the upstream chamber was pressurised with nitrogen. The assembly was designed to ensure that the DBB would be positioned in the line precisely where it needed to be with a predetermined measurement verification marking on the lanyard. The position of the plug in the line made the conventional actuation process of mechanically activating the plug by manually torqueing the nuts on the shaft of the plug impossible. The system was under pressure and closed off from the atmosphere. This necessitated the special hydraulically actuated plug, which included a hydraulic piston cylinder internal to the DBB. The cylinder was activated by energising a hydraulic hose that fed to the plug. As the cylinder moved, it compressed the seal material forming a leak-tight seal on the two locations on the pipe wall.

During deployment of the plug, the team had to develop a way to not only extend the plug to its setting location and safely bring it back, but also maintain pressure boundaries between the hydraulic hose assembly, connections, fittings, and gauges inside the launching spool assembly and the atmosphere. The solution was to route the hose assembly around the push rod in a spiral. As the plug was moved into position, the assembly extended like an unravelling spring to ensure service to the test plug was maintained while the plug was extended. Once the seals were compressed, the hydraulics were locked and monitored and remained in the system – along with the plug and the rod. To ensure that the plug was fully engaged with the pipe during the entire process, the team had to continuously monitor the pressure at the plug. The plug was positioned in the line such that the two seals straddled a 4 in. auxiliary pipe running off the main line. The team pressurised the auxiliary line and monitored it for any drops in pressure, which would indicate that one or both seals was leaking. With the plug secure, the nitrogen pressure was released, and the launching spool assembly and failed blowdown valve were safely removed. A new valve was securely installed. The launching spool assembly was reinstalled to the new valve flange and the process was reversed to safely remove the special DBB plug. The entire process enabled safe replacement of the blowdown valve while maintaining a nitrogen-rich environment to ensure no hydrocarbons escaped and no oxygen entered the system.

Success through collaboration

The company needed to operate under a tight timeline to ensure successful execution of this project. Working closely with the operator’s team to ensure it met all of their specifications, they able to develop the hydraulically actuated DBB plug and successfully deliver it within the short window of opportunity. The plug was flown to the offshore platform by helicopter where the operator’s maintenance crew performed the installation successfully. In addition to the operator’s crew, a dedicated PipeServ technician was on site during the process to ensure the valve change-out went smoothly. The crew was able to perform the valve replacement in about one day, realizing a significant cost savings in time and labour for the operator, over the 4-day schedule originally planned. Remote technical support, and detailed installation instructions provided with the plug were contributing factors to the success of the project as well. Rather than flying an application expert to the site to oversee the process, which would have added significant cost and additional days to the job, the operator’s maintenance crew were able to perform the repair easily and efficiently by following the detailed installation steps. The custom solution not only delivered significantly lower repair costs vs a traditional valve replacement procedure, but the operator was able to keep their crew safe and the integrity of the pipeline and other equipment intact as well. The operator plans to document the success of this project to standardise similar procedures for other valve Figure 1. The DBB housed in the spool assembly prior to deployment (top), and after it has been deployed through changing applications. the valve and into its setting position by the push rod (bottom).

30 | Oilfield Technology September/October 2020

The value of a


Brent McAdams, OleumTech Corp., USA, explains how well-chosen automatic tank gauging technology can increase the oilfield’s overall production.


n the oil and gas industry, hydraulic fracturing (fraccing), horizontal drilling and the utilisation of multi-well pads have allowed producers to maximise returns from each location. As a result, extremely large volumes of oil and liquids are being produced on a daily basis from each site. However, the multiphase flow characteristics of these unconventional wells make accurate tank gauging extremely challenging, as wells will produce varying amounts of oil, water, condensates and natural gas

components. Regardless, tank gauging in itself is an essential element of inventory control and custody transfer, enabling any Blockchain strategy as well as having the ability to provide leak detection. Extremely reliable and accurate tank level measurement is therefore essential to each producer’s operation. Automatic tank gauging (ATG) provides a means to automate this process, allowing producers to reduce costs, maximise efficiency and provide a safer work environment for all employees.

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ATG technology has now been around for several decades, but few products have been trusted to the point of using the device as a de facto standard. While many products have been introduced into the market over the years, the challenging process conditions make it extremely difficult to operate reliably enough to meet the expectations of the industry. Not only are these unconventional wells producing oil, water, condensates, and natural gas, but they are also producing corrosive gases that can destroy level sensors in a matter of weeks. In addition, paraffinic build-up and scaling can occur on a level sensor, significantly affecting the accuracy of the measurement, leading some producers to pull their sensors every 30 days for maintenance. However, some manufacturers have fortified the technology, which has led to increased reliability and accuracy. The components of an ATG consist of the level sensor and either a wired or wireless transmitter head. The sensor can either be rigid or flexible and is sized based on the actual tank height, providing some contingency for adjustability during installation. For most applications in shorter or turbulent tanks, a rigid sensor is utilised. The rigid sensor seats all the way on the bottom of the tank and is provided with either one or two floats. While a single float will measure top-level product only, the dual floats will measure both top-level product and the product/water interface level. The sensors are also supplied with an integral resistance temperature detector (RTD) for temperature measurement of the fluid in the tank. For taller tanks, especially those that are 15 ft and above, a flexible level sensor is installed. The value of the flexible level sensor is that one person can complete the installation in a matter of minutes, as illustrated in Figure 1, whereas with a tall rigid sensor multiple people or even a crane would be required to complete the installation. Like the rigid sensor, the flexible sensor is provided with either a single float or dual floats. However, unlike the rigid sensor, the flexible sensor hovers slightly above the bottom of the tank and uses a weight kit to keep the sensor taut while allowing for minimal thermal expansion and contraction. The transmitter head can either be wired or wireless and is secured to the level sensor by means of a quick connect connector that is hand tightened, making the installation easy. The wired transmitter head is externally powered and may be daisy chained to other wired transmitter heads using RS-485 in a multi-drop fashion. In this case, intrinsically safe barrier boards must be used to maintain area classification between the hazardous and non-hazardous locations. The wireless transmitter heads are entirely self-contained, battery-powered and intrinsically safe. By being intrinsically safe, these wireless transmitters can be installed in Class I Division 1 environments where there are always explosive liquids, vapours, and/or gases present, and the transmitter will not generate enough energy to cause a spark in the hazardous environment. The battery life can be up to 10 years, based

Figure 1. Tightening the compression fitting and completing the sensor installation.

32 | Oilfield Technology September/October 2020

on user defined transmit intervals of 45 seconds and greater. This includes powering the sensor as well as the wireless transmitter. As a result of these benefits and return on investment (ROI), wireless ATGs have been adopted by many large producers. From an architecture perspective, the wireless ATG transmitter heads report back level(s) and temperature measurements at user-defined transmit intervals to a wireless gateway. The wireless gateway is a point to a multipoint device acting as a data aggregator, offering significant economies of scale as it will support dozens of wireless transmitters. This enables producers to bring back more than just tank data. For the incremental cost of the sensor and wireless transmitter, the same gateway can accommodate wellhead pressures, temperatures, flows, etc. Another significant advantage of wireless over wired is that the former is not susceptible to noise being introduced into the system, in contrast to some wired architectures. This noise could be introduced into the system from a water hauler with a pump that is not properly grounded, meaning the pump is creating static electricity and feeding it into the facility. Without proper grounding, a wired system will interpret this as noise, impacting communications and the accuracy of the measurement. The noise could also be introduced by thunderstorms passing through the area. In addition, oilfield growth is outpacing electrical infrastructure build out. Using self-contained, battery-powered wireless sensors minimises power requirements for each site.

