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March 2019 Conntentstents Volume 12 Issue 03

03 Comment 27 Collaborative completions Dale Logan, C&J Energy Services and Panos Adamopoulos, Seismos, USA, examine a combination of new technologies designed to optimise horizontal completions. 05 World news 30 Developing a digital future Manoj Nimbalkar, Weatherford International, USA, discusses recent advances 10 Weighing the odds in digital and cloud-based technology designed to drive oilfield productivity. Oilfield Technology Correspondent, Gordon Cope, reviews the state of the upstream industry in the Middle East and Northern Africa. 33 Thinking outside the box Andrew Poerschke, Teddy Mohle and Paul Ryza, Apergy, discuss a new 13 Leveraging legacy data approach to implementing artificial gas lift designed to improve production Jo Firth and Priyabrata Pradhan, CGG, UK, explore the value in in declining wells. reprocessing legacy seismic data sets. 37 Keeping things crystal clear 18 A critical component Simon Larson, Siemens, Sheng Kun Sun, CNPC, and Xiao Ming Sun, Tom Hewitt, Jordan Lewis, and Stephen Forrester, NOV, examine the use Liaohe Petro Engineering Company, review water treatment measures of custom solutions to the challenges of North American coiled tubing. designed to comply with China’s tough new treatment standards.

23 Enhancing tubing technology 41 Well Control Q&A Irma Galvan, Global Tubing, USA, explores how the rise of ‘super lateral’ Oilfield Technology invited experts from Cudd Well Control, Halliburton, wells is driving the optimisation of coiled tubing interventions. RESMAN and Wild Well Control to share their knowledge on a variety of well control topics.

Front cover Abaco Drilling Technologies is 46 An integrated approach EXPLORATION | DRILLING | PRODUCTION MARCH 2019 a leading technology-driven Michael MacMillan, C-Innovation, USA, discusses the benefits that a manufacturer of power sections single-source ROV and vessel support services solution can deliver for subsea for oil and gas drilling and construction projects. thru-tubing operations.

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ISSN 1757-2134

Copyright © Palladian Publications Ltd 2019. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted Oilfi eld Technology is audited by the Audit Bureau of Circulations (ABC). An audit certifi cate is in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. available on request from our sales department. 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. +1.713.849.2769 | cuddwellcontrol.com CRITICAL WELL INTERVENTION SERVICES When faced with a critical well event, you need to rely on the experienced well control leaders to resolve your situation quickly and safely. Cudd Well Control promptly responds to assess the situation and develop a plan of action to return your operations to production.