Business justification and return on investment Many producers look at the initial cost of ATGs and assume that the technology is cost-prohibitive. However, a device that is trusted provides true value all the way through custody transfer. This means the ROI is achieved much sooner than most realise, especially when looking at key performance indicators (KPIs). The most intuitive is that, from a KPI perspective, every employee has an hourly wage associated with them. An example may help to illustrate this: a facility has three tanks for which an employee is required to properly gauge and check bottoms. It is estimated that the employee will spend approximately 20 minutes on the tanks. After extrapolating that out to 25 sites, every day, 365 days a year, it can be deduced that, with a trusted device, visits can be cut to four times a year doing quarterly calibrations. How much money was saved? More importantly, how long did it take for the ATG system to pay for itself? While producers can enter their own hourly wage KPI numbers into the formula to extrapolate individual ROI, the short answer is not long at all.

Benefits The benefits of ATGs go well beyond just the immediate ROI. In addition, efficiency and visibility are greatly enhanced. For instance, if a producer is fraccing on a new well and happens to hit other wells in the area, they now have that visibility. Since all well sites are communicating and reporting back tank information, suddenly these wells are producing substantial amounts of water. In addition, wells that did not need supervision now need a flow back unit on each site. The value of having a trusted device on the tank is that, while a flow back unit on each site may be needed initially, the probability of having personnel onsite for the long-term is minimal. The reason for this is that producers need only have one resource going from site to site to double check operations once or twice daily. Efficiency is greatly increased, and additional resources saved by not having to deploy dedicated personnel on each site. Furthermore, from an efficiency perspective, dispatchers have visibility into the entire field. Analytics can therefore be utilised, allowing reports to be generated every 12 hours (e.g. 06:00 and 18:00). With the information contained in these reports key personnel throughout the organisation know exactly what is in the tanks and what they are hauling.

In addition, data is available to optimise routes as some sites may not even need to be visited, having not produced any oil at all. Not having this data available would cost money and time from the dispatching of trucks for zero benefit. This also enables the company to determine whether a site produced more than it was supposed to or did not produce any oil at all, providing additional evidence that the gas lift or compressor went down. It also provides the visibility that there is oil in a water tank. Regardless of the scenario, personnel can be notified to take corrective action to prevent any long-term impacts on operations and tank inventory. One of the other significant benefits of having ATGs is surveillance. Many people in the industry are relying on cameras which, from a visual aspect, is understandable. However, it is difficult to know what that visual is truly telling producers about their equipment and what is actually in the tank. Some in the industry are migrating to acoustics but as soon as a thunderstorm passes through the baseline is skewed, creating significant headaches for not much value. Lastly, safety is perhaps seen as one of the biggest benefits of having a trusted device. With a trusted, field-proven device that is only visited four times per year, top of tank exposures are limited, thereby reducing human exposure to hazardous environments. In addition, by making the truck drivers, water haulers, and oil haulers more efficient, the roads are safer for everyone.

What makes a device trusted? This article has discussed at length the ROI and benefits of a trusted device but, because of the mixed record of ATGs, it is also important to consider what makes a device trusted. According to an automation technician at one of the world’s largest producers – who previously worked as a production specialist focused on downhole applications and worked in slop facilities, which required taking the worst of the worst liquids and making them into good oil, meaning that they had to understand fluid

properties – it is crucial to understand that the conditions of the tank have a significant impact on ATG performance. It is easy to blame the device and say that it is wrong. Typically, what happens is that a technician is dispatched to travel to the site and calibrate the device. However, without truly investigating what actually caused the inaccuracy, the assumption is made that something is wrong with the device or, perhaps, it has drifted. The recalibration may very well be introducing additional error into the measurement. In reality, something changed within the tank and now when fluid is rolled the measurement is now out of tolerance based on the offset introduced during the recalibration process, resulting in self-inflicted issues. By going through the investigation process and ultimately understanding exactly what is happening in the tanks, the device becomes proven and trusted over time. Therefore, when issues arise, the focus of evaluating the root cause goes beyond blaming the device. It allows companies to focus on the device last and rule out everything else first instead of running in circles, wasting time and resources. This approach also removes the undesirable possibility of calibrating the device out of tolerance, only to find when conditions stabilise and return back to favourable within the tank the offset introduced becomes the actual issue. The same automation technician said that they consider a failure more than just a failure. They categorise failures based on their own experience, as defined below: Operational failure – ultimately falls within human error in terms of who gauged the tanks. How did they gauge the tanks? How long were they turned out of the tanks? What was the temperature? What was the condition of the fluid? If the tank has been sitting stagnant and the temperature is 30˚F or below with paraffinic oil and chemical(s) are not being injected into the tank, they know from experience the float will be sitting slightly higher on the fluid than when starting to produce into it. If that happens to be the time the device was calibrated, an error was just introduced.


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Mechanical failure – this failure falls into the category of the wired or wireless transmitter head that is connected to the sensor, including a depleted battery. It could also be a result of an issue with wireless communications from the transmitter to the wireless gateway. It could be as simple as a new remote terminal unit (RTU) that was connected to the gateway and the communications interface settings are incorrect in terms of baud rate, parity, stop bits, etc. or could be the result of a lightning storm in the area that caused damage to an antenna. Device failure – this is actually where the level sensor fails. With a trusted device, operational and mechanical failures are ruled out first and this is the last part of the troubleshooting process. In reality, the device should be the last thing that any producer should worry about.

As mentioned, ATGs have been installed for decades. With the challenging conditions the devices are exposed to, much of their record is not good. Therefore, the culture in the oilfield industry is to not trust the device. That being said, it is important to note that not all ATGs are created equal. Regardless of this, for some manual tank gauging is seen as superior over ATGs but that is not the case. Looking at the issue from the perspective of having two different linear devices may provide an answer. The first is a fixed length, digital linear device. The second is a mobile linear device, which has many moving parts and variables, including a plumb bob (or plummet). In addition, it could be a windy day, rainy day, hot day, or any combination thereof. A tank gauger can simply walk on top of the tank and drop the device into the tank but where was the plumb bob actually placed? How was the level actually checked with the device and was it identical to the previous check? Which is more likely to introduce the error: the fixed length digital linear device or all of the random variables introduced with the mobile linear device? While the answer is clear, there are still people in the industry that put trust in the mobile device. From a temperature measurement perspective, the digital device is more accurate and consistent. This is because even though the temperature is being taken from one consistent spot the temperature is taken at the beginning of the load but then the tank is stirred during the load, allowing for better temperature transfer. This means the temperature reading is better than simply going in and averaging temperatures from the bottom to the top of the tank; the sun could have possibly been shining on the back of the tank, introducing even more variability in the overall temperature reading. In the case of ATGs, the temperature is taken at the front of the tank where it is going be more consistent with a digital field device than a hand gauging method. That alone makes it more efficient. This is not appreciated by many people simply because they do not understand fluid properties with respect to temperature transfer. In the summer, temperature transfer is much faster because, as things heat up, molecules move much faster. In other seasons, especially where the temperature falls significantly during the night and rises during the day, the temperature swing throughout the fluid will be dramatic. In addition, if the tank has water pockets or any emulsion, temperature variations will exist throughout the tanks, as water holds temperature better than oil does. This means pockets could exist within the tank that are different in temperature by as much as 7˚F from the rest of the tank.