• Well Firefighting/Blowout • Surface and Subsea Well Control • Gate Valve Drilling Operations • Well Recovery Operations • Freeze Operations • Well Control Engineering • Hot Tap Operations Comment March 2019 ContactContact uuss David Bizley, Editor david.bizley@oilfi eldtechnology.com Editorial Managing Editor: James Little [email protected] fter a gloomy start to 2019 and the January slump that saw Editor: David Bizley oil prices fall to the low-US$50s, Brent crude is back on the [email protected] rise again – at least for now. Editorial Assistant: Aimee Knight A [email protected] The return of Brent crude to the mid-US$60s range has largely been driven by OPEC’s continued output cuts. OPEC and Design its allies have actually over-delivered on the cuts with a further Production: Hayley Hamilton-Stewart 300 000 bpd decline. According to a Reuters survey, the 11 OPEC members bound by the [email protected] deal managed to achieve 101% compliance with the agreed-upon cuts, up from 70% in Sales January. Saudi Arabia alone produced 130 000 bpd less than in January, whilst Kuwait, Advertisement Director: Rod Hardy 1 the UAE and Iraq also all made significant cuts. [email protected] Adding an interesting geopolitical twist to the proceedings is the fact that these Advertisement Manager: Ben Macleod increased cuts have occurred despite US President Donald Trump urging OPEC and its [email protected] allies to produce more and reduce efforts to raise prices. When questioned by Reuters, Website sources at OPEC simply said: “We are sticking to the plan.”2 Website Manager: Tom Fullerton Involuntary cuts also played a part in the production decline. Venezuela’s already [email protected] ailing output was hit by newly imposed US sanctions on PDVSA. Once a leading global Digital Editorial Assistant: Nicholas Woodroof supplier, and despite being blessed with vast natural reserves, Venezuela’s output has [email protected] fallen significantly as a result of years of mismanagement. Iran also continues to be the subject of US sanctions, which have seen its output fall. Some estimates show that the Marketing sanctions on these two countries have taken as much as 2 million bpd of supply off the Subscriptions: Laura White [email protected] global market. Reprints: Analysts are treating the news of tightening supply with some optimism – a [email protected] note released by Barclays was quick to point out that: “OPEC exports are off by over 1.5 million bpd since November”, and a spokesperson for Fitch Solutions was quoted as saying that they expected Brent crude to average US$73/bbl this year.3 Palladian Publications Ltd, 15 South Street, Farnham, Surrey GU9 7QU, UK Another factor driving up prices is the news that the US and China could be close to Tel: +44 (0) 1252 718 999 Fax: +44 (0) 1252 718 992 signing a trade deal that would end the ongoing tariff row between the two economic Website: www.oilfieldtechnology.com giants. The disagreement, which had seen heavy tariffs placed on hundreds of goods including solar panels, washing machines, aluminium, airplanes, cars, pork, and soybeans, had been acting as something of a wet blanket on the global economy. The news that this dispute could soon be over has boosted hopes that economic activity will increase and drive further oil demand. Given the current rate of progress, a formal trade deal could be agreed upon by President Trump and President Xi by the end of March.4 All things considered, the signs are looking fairly positive for the upstream sector – challenges still remain, but the silver linings currently outnumber the clouds. As we head into spring, here’s hoping that the signs of new life continue to grow and eventually bloom. SSubscriptionubscription

Oilfield Technology subscription rates: Annual subscription References £80 UK including postage/£95 overseas (postage airmail). Two 1. ‘In rebuff to Trump, OPEC oil output drops further in February’ – https://uk.reuters.com/article/ year discounted rate £128 UK including postage/£152 overseas (postage airmail). uk-oil-opec-survey/opec-oil-output-drops-further-in-february-as-saudi-over-delivers-on-cuts- Subscription claims: Claims for non receipt of issues must be idUKKCN1QI4GT?rpc=401& made within three months of publication of the issue or they will 2. Ibid. not be honoured without charge. Applicable only to USA & Canada: OILFIELD TECHNOLOGY 3. ‘Oil climbs on US-China trade deal hopes, OPEC’s deepening supply cuts’ – https://www.cnbc. (ISSN No: 1757-2134, USPS No: 025-171) is published monthly com/2019/03/04/oil-markets-us-china-trade-opec-in-focus.html by Palladian Publications, GBR and is distributed in the USA 4. Ibid. by Asendia USA, 17B S Middlesex Ave, Monroe NJ 08831. Periodicals postage paid New Brunswick, NJ and additional mailing off ices. Postmaster: Send address changes to Oilfield Technology, 701C Ashland Ave, Folcroft PA 19032.

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Visit www.downholeproducts.com to fi nd out more World news March 2019 Tendeka secures multi-million-pound AICD contract to boost oil recovery in Middle East IInn bbriefrief Independent global completions service company Tendeka has secured a further multi-million-pound contract with a major national oil company in the Middle East. The agreement will see Tendeka provide reservoir modelling and the installation of its Senegal FloSure Autonomous Inflow Control Devices (AICDs) to boost production and improve reservoir MODEC, Inc. has announced that its performance in several mature fields. The company will perform reservoir simulations for subsidiary, MODEC International Inc., each well, working closely with the client to ensure optimum reservoir performance, with the has been awarded a contract by technology helping in the reduction of unwanted fluid production. Woodside Energy (Senegal) B.V., as Having carried out several similar projects in the region, the company has significant Operator of the SNE Field Development, experience of the challenges of brownfields and carbonate reservoir that form a large proportion for a floating production storage and of oilfields in the Middle East. offloading (FPSO) vessel for Senegalese Scott Watters, Chief Operating Officer at Tendeka, said: “This is a major contract for the waters. business and one that continues a long and well-established relationship with the client. We’re Under the contract, MODEC will renowned for our FloSure technology with a strong track record in supporting clients and driving perform Front-End Engineering Design efficiencies. (FEED) for the FPSO and, subject to a “Our FloSure technology and global supply chain capability has allowed us to bring real final investment decision on the project value to major Middle East projects. We are committed to the continuous development of this in 2019, will be responsible for the technology to tackle future challenges and smooth field development planning for the long term. supply, charter and operations of the It’s an area we aim to grow over the coming months and years.” FPSO. The SNE deepwater oilfield is expected to be Senegal’s first offshore Shearwater GeoServices Block Energy to acquire 100% oil development. The field is located awarded 4D contracts interest in West Rustavi field within the Sangomar Deep Offshore permit area, approximately 100 km Shearwater GeoServices Holding AS has Block Energy Plc, the exploration and production south of Dakar, Senegal. announced the award of three 4D seismic company focused on the Republic of Georgia, surveys by Equinor AS to be conducted this has announced that it has secured an agreement summer. The projects confirm Shearwater’s with Georgian Oil and Gas Limited to increase its Algeria Isometrix crews will be active in 2019, on 4D working interest in the West Rustavi licence to Neptune Energy and Sonatrach projects in the North Sea and Barents Sea. 100% from the current 25%. have announced that first gas Equinor has awarded Shearwater a Block’s interest in the Licence is held via its has gone in to the Touat project multi-project contract, with three surveys 100% owned subsidiary Georgia New Ventures, in Algeria as part of project to be conducted in 2019 at the Kvitebjørn Inc which is also party to the Agreement. The commissioning. The development, & Valemon, Visund and Snøhvit fields. Agreement replaces the original earn-in deal, which will produce around 75 000 boe/d The first survey is scheduled to start in which provided that Block would increase its (450 million standard ft3/d) at plateau, Q2 and the total duration for the three WI to 75% upon completion of the Company’s remains on track to commence gas 2019 projects is estimated at around 3 ongoing West Rustavi workover and sidetracking export production by the end of the months. The surveys will be conducted programme. first half of 2019. by Shearwater’s Amazon Conqueror and On completion of the transaction Block Touat comprises eight gas fields SW Amundsen. will take full strategic control of future and a gas processing plant and is “We see a clear increase in activity in operations in the field, which holds an located in the Basin of Sbaa, 1500 km the 4D market in 2019, and we are very estimated 38 million bbls of gross contingent southwest of Algiers, near Adrar. pleased to see a leading purchaser of 4D resources (‘2C’) of oil (source: CPR completed Jim House, Neptune CEO, seismic choosing Shearwater’s Isometrix by Gustavson Associates, 1 January 2018), and a said: “First gas in at Touat marks technology for their 4D surveys. Shearwater legacy gas discovery. a significant milestone for this has decades of innovation and crew According to the well passport the company important project. We are now focused experience in 4D and it is important to received on acquiring its interest in the 36.5 km2 on delivering commercial full export see this capability selected by established Licence, one of West Rustavi’s discovery production by the end of the first half clients,” said Irene Waage Basili, CEO of wells flowed at rates up to 29 000 m3/d when of the year.” Shearwater GeoServices. originally tested in 1988.