Other technologies While the most success has been achieved with float-based, resistive technologies, there are certainly other technologies available. Some operators use Hall effect type sensors, which do have advantages in terms of resolution and are very consistent – limiting the amount of drift that can occur – but are less robust. In addition, they are not intrinsically safe and cannot be sealed. In addition, the transmitter head has neither an available local display to allow the operator to be able to read the tank

34 | Oilfield Technology September/October 2020

variables directly from the top of the tank, nor does it have a wireless transmitter head offering. Guided wave radar (GWR) is another technology that has gained considerable traction in the past few years. It uses many formulas embedded in firmware to calculate and identify where the product level is, as well as the water interface level. However, it is unclear that it adjusts to the conditions of the tank as well as float-based technology. As a result, most companies will have to employ personnel to go and check these devices on a regular basis. In additional to these frequent checks, many GWR manufacturers recommend pulling and cleaning the sensors due to scaling and paraffinic build-up concerns. Both conditions cause false readings and, because of the potential for measurement error since all the variables are being calculated, it acts much like a nonlinear device. Conversely, having a linear device pushes out these checks to a quarterly basis, resulting in significant savings in terms of maintenance costs and results in an immediate payback for the deployment of ATGs. Perhaps the most alarming feedback received is that most producers do not actually pull the GWR sensor for cleaning – they access the cable through the thief hatch, which is a clear violation of safety standards and puts employees in harm’s way. This also means that when these quarterly checks are performed and the top third, middle third, and bottom third of the tank is seen within tolerance, it is considered a ‘calibration’, meaning the device does not actually have to be touched. With GWR, this is not the case as a minimum of annual calibrations are required. From a cost perspective, consider a field that consists of 100 tanks. There is considerable cost associated with this, as full-time personnel would be required just to do annual calibrations. In addition, a truck must be dispatched to move the fluid around in the tanks to be able to achieve the top third, middle third, and bottom third calibrations. Therefore, two people and two trucks must be dedicated to this effort year-round simply to maintain the devices, not to mention the time it takes to move the fluid around in the tanks. To alleviate scaling and paraffinic build-up, some designs of the resistive, float-based technologies have been fortified through material selection and float design. The end result is a sensor design that provides reliable, accurate level measurement without requiring the routine maintenance that other technologies do. Providing additional confidence to producers, these manufacturers have gone so far as to provide a limited lifetime warranty against hydrogen sulfide damage, scaling, and paraffinic build-up.

Conclusion As noted, the multiphase flow characteristics of unconventional wells make accurate tank gauging extremely challenging. However, today’s sophisticated ATGs can measure levels for two liquids to within a 1/8 in. accuracy over the height of any tank and provide temperature measurement to allow sellers and buyers to reconcile volumes based on temperature, which is paramount for any Blockchain strategy. Ultimately, ATGs are capable of doing considerably more than the majority of companies realise. Most companies seem stuck on lease custody transfer because the perception is that it is much harder to implement than it actually is. However, with a trusted device, not only can short-term ROI be achieved but, as discussed, there are many other benefits to having a field-proven, trusted device. Automation is just one piece of the overall puzzle that can directly affect the efficiency of how companies produce on wells. With an ATG, while resources are still visiting the site, less time can be spent on the actual tank(s), allowing more time to focus on the separator, a chemical tank, a pump, or whatever is local to that site. As a result, ATGs help increase overall production for the field, management, and the entire company, which should be the shared common goal for everyone involved.

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FLATTENING Eugene Sweeney, Well Control School, USA, investigates the educational methods being used to instil retention-driven well control skills in the workforce.



CURVE 36 |


t does not take much imagination to envision a future where automation and artificial intelligence (AI) make (or at least ensure) many of the critical decisions to maintain proper well control. Such a future remains distant at best however. Until then, robust practices carried out by highly trained, competent people continue to be the most important well control barrier for the foreseeable future. Well Control School (WCS) has developed a system technology to strengthen and ensure this barrier. The newly-developed SMART knowledge retention programme combines e-learning with instructor-led training to instil retention-driven well control skills and knowledge training.

Strengthening the well control practice barrier What does a Prussian soldier-turned-psychologist, who died more than 100 years ago, have to do with ensuring healthy well control barriers in today’s fields? More than one would think. While people have long known that the mind is a complex machine, constantly learning, remembering and forgetting information, it was Hermann Ebbinghaus who first quantified some of the most important nuances of how our minds learn and remember. After fighting in the Franco-Prussian War in 1870, Ebbinghaus became a giant in the infant field of psychology and cognitive science. Some of his cognitive paradoxes, such as the example shown in Figure 1, have become familiar to many. Ebbinghaus was also the first to discover the theory commonly known as the ‘learning curve’. Most relevant for the purposes of this article however is his discovery of the ‘forgetting curve’. Most people are familiar with the concept of the learning curve: knowledge is gained over time or a task is learned after repetition. A steep learning curve usually means a task is difficult to learn with rapid progress or knowledge attained at the beginning. The forgetting curve describes the exponential loss of information that has been learned. Figure 2 shows a representation of that loss over time. Ebbinghaus showed that learners forget 50% of what they just learned within an hour, 70% within a day and a 90% in a month. The critical decision-makers, both at the rig site as well as those that direct and engineer actions from the office, comprise the frontline defence for ensuring crews maintain well control and safe operations. This human barrier is critical.

The strength of this barrier is verified every two years through the process of well control certification. Would confirming other critical barriers, such as blowout preventer (BOP) testing, only every 2 years ever be considered? The question becomes even more daunting when the forgetting curve is considered. How can it be known for certain that people are going to make the right critical decision during a high-intensity situation, say 18 months after they have been certified when they may have forgotten more than 90% of what they had learned? Luckily, there is an answer. This knowledge decline can be limited by leveraging another Ebbinghaus discovery, known as ‘cognitive savings’. Ebbinghaus quantified the phenomenon of subconscious knowledge, stating that knowledge is retained in the subconscious even if it is not readily available to the conscious mind. The ‘savings’ mean that when something is relearnt, it is achieved more quickly, i.e. the new learning curve is shorter. This has the additional effect of flattening the forgetting curve when relearning or refreshing memore (Figure 3). Based on cognitive savings, interval repetition becomes the best method for reducing ‘skill fade’.

Using technology to combat skill fade WCS began development of the programme with the specific scope to find the best technological solution to well control learning retention. By doing so, the aim is to ensure that when a critical decision is made or planned even 18 months after an employee has gone through certification, he or she will perform the task with the same skills displayed immediately after successful completion of well control training. The basis of design was to address skill fade while implementing the most effective, proven e-learning techniques. Among these are: Learning platforms with optimal module sizes – studies have shown that brief, targeted learning modules are better retained than longer ones. Optional assessments – users assimilate key takeaways more efficiently through use of assessments. These help to move information from working memory to long-term memory. Cater to different learning behaviours through a multimedia approach – all people learn differently. For example, some retain


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knowledge best through visual, some auditory and some through hands-on training. Empowering learners to take control of their training – knowledge is best gained and retained when learners can take control and become invested in expanding their skills. The programme can be accessed any time during busy schedules and can be used as a refresher. During actual situations, workers can find what they need, when they need it. Effective use of graphics, pictures, charts and other learning modes – the human brain remembers images more effectively than text, so visual summaries help to boost knowledge retention and active recall. Spaced reinforcement and repetition – the brain needs to take breaks to allow knowledge to assimilate and avoid cognitive overload. Multiple activities – SMART learners are exposed to, review and reinforce important well control concepts multiple times. Prior to classroom learning, they watch e-learning tutorials. Then they are given classroom learning with extensive simulations. After taking their

Figure 1. The Ebbinghaus illusion: the mind perceives the orange circle on the left to be smaller than the one on the right, when in reality they are the same size.


assessment, any questions missed are reviewed face-to-face with the instructor. Afterwards, short learning modules are scheduled to be pushed to the learner at set intervals – three months, six months, etc. – which include assessments to ensure knowledge retention. Access to experts – sometimes individual teaching is the best way to learn and experience, and insights are needed to explain things when learners face a question or situation they do not understand. The programme includes easy access to well control experts available 24/7 by email or phone.

Programme development The project began with the development of more than 400 learning modules that incorporate all of these important requirements. The content covers all of the learning objectives required by current industry standards. The learner is supported before, during and after the certification process. By delivering well control training in short bursts, or ‘micro-courses’, learners quickly review topics they may already know, giving them time to focus on less familiar topics. This also makes the system a good tool to use to prepare for formal training. While in class, students can use micro-courses to help clarify topics covered in that very class or to help prepare for the next day’s class. Once enrolled in the system, each learner has access to all the courses for the duration of their enrollment. The programme also creates courses and knowledge assessments for each learner, assigned to pre-determined dates throughout the certification period. Completing the courses boosts the learner’s retention skills and remediates topics missed on prior certification exams. This helps ensure learned objectives are not forgotten. Knowledge assessments help gauge the effectiveness of the training and can signal a need to increase or decrease the amount or frequency of training required. The full system includes: Pre-course study: prior to formal certification assessments, trainees can prepare at their own pace. Training administrators can coach and evaluate each trainee’s progress in real time, helping assure better results. The trainee feels more confident in a positive outcome when prepared. Self-study: trainees can access the library at any time and reinforce any instructor-led or facilitated training. Missed objectives review: all material within the library is keyword-linked to specific industry training standard learning objectives. Students can easily access and review any topic missed on certification tests immediately or at any time within the subscription period. Continuation training: training administrators assemble multiple micro-courses specific to industry learning objectives and schedule them to be taken over time. Interim assessments: knowledge retention is evaluated by conducting individual assessments between certification renewals. Retention assessments will identify any need for remediation of knowledge gaps.


Figure 2. The forgetting curve: people forget most of what they learn within

days or even hours.


The programme in practice

Figure 3. Flattening the forgetting curve: through periodic check-ins people can dull or remove the forgetting curve altogether.

38 | Oilfield Technology September/October 2020

The company has begun implementation of the programme for all well control training. While the time has not yet been reached for the interval check-ins, strong benefits from the front-end have already been observed. Students who have used it are seeing that the system allows for a greater command of both basic and advanced well control concepts. By incorporating proven techniques that cognitive science provides about learning, students can more readily and rapidly recall critical knowledge when most needed – during time-sensitive situations. Subconscious knowledge becomes working knowledge through systematic repetition and reinforcement. In other words, well control skills become ‘second nature’, enabling learners to act confidently and make the right decision.

SOUND Yasuyuki Kawasumi, Yokogawa Electrical Corp., Japan, explains why continuous monitoring of noise levels in upstream facilities is a critical step towards improving hearing conservation programmes.


he oil and gas industry, particularly the upstream segment, has many potential hazards. The dangers of flammable and even explosive products are made worse by the presence of toxic hydrogen sulfide. People tend to fixate on the potential for fatalities, but there is a far less visible yet insidious hazard: hearing loss. Given the numerous more obvious safety considerations, hearing loss does not always get the attention it deserves. Nevertheless, the problem is widespread and can affect a high proportion of workers if not dealt with correctly.

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Upstream sites generate noise from two types of equipment: temporary (e.g. drilling and completion machinery), and permanent (e.g. pumps, compressors, and other installations that continue to operate during the life of the site). Land-based facilities are less hazardous in this regard, as equipment is typically spread over a larger area and some can be located outdoors, whereas offshore platforms contain more equipment in smaller and more confined spaces. Table 1. Hearing protection regulations in selected countries Country

Exposure limit value



83dB(A), 12h 85dB(A), 8h

NORSOK standards S-002 Working Environment


87dB(A), 8h

Control of Noise at Work Regulations 2005


90dB(A), 8h

OSHA standards 29 CFR 1910.95 Occupational noise exposure


90dB(A), 8h

Norma Oficial Mexicana NOM-011-STPS-2001


85dB(A), 8h

National Standard for Occupational Noise [NOHSC: 1007 (2000)]


85dB(A), 8h

Factories and Machinery (Noise Exposure) Regulations 2019

China National Offshore Oil Corp. (CNOOC) conducted a field investigation in 2015 to study the effects of noise hazards on six offshore platforms. After measuring sound levels at 373 sites spread across the platforms, the study found that 70% of those sites had noise levels in excess of 80 dB(A). Even 50% of areas without noisy equipment still showed levels in excess of 80 dB(A). 1 A study conducted between 2006 and 2015 and published in the American Journal of Industrial Medicine found that in oil and gas extraction generally, 14% of noise-exposed workers suffered hearing loss. Natural gas liquid extraction was even worse, as 28% of noise-exposed workers suffered hearing loss.2 Researchers at the US National Institute for Occupational Safety and Health found these levels of noise exposure are associated with elevated cholesterol levels and high blood pressure. 3 Hearing conservation practices are a common part of worker protection regulations. Details vary, but a threshold of 80 – 90 dB(A) for a period of 8 hours is typical (Table 1). Workers exceeding the threshold as an average over the specified period of time must be included in a hearing conservation programme. Such worker protection programmes typically involve a mixture of actions: Reduce noise levels by replacing noisy equipment or enclosing it. Change operational parameters where practical so equipment can run more quietly. Compel workers to participate in hearing conservation, including testing and wearing appropriate personnel protective equipment (PPE). Remove any factors that might keep individuals from being able to use PPE effectively. Change work schedules and rotations so individuals do not spend too much time in noisy areas.



Each of these actions requires dynamic monitoring of noise levels, which can now be done using wireless systems. However, before dynamic monitoring can be implemented, baselines must be established.

Establishing baselines

Figure 1. Hand-held sound level meters are a common tool for performing manual facility surveys, but only provide snapshots of conditions.