March 2019 Oilfield Technology | 5 World news March 2019

Diary dates

18 - 21 March, 2019 Aker Solutions to develop Lundin Petroleum MEOS 2019 digital twin for Nova field completes exploration well Manama, Bahrain E: [email protected] Aker Solutions has been appointed by Lundin Petroleum AB (Lundin Petroleum) www.meos19.com Wintershall AS to build a complete digital has announced that its wholly replica of the Nova production system to owned subsidiary Lundin Norway AS 27 - 29 March, 2019 enable data driven engineering, production and (Lundin Norway) has completed the maintenance decisions. drilling of exploration well 7121/1-2 S, OMC 2019 Through two separate agreements, targeting the Pointer and Setter prospects Ravenna, Italy Aker Solutions will provide both a fully in PL767 in the southern Barents Sea. E: [email protected] interactive digital replica of the integrated Oil shows were encountered at various www.omc2019.com production system as well as undertake a study intervals in the Pointer prospect but the to enable live data streaming and condition well is classified as dry. 06 - 09 May, 2019 monitoring of the subsea equipment. The main objective of the well, located OTC The digital twin will become an advanced 20 km north of the Snøhvit gas field, was Houston, USA replacement to traditional paper-based to test the two distinct lower Cretaceous E: [email protected] handbooks and equipment documentation, sandstone targets, the shallower Setter www.2019.otcnet.org ensuring that all relevant engineering data prospect and the deeper Pointer prospect. is held centrally in a single, interactive Water wet sands with a total 19 - 22 May, 2019 and searchable solution. It will be built thickness of 40 m with moderate reservoir AAPG ACE on a cloud-based architecture capable of properties were encountered in the San Antonio, USA processing live data and ensuring that vital Setter prospect. In the Pointer prospect, E: [email protected] engineering information is kept up to date at about 130 m of sand with oil shows www.ace.aapg.org/2019 all times. was found, however the reservoir was The connected study to enable live evaluated to be tight and of low quality 22 - 24 July, 2019 data streaming from the subsea production across the entire interval. The well was equipment will be instrumental in driving not formation-tested, but extensive URTeC 2019 forward real time subsea condition monitoring, data acquisition and sampling have Denver, USA production optimisation and predictive been carried out. The well has been E: [email protected] maintenance for the field. permanently plugged and abandoned. www.urtec.org WWebeb nnewsews KCA Deutag awarded US$110 million of land drilling contracts hhighlightsighlights in the Middle East, Russia and Africa KCA Deutag has announced that its land drilling operation has won new contracts and Ì Andalas Energy & Power announce contract extensions worth approximately US$110 million. Colter well update In the Middle East, KCAD has been successful in winning a total of 7 years of contract Ì EnerQuip sets sail on Vantage drillship extensions for five heavy rigs operating in Oman. The extension for each rig ranges from project one to two years. In addition to this, the company has also signed a contract with a new client in Oman for one of its 2000hp rigs. N-Sea announces multi-million pound Ì In Russia, the company has been awarded a contract for a 1000 hp rig with one of North Sea contract wins the country’s leading integrated oil companies. KCAD is also the drilling contractor on Ì Weatherford completes sale of Algeria three platforms offshore Sakhalin Island. land drilling rigs In Nigeria one of the company’s 700 hp rigs has won a one year contract to carry out a workover programme, with a further one year extension option. Additionally a second rig has won a short term contract for a three month programme. To read more about these articles This 1500 hp rig will be operating in an area of Nigeria where KCA sees increasing and for more event listings go to: activity. This is the rig’s second contract in quick succession in this location and there are many other active opportunities that are currently being pursued. www.oilfieldtechnology.com KCAD has also had some success in Algeria, where it was awarded a short term contract extension for one of its 1500 hp Speed rigs.