40 | Oilfield Technology September/October 2020

Determining the need for a hearing conservation programme typically involves two phases. First, a group of spot readings can be taken with a hand-held sound level meter to determine the noise in various parts of the facility (Figure 1). If no areas are found to exceed the applicable threshold – unlikely in any industrial environment – there will be no need for a programme. If there are areas that are sufficiently noisy however, it will be necessary to determine if workers routinely spend enough hours in those areas in the course of daily operations. Representative individuals will need to wear a sound level recorder for a full shift. These recorders take sound level readings at frequent intervals, which are then averaged at the end of the shift. Time spent in quiet areas mitigates the effects of the noisy environments, which is reflected in an average along with any excessively high spikes. Noise exposure standards consider time of exposure along with the actual level, so this type of

charting is necessary to make a full determination. If the level exceeds the standard for the specified amount of time, it will be necessary to implement a hearing conservation programme for the affected worker population.

Sound mapping a facility Understanding how individuals are affected in a given facility environment requires understanding of the noise profiles of different areas, because sound is not homogeneous. Some pieces of equipment are louder than others and sound can project in unexpected ways. The typical approach for sound mapping entails a technician moving around the facility with a portable sound-level meter to take readings in a variety of locations. If done thoroughly, this can provide enough data to create a map on which the operator draws in boundaries of sound levels over a floor plan of the facility. This method, while providing a good first step, does not take into consideration the dynamic characteristics of sound, which tends to change over time, perhaps even on a daily or shift-to-shift basis. For example, if there is a compressor train with three units, the sound profile will be much different when one is running rather than all three. The PPE a worker wears when carrying out a task in that part of the facility may need to be different under one scenario than another. It may be necessary to limit the time the worker spends in that area or wait until a time when conditions are more favourable. Trying to replicate this level of detail with a static sound map is not practical.

Dynamic sound mapping Facility sound levels and characteristics change for a variety of reasons: Different operations that call for different pieces of equipment. Changes in product flows and routing through various valves and piping. Varying production levels from low to high. Deterioration of mechanical equipment, causing higher noise levels.


New sound level sensors equipped with transmitters using ISA100 wireless technology allow deployment on existing wireless instrumentation networks, so there is no need for signal wiring. The sensor assemblies can be placed at the most strategic points in a facility without adding to the wiring infrastructure. Such self-powered sensors do not require external power supplies or power wiring and can be rated for use in hazardous areas, so location concerns need not be a constraint. Using pre-configured analytical software, a map or floor plan of a facility can be created with the locations of critical pieces of equipment included along with the sensors (Figure 2). Using data collected via the wireless network, the system can monitor and record conditions, and report results to operators and maintenance technicians. Since the sensors use the wireless network, they can be relocated to help resolve complex situations. If it is necessary for workers to venture into the facility to perform a task, the current noise levels can be observed on a real time sound map and appropriate action taken.

Sound as a diagnostic tool Sophisticated sound measurement and analysis can do more than simply record basic levels. Looking at patterns of harmonics can indicate potential problems in a facility. Once the system has sufficient historical data to develop typical patterns, it can identify when conditions have changed. These might be caused by a simple adjustment of throughput or other intentional action. On the other hand, it might indicate a developing mechanical failure that could result in an unexpected failure and equipment outage. If a change in the sound profile does not correspond to a known and hopefully intentional process adjustment, it becomes necessary to look for a cause. New technologies for deploying wireless diagnostic sensors, without the need for additional wired infrastructure and custom code writing, make it less costly to protect workers and comply with regulations.


1. NING, Y. ‘A survey of current status of noise hazard on offshore oil As a result, trying to determine how much hearing protection platforms’, www.ncbi.nlm.nih.gov/pubmed/27682664 (August 2016). an individual worker has to wear to carry out a task in a given 2. LAWSON, S.M., MASTERSON, E.A., and AZMAN, A.S., ‘Prevalence of hearing loss among noise-exposed workers within the Mining and Oil and Gas part of the facility may change from day to day, and a static Extraction sectors, 2006 – 2015’, www.ncbi.nlm.nih.gov/pubmed/31347715 facility sound map cannot provide up-to-the-minute conditions. (October 2019). 3. Centers for Disease Control and Prevention, ‘High Blood Pressure and So, how is it possible to keep close tabs on facility noise levels? High Cholsterol Associated with Noisy Jobs’, www.cdc.gov/media/ In the same way that it takes multiple temperature sensors releases/2018/p0321-noisy-jobs.html (March 2018). to create a real time temperature profile in a process or environment, it is possible to deploy multiple sound level instruments around a facility. Each instrument monitors conditions continuously and reports back to a host system able to display current conditions and record the data for later analysis. The idea of deploying new sensors throughout a facility and developing the host system to create a sound map may seem impractical and too costly if carried out with traditional technologies. Adding wired infrastructure for the sensors and calling in a system integrator to create the necessary software would indeed be costly, and the prospect of obtaining sensors rated for hazardous areas might make such a project seem unfeasible. Fortunately, these problems can be overcome using newer approaches that cut costs and speed deployment Figure 2. Yokogawa’s WN30 Noise Map software creates a dynamic real time while reducing complexity. sound level map showing current and historical conditions.

September/October 2020 Oilfield Technology | 41

DOWNHOLE TOOLS REVIEW Oilfield Technology presents an overview of some of the recent developments in downhole tool technologies and services that are available to the upstream oil and gas industry.

Ace Oil Tools With the Ace Ratchet Collage (ARC), the traditional stop collar has been re–imagined to bring excellent holding force to operators looking to centralise the pipe and protect equipment downhole. Safer, more reliable and easier to install, the ARC locks together to deliver a holding force equivalent to over 90 000 lbs. Tested to withstand axial loads up to 180 000 lbs while meeting passthrough requirements, its slim design has been specifically intended for close-tolerance applications. This is important, especially where it needs to pass tight restrictions and effectively manage surge and swab. The tool makes minimal impression on the pipe and has no loose parts. The slim design also allows for faster running speeds, even in formations with narrow mud margins. The placement of a 13 5/8 in. casing string below a 17 7/8 in. liner was required in an exploration well, off the coast of Uruguay, at a record water depth. There was uncertainty about whether a 16 in. contingency liner would

42 |

be required between the 17 7/8 in. and 13 5/8 in. strings. If this was the case, it would require the use of expensive centraliser subs and traditional centralisers and stop rings to solve. To avoid this, the ARC was selected with a 1-piece non-welded centraliser to reduce the overall spend on centralisation. The collar has a 14.11 in. outer diameter and is rated to over 90 000 lbs axial load. This means it can pass through the 16 in. liner while delivering the high holding force required to ensure the centralisers remain in place on the casing string. The ARC is also designed to maintain sufficient bypass to help prevent formation breakdown during run-in. For this well, over 40 tools were installed offline at the pipe yard by two trained installers in less than one day. The pipe was then shipped to the rig, run in the hole and successfully cemented at total depth without issue. This was the first run of the ARC for this major operator, who is now pursuing other applications.

Bal Seal Engineering Downhole tools are getting smarter. While this is great news for end users, it is creating a whole new set of challenges for the engineers tasked with designing them and making sure they consistently send critical information topside. For years, electronics have been incorporated into actuators, sensors and other downhole gear to help identify water, rock, sand, crude oil, natural gas and other materials in the formation, or to measure environmental conditions such as pore pressure, temperature and gamma radiation. However, as a result of miniaturisation and other advancements, more electronics are being packed into the tools to help operators determine optimal well placement and keep the wellbore within the most productive portion of the reservoir. These advances in functionality have forced tool designers to seek out new electrical connecting technologies that are more flexible, compact and ultra-reliable. In response, an increasing number of engineers have begun to leverage the three-in-one capabilities of the canted coil spring. When used as an electrical contact element, the canted coil spring efficiently conducts current between sensors

Drilformance With the ever increasing frequency of extended reach laterals, the demand for downhole vibration tools has steadily increased over the past decade. In many lateral sections – particularly extended reach drilling (ERD) – friction between the drill string components and formation can diminish weight transfer between the surface and the drill bit. In order to break this friction and reduce drag, vibration tools are commonly used. Some drawbacks exist for common vibration tools. Most vibration tools rely on elastomer material for their power sections, which limits the temperature rating. In addition, the intermittent hydraulic pulse derived from typical vibration tool’s valve assemblies can interfere with measurement while drilling (MWD), electromagnetic (EM), or logging while drilling (LWD) tool signals. What is more, common vibration tools often require a pressure drop which can reach as high as 600 psi. Lastly, most downhole vibration tools block the bore of the drill pipe, making wireline retrieving of any tools below impossible. Drilformance has developed Accelglide to solve these industry-wide issues. The tool has a thru bore which enables wireline retrieving of the MWD, and has been engineered with a 150 psi pressure drop, enabling higher flow rates

Enventure ESET® is a solid expandable liner that can be rotated and reciprocated, which increases the operating envelope of solid expandable tubulars. Advances in directional drilling technology have caused wellbores to become more tortuous, ultimately creating challenges that accumulate non-productive time (NPT) for operators. Ledges, highly deviated, long-reach, and equally challenging well geometries are challenges that can stop conventional expandable liner runs short of the target setting depth.

and other devices. It also mechanically latches or locks tool parts together with controllable force, and shields sensitive electronics against the potentially harmful effects of electromagnetic interference (EMI). Increasingly, canted coil springs are finding their way into downhole designs. The spring itself is especially well suited for use in oilfield connectors, many of which either thread or stab together, because each coil deflects independently to ensure reliable contact and prevent the formation of oxides. The spring lets designers precisely determine insertion and breakaway forces, and its construction enables it to maintain a nearly constant force over a wide compression range. The individual coils of the spring ensure electrical connectivity even in 360˚ rotation and under shock/vibration conditions. As an EMI shield, it eliminates noise that would otherwise corrupt data transmissions. With the increased use of electronics downhole, Bal Seal Engineering is seeing more designers adopt the spring as a fastening and conducting solution. The company sees it as an opportunity to simplify their designs without compromising performance. than other comparable vibration tools while still producing an effective mode of vibration. It can achieve this unique signal in part because it uses an all-metal, turbine power section energising an eccentric mass which generates a smooth, high-frequency vibration. The low pressure and high frequency signature derived from the Accelglide tool does not interfere with MWD, EM or LWD tool signals, and the tool can be placed directly above the bottomhole assembly (BHA). This near BHA placement transfers maximum energy to the drill bit while also mitigating severe lateral and axial vibrations that can harm MWD equipment. Due to the all-metal construction, the tool has a temperature rating of 400˚F. In a recent case study in the Permian Basin, an operator drilled two similar Wolfcamp wells, one with the Accelglide and one without. The operator utilised an otherwise identical BHA with the same motor configuration, drill bit, directional company, etc. The well that utilised the Accelglide equipped BHA experienced a much smoother toolface response, 32% increase in build rates, 40% increase in sliding ROP, and ultimately a 20% reduction in total curve hours. The operator commented that the ability to maintain accurate toolface during the slides was key to the overall improvement in the curve performance.

To address these challenges, Enventure has added an eccentric guide nose on the enhanced solid expandable liner to help guide the tool over ledges in the wellbore, minimising time and increasing the probability of the liner reaching the target setting depth. High-torque connections enable the rotation of the liner and minimise the risk of connection back-off or connection make-up down hole, either of which could lead to pressure losses while expanding the liner and ultimately the accumulation of NPT.

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DOWNHOLE TOOLS REVIEW The company modified the launcher, or expansion assembly housing, and inner string to handle the increased

Enventure ESET Enhanced Set System.

Frank’s International As well complexity and well depths increase, well conditions and structures continue to impose challenges on storm packer system design. Casing strings of 20 in. and 22 in. are extending to deeper depths and are an important and essential operation during well exploration and development. As it is common for these large casing strings to be installed in sediments above salt, there is a high remediation rate where some type of squeeze is required. This requires deployment of a remedial cementing assembly to the 20 – 22 in. casing section. Additionally, where there is a hole to be drilled, suspension tools are required to ensure the well remains contained below a retrievable type tool where the drilling/completion bottom hole assembly could be hung-off. The limited current solutions for this type of application use inflatable technology which is associated with increased rig time and risk to operations. Traditional 20 in. and 22 in. retrievable mechanical packer systems are challenged by well profile restrictions that limit their deployments due to the placement of subsea high-pressure wellhead housings,

Gyrodata The modern oilfield is demanding improvements to wellbore placement accuracy to mitigate the ongoing economic challenges of a lower-for-longer commodity price. After years of research and development, Gyrodata released the next evolution of solid-state gyroscopic technology, the OmegaX drop gyro surveying system, to address this challenge. The solid-state drop gyro system incorporates two independent three-axis sensor probes to measure the earth’s rotational rate, precisely and accurately determining inclination and true north to improve wellbore placement. An operator with wells offshore Malaysia suspected that their old wellbore surveys, taken when the project was initiated in the 1980s, were inaccurate, especially with regards to well placement. The wells were primarily

44 | Oilfield Technology September/October 2020

torque and reduced the number of internal connections while increasing the make-up torque of the internal connections. The ESET inner-string components have been tested to 40 000 ft-lb of torque. Typically, the system is tripped in the hole conventionally and only begins circulation and rotation to confront ledges, dips and other wellbore tortuosity issues. Unlike a standard non-rotational solid expandable liner where the progress can be halted when encountering a ledge or increased friction in tortuous extended wellbores, the system can then be rotated to help it across the ledge or out of the well cavity and continues toward targeted depth. Wellbore clean-up will be improved with the ability to rotate to help deliver a clean wellbore for expansion. Once at the bottom, rotation will help promoting a turbulent cement flow to help enhance the integrity of the cementing job and the shoe test.

wear sleeves, blowout preventer valves and other equipment prior to entering the wellbore. As a solution to this challenge, Frank’s has developed a 20 – 22 in. BRUTE® High-Expansion Packer System that provides a more efficient and reliable option for casing testing, suspension, and squeeze applications while meeting the challenges of these inner diameter restrictions. Also, to prevent tripping additional footage to catch a smaller casing size, the 20 – 22 in. packer can handle a large pressure and weight envelope, allowing operators to evacuate, return to work, and continue with operations as normal in the event of a temporary abandonment from 22 in. or smaller casing. Additionally, when covering multiple applications, system modularity is key to condensing the amount of equipment on board, removing cumbersome assembly lifts, and reducing the logistics between applications where multiple tools are required. The BRUTE system is designed to enhance operational efficiencies, allowing a wide variety of applications to be completed with a simple plug-and-play technique without the need for additional equipment.