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Wood awarded EPCI contract by Equinor in Norway McDermott awarded EPCI contract from Saudi Aramco Wood has secured a new US$13 million contract with Equinor to deliver engineering, procurement, construction, and installation (EPCI) services to the Vigdis boosting station McDermott International, Inc. has announced increased oil recovery (IOR) project. a large contract award from Saudi Aramco for Effective immediately, Wood will provide topside modifications to enable the tie-in engineering, procurement, construction and of subsea equipment to offshore platforms Snorre A and Snorre B, which process oil from installation (EPCI) services in the Marjan field, the Vigdis subsea field, located in the Norwegian North Sea. offshore Saudi Arabia. The contract is delivered from Wood’s office in Sandefjord, Norway, and follows The contract includes the full suite of the company’s successful completion of the front-end engineering design (FEED) and EPCI services for the upgrade of two existing concept study for the asset. Wood also currently provides maintenance, modification platforms related to the installation of associated and operations (MMO) services on Snorre A and B under a framework agreement with equipment for electrical submersible pumps Equinor. (ESPs) and space for a future high integrity Dave Stewart, CEO of Wood’s Asset Solutions business in Europe, Africa, Asia & pressure protection system (HIPPS), subsea Australia, comments: “Wood has a longstanding relationship with Equinor and this composite cable lay and topside cable tie-ins. contract award further demonstrates their confidence in our offshore modifications “This award is testament to Saudi Aramco’s capabilities. This new contract also supports our strategic focus on solidifying our confidence in McDermott’s ability to execute position as a modifications service provider in Norway.” this complex type of project,” said Linh Austin, Lars Fredrik Bakke, Wood’s senior vice president in Norway adds: “Wood has decades McDermott’s Senior Vice President, Middle East of experience in the Norwegian energy sector. This experience, combined with our local and North Africa. “We have a long track record of engineering team’s customer specific knowledge of Equinor’s processes and systems, executing similar scopes of work and believe that positions us ideally to safely and successfully deliver this contract.” by working closely with our clients we can offer On completion of the project, production from the Vigdis field will be increased by industry leading solutions which are suited to this almost 11 million bbls. evolving market segment.”

Santos boosts operated position across off shore RockRose Energy plc to Northern Australia acquire Marathon Oil UK

Santos has announced that it has reached an agreement to align the company’s RockRose has announced that it has signed a share interests, under Santos operatorship, across four exploration permits in the purchase agreement (‘SPA’) to acquire 100% of Bonaparte Basin offshore Northern Australia adjacent to a large existing contingent Marathon Oil U.K. LLC and 100% of Marathon Oil West resource. of Shetland Limited from subsidiaries of Marathon Santos’ position in the Bonaparte Basin already includes an 11.5% interest in Oil Corporation. The consideration payable by the Bayu-Undan gas-condensate field and the Darwin LNG plant, as well as a 25% RockRose to Marathon Oil in connection with interest in the Barossa field, which is currently in front end engineering and design the Acquisition is circa US$140 million (subject to and is the leading candidate to backfill Darwin LNG. customary adjustments), which RockRose currently The transaction with Beach Energy will see the companies become 50/50 joint anticipates will be funded through existing resources venture partners across NT/P82, NT/P85, NT/P84 and WA-454-P. Santos will operate and facilities. all four permits. MOUK holds 37 - 40% operated interests in fields Permits NT/P82 and NT/P85 are located immediately to the south of the Barossa in the Greater Brae Area and MOWOS holds a 28% project area, where Santos acquired the 4347 km2 Bethany 3D seismic survey in interest in the BP plc operated Foinaven Field unit 2018. NT/P84 and WA-454-P are proximal to the Petrel/Tern/Frigate field complex in and a 47% interest in Foinaven East, respectively. the Petrel sub-basin, where separate agreements with Neptune Energy see Santos RockRose Executive Chairman, Andrew Austin move to 100% operated interest in the Tern and Frigate fields and a 40.25% interest said: “This acquisition marks a major step change in in the Petrel field, subject to customary approvals. the Group’s reserves and production profile. Given Santos Managing Director and Chief Executive Officer Mr Kevin Gallagher said: the quality of these assets the Board’s view is this is “This alignment of equity and operatorship will allow for a more strategic approach a good opportunity to make the transition to the role to the next phase of exploration in the region.” of operator. “The next step for these permits is to evaluate new and existing seismic data to We look forward to welcoming Marathon Oil UK build inventory and define potential targets for drilling within the next few years. employees, who have an excellent track record Permits NT/P82 and NT/P85, which are located immediately south of our Barossa operating in the North Sea, to the RockRose team at project, will be a key focus for this work,” Mr Gallagher said. closing.”

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5HYHDOLQJSRVVLELOLWLHV shearwatergeo.com WEIGHING THE ODDS Oilfield Technology Correspondent, Gordon Cope, reviews the state of the upstream industry in the Middle East and Northern Africa.