high-angle wells with an inclination of greater than 70˚ and extended tangent sections that had a high potential for enhanced oil recovery (EOR). Since the wells were so old, the operator did not have information on the measurement while drilling (MWD) tool type used when they were originally drilled, resulting in a standard MWD error model being applied to the available data for wellbore placement. The operator needed a technology that could operate effectively in the challenging environment and deliver improved surveys to determine precise bottomhole location. As part of the campaign, the operator planned to resurvey five wells across two platforms. The wells required a system with improved battery life, as long logging runs required significant tool time downhole, and a system that would help the operator understand the true well location

to maximise the effectiveness of the EOR campaign. The operator chose the OmegaX system for the initial two wells on the first platform, with the high-accuracy surveys revealing discrepancies between the original data and the true wellbore location. Results from the wells showed the following: Well 1: there was a true vertical depth (TVD) difference of 2.11 m and a lateral difference of 6.78 m vs the original surveys. Well 2: there was a TVD difference of 4.93 m and a lateral difference of 10.66 m vs the original surveys.


where to place new wells to improve the recovery rate on the field. The final three wells, which will be resurveyed from the second platform, are expected to show similar results. The project highlights the need for continued vigilance when determining wellbore placement, as placement accuracy will be critical in determining each well’s recovery factor.


In addition to the updated wellbore position, the system provided a significant improvement in uncertainty reduction over historical data, allowing the operator to make better decisions on

OmegaX vs MWD.

Halliburton Halliburton Company introduced its new technology, DynaTracTM Real-Time Wireless Depth Correlation System, to reduce uncertainty and save rig-time by enabling operators to accurately position packers, perforating guns and the bottomhole assembly (BHA) without wireline intervention or moving the work string. The system operates as a real time downhole ruler, sensing gamma signature to take static measurements to determine the position of the bottom hole assembly (BHA) before and after setting the retrievable packer. Operators can measure depth within less than 1 ft at any time while tracking changes in position to improve operational efficiency. The company developed the system to provide operators with a more accurate position of their BHA depth in real time

Packers Plus Energy Services Inc. Packers Plus is an innovator of lower completion solutions for a variety of applications, including horizontal, multilateral, HPHT and offshore wells, and partners with operators to overcome challenging applications in oilfields around the world. The latest company solution is providing operators with higher efficiency plug-and-perf systems. The company’s diversified portfolio of lower completion solutions includes the line of Lightning frac plugs, which consists of both composite and degradable plugs to improve deployment and reduce/eliminate millout operations, saving time and reducing risk. The suite of frac plugs includes the Lightning Frac Plug, LightningPLUS Composite Plug and

while also improving safety and efficiency of operations. The technology reduces downhole uncertainty and improves reservoir insight while saving valuable rig-time. Traditional methods of depth correlation require either wireline or work string manipulation and provide depth only at a single moment in time. The DynaTrac system is run with the BHA to provide continuous position throughout operations. Through on-demand measurement of tool position, the technology reduces health, safety and environmental risks associated with performing wireline operations and work string movements. By determining position of the BHA with a simple button click in software, the system also reduces the number of personnel required at the wellsite. Additionally, operators can configure the system to perform automatic position measurements to track BHA movement over time, which increases the accuracy and reliability of reservoir analysis.

LightningBOLT Dissolvable Plug. Each plug is paired with a ball to provide zonal isolation and, with over 3000 installed, operators are seeing faster millout operations from a shorter plug design and composite slips. One of the early deployments on a well in Texas, US, proved the millout efficiency of the plugs, as 18 plugs were milled out with an average time of 12.67 mins. – and favourably sized cuttings were seen on the surface. Another operator, working in Alberta’s Duvernay formation, tested the millout capabilities of several frac plugs in a real-world setting – including the LightningPLUS Composite Plug. The operator deployed two plugs as part of the two-well test and both plugs were successfully milled out in just 5 minutes, producing fine and easily manageable debris.

September/October 2020 Oilfield Technology | 45

DOWNHOLE TOOLS REVIEW Packers Plus has a long history of collaborating with operators to solve challenging completion problems. The company recently worked with an operator to overcome frac plug installation issues due to deformed casing by designing a reduced outer diameter (OD) that could be pumped passed trouble areas in the casing and still withstand the differential pressure required during stimulation operations. The uniquely shaped pump down fin of the composite plug also enables faster run-in-hole speeds, which results in less fluid pumped compared to other plugs.

Four of the redesigned composite plugs were pumped to the planned depth, set successfully and held pressure throughout the stimulation program, which included wellbore pressure up to 56 MPa (8122 psi) without any slippage of the frac plugs. After stimulating the wells, the operator milled out each plug within 6 – 10 mins. The two-well comparison of the reduced OD frac plugs led to the operator ordering additional composite plugs to continue their stimulation programme.

READ Cased Hole

are deployable on electric wireline, slickline or coiled tubing, in both memory and surface read out modes. The company’s dedicated well integrity platform includes multifinger calipers, magnetic thickness tools, cement evaluation and leak detection technologies. Across its entire well integrity portfolio, the company delivers impartial, expert data analysis and interpretation through READ ANSA.

READ Cased Hole is a provider of independent cased hole logging services, and for 30 years the company has been delivering innovative solutions that help operators overcome well challenges all over the world. Well integrity is a fundamental aspect of the safe and profitable operation of any oil and gas project. It requires a thorough understanding of a well’s barrier performance and the structural integrity of the tubing, casing, liners and cement. READ has an extensive portfolio of specialist downhole well integrity tools that can accurately identify and quantify damage and deformation, and

High-resolution data acquired by the ABI-43 ultrasonic downhole technology showing casing thickness and acoustic internal tubing diameter measurements.

Rubicon The utilisation of reamers and stabilisers in the drill string has been an accepted operational practice for over 40 years, with the first roller reamers being deployed to simply maintain or enlarge the diameter of the borehole; or serve as a stabiliser above the bit to stabilise the drill string against deviating tendencies encountered during drilling. A wellbore with ledges, doglegs, poor cutting transportation, erratic drilling torque, stick slip, key seating, reactive and over-pressured formations are common drilling challenges that limit overall performance and lead to increased non-productive time (NPT), affecting the delivery of the well and increasing cost per foot.

46 | Oilfield Technology September/October 2020

2019 saw the company introduce the ABI-43 acoustic borehole imaging technology to its well integrity offering, a cutting-edge ultrasonic scanning solution for borehole casing and cement evaluation. ABI-43 is a compact ultrasonic evaluation tool, enabling easy through tubing deployment in all well deviations, including horizontal. The tool employs ultrasonic pulses generated from within the 1 11/16 in. (43 mm) dia. tool body, directed by a rotating mirror meaning no moving parts are exposed to the well environment. In early 2020, READ’s successful deployment of the ABI-43 on electric wireline provided valuable insight into the casing integrity of an onshore test well for an operator in Europe. Its ANSA data analytics team carried out a fast and high-precision assessment of the data acquired in real time from the 7 in. casing, to provide accurate measurements of the casing thickness, as well as the tubing inner and outer diameters. This ultrasonic inspection solution gave the operator the answers it needed to proceed with its desired operations for the test well confidently and in a timely manner.

The Roller GunDRILL Reamer (RGDR) is a drilling enhancement tool that combines the passive PDC cutting capabilities of a versatile drilling reamer with the advantages of a Roller Reamer in one tool. With its PDC cutters and gauge-reaming roller cutters, the tool prevents costly stuck pipe situations and enhances hole quality, improving rate of penetration and reducing NPT, while minimising torque and smoothing related fluctuations. The RGDR was recently utilised with an operator in the Middle East in a dual run to overcome stuck pipe and excessive back reaming in a 12 ¼ in. hole with a high surface RPM in a plastic formation. Back reaming was eliminated with no caving or stuck pipe and an 80% improvement in tripping time.

A recent addition to the drilling enhancement family is the 6 1/8 in. Eccentric GunDRILL Reamer (EGDR), which was fitted with an engineered PDC cutting structure for hole enlargement and tungsten carbide inserts on the blades to further condition the borehole and deliver a smoother borehole profile. The tool successfully deployed to ream and back ream through the selected DLS intervals and the

4 ½ in. lower completion reached target depth without issue. The operator in the Middle East was able to pull the reaming bottomhole assembly on an elevator to the 7 in. liner shoe with no recorded overpull issues and run in hole freely back to target depth, confirming that the open hole was in excellent condition due to the enhanced reaming capabilities of the EGDR.


SwellFrac’s proprietary water swellable particles use a combination of super absorbent polymers and osmotic swell mechanisms to optimise speed and strength of the swelling process and maximum chemical resistance. As the sealing material inside the perforation tunnel is chemically resistant, the risk of erosion and/or dissolution during the re-fracturing process is minimised. The internal diameter of the existing completion is fully maintained allowing standard plug sizes to be used and multiple re-fracturing operations to take place as subsequent production decline is experienced with time. From simple to complex well designs, the global specialist in advanced completions and production solutions delivers enhanced productivity for clients’ reservoirs both offshore and onshore. In the current economic environment, efficiency is more important than ever. The company is dedicated to investment in R&D, bringing disruptive technologies to market and offering solutions targeted to operators’ specific production challenges. This will ensure the sector can safely reduce costs and remain competitive, valourise existing assets, and achieve environmental compliance and climate change goals.

Tendeka has an expansive history in providing in-house developed swelling elastomer technology to the industry in the form of zonal isolation packers and has developed extensive elastomer expertise along the way. The company has built upon this expertise to generate an operationally simplistic, chemically stable, cost-effective solution to enable re-fracturing. Conventional methodology typically involves running a liner and cementing to isolate existing perforations, which can result in complex procedures and a significantly reduced internal diameter. The SwellFrac solution uses swelling elastomer technology to simply and economically isolate existing fractures in oil and gas wells whilst maintaining full internal diameter allowing the well to be re-fractured. Sized swellable elastomer particles are pumped in aqueous slurry from surface into the existing perforation tunnels. This immediately creates sufficient pressure differential to cause diversion ensuring that all existing perforations are isolated. In-situ swelling then creates an effective high-pressure seal to enable re-fracturing operations to take place in the wellbore.

TGT Wells are built to convey valuable fluids between downhole reservoirs and surface facilities safely, cleanly and productively. They need to withstand the rigors of downhole conditions for many years, often decades, and operate 24/7 without compromise. Unfortunately, according to the ISO well integrity standard 16530-2:2013, every well has 26 potential weak points, each of which can undermine integrity and performance. Not surprisingly, one or more failures are likely during the wells’ life, and these need to be diagnosed accurately and completely so that the impact can be fully understood, and the correct action taken. Operators traditionally turn to ‘downhole tools’ or ‘logging’ to carry out well diagnostics, but diagnosing wells correctly often requires a more powerful approach. This is because the vast majority of the ISO’s 26 failure points exist outside of the wellbore, behind one or more steel and cement barriers. Locating failures behind barriers requires a special breed of diagnostics. To overcome this challenge, TGT has developed two ‘diagnostics systems’ – the True Flow System and the True Integrity System – to diagnose well performance issues anywhere in the well system. These two systems

and the answer products derived from them are referred to collectively as ‘through-barrier diagnostics’. The two diagnostic systems share a select combination of five technology ‘platforms’: Chorus, Cascade, Pulse, Indigo and Maxim. Each platform has a particular role, and they work together to provide a more complete understanding of well dynamics and failures. For example, Chorus utilises high-fidelity acoustic sensing to locate flow, and Cascade converts temperature changes into flow rates. Pulse uses electromagnetic energy to examine the condition of well tubulars, and Indigo provides a host of multisense measurements that complete the well dynamics picture. Maxim is the all-important ‘digital workspace’ that provides analysts with the functionality and tools to develop diagnostic programmes, process data, perform data modelling to create new insights and carry out the analysis and interpretation that is ultimately packaged in the final diagnostic answer. This approach to diagnostics goes beyond the capabilities of traditional downhole tools and logging to deliver a more complete understanding of well dynamics and failures, so the correct action can be taken. Ultimately, this approach enables better well management decisions to deliver safe, clean and productive well operations.

September/October 2020 Oilfield Technology | 47

DOWNHOLE TOOLS REVIEW Upwing Energy In unconventional gas wells, liquid loading can significantly reduce production and lead to premature abandonment. Upwing Energy has developed a high-speed Subsurface Compressor SystemTM (SCS) on magnetic technologies that maximises gas and condensate production, recoverable reserves, gas-in-place recovery efficiency and liquid unloading at the same time. Upwing deployed its first commercial SCS in an unconventional shale well in Indiana during 4Q19. The trial results demonstrated that the SCS increased gas production by 62% and liquid production by 50% over the steady-state performance with the rod pump prior to the SCS installation. The well had a vertical wellbore of 2000 ft and a horizontal wellbore of 5000 ft, where liquid had accumulated. To provide sufficient velocity to carry liquids, the compressor was installed at the bottom of the vertical section with a tail pipe extending approximately 1000 ft into the horizontal section. The well’s gas production was approximately 185 000 ft3/d prior to installing the SCS, and its liquid

production via rod pump was 5 – 7 bpd. The well choked in a few hours without the rod pump. With the SCS, the well stabilised at a production rate of 300 000 ft3/d (+62%) with the help of nitrogen injection to kick off the well. At 30 000 rpm, the liquid production increased to over 9 bpd (+50%), which can be attributed to the gas velocity increasing to 29 ft/sec. Following the successful unconventional field trial, Upwing is scaling up the SCS for higher flowing wells and is building and testing a more powerful version in preparation for a trial later this year. With higher pressure ratio and mass flow capabilities, the new SCS tool will offer a more environmentally friendly way for E&Ps to increase gas production from their existing assets vs undertaking additional drilling and fracking. Some other features of the new SCS tool include: Design point pressure ratio of up to 2:1 at 50 000 RPM. Ability to perform up to 12 000 ft below the ground. Ability to handle over 2 million ft3/d with over 150 bbl/1000 ft3 of liquids. Ability to address over 60% of conventional gas wells globally.


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