10 | he countries of the Middle East and Northern Africa (MENA) 280 trillion ft 3. There are no off icial estimates for the size of its have an incredible profusion of hydrocarbons – and an unconventional resources, although Aramco off icials have noted that T unenviable track record of war, misfortune and catastrophe. they are ‘huge’. The global oil and gas sector is also facing wrenching Saudi Aramco began developing unconventional gas in transformations to which the MENA region is by no means immune. the North Arabia field in early 2018, ramping up production to The growth in North American production, the political travails of key 190 million ft 3/d to meet the needs of Wa’ad Al Shamal, a mining and OPEC members and the comprehensive US sanctions against Iran all industrial city in northern Saudi Arabia. threaten traditional markets. Saudi Aramco now has 16 unconventional rigs which completed Many MENA countries have the intelligence and foresight to take over 70 wells around the country in 2018. The programme is part of the initiative and prepare for the future. Others are mired in social, the kingdom’s plan to spend US$150 billion to increase domestic cultural and mismanagement complications that threaten their gas production from 14 billion ft 3/d to 23 billion ft 3/d within the next prospects. The stakes are high: who will win the race? This article decade. The increase is to meet growing domestic demand from considers the winners, placers, also-rans and long-shots. consumers and industry, as well as off set exportable liquids that are currently consumed by utilities. Winners The smart punters are backing Abu Dhabi. In late 2018, The smart money is on Qatar, which has almost 800 trillion ft 3 of gas Abu Dhabi’s Supreme Petroleum Council green-lighted the spending reserves and is the world’s largest producer of LNG. According to the of US$132 billion over the next five years to expand oil and gas. International Gas Union, Qatar exported 81 million t of LNG in 2017, State-owned ADNOC announced that one of its first goals will over one quarter of global trade. be to boost crude production to 4 million bpd by 2020. A major Qatar announced that it will boost capacity by approximately component is the upgrading and expansion of its giant Bu Hasa 30% over the next five to seven years. The decision is predicated, in production complex. The onshore field will increase output from part, by the tremendous increase in Chinese LNG demand as it tries 550 000 bpd to 650 000 bpd through a combination of new pipelines to ween domestic industry and utilities off coal. In September 2018, and production hubs, as well as a second gas-lift recovery phase. Qatargas announced that it had signed a new, 22 year contract with ADNOC also announced plans to grant Italy’s Eni a 40-year China to supply 3.4 million tpy. concession in its off shore Ghasha concession ultra-sour gas fields. On the diplomatic front, Qatar has been at loggerheads with The concession is for a 25% stake in the project. ADNOC estimates Saudi Arabia and neighbouring countries over its support of the that the area holds several trillion ft 3 of recoverable gas, with the Muslim Brotherhood and the Al-Jazeera TV network. In December, potential to produce up to 1.5 billion ft 3/d. 2018, Qatar announced that it would withdraw its membership from Finally, the US Geological Survey (USGS) estimates that OPEC, starting on January 1, 2019. Government off icials stated that Silurian, Jurassic and Cretaceous source rocks beneath the the country would focus on its long-term LNG growth strategy. United Arab Emirates hold over 200 trillion ft 3 of technically Saudi Arabia is also a front runner, with 261 billion bbls in recoverable natural gas and 22 billion bbls of technically recoverable proven reserves and 10.5 million bpd of production (and exports of crude. ADNOC will target 1 billion ft 3/d of unconventional gas 7.6 million bpd). While Saudi Arabia suff ers from severe geopolitical production by 2030. The state-owned company recently contracted complications, its oil and gas sector has outlined a promising Total to explore the onshore Ruwais Diyab unconventional gas future by diversifying the economy away from oil exports. In early concession, which is considered to have similar potential to some December 2018, Saudi Aramco announced that it would spend more of the premier North American shale gas plays. The deal calls for up than US$100 billion over the next decade in petrochemicals in order to seven years of exploration and appraisal, followed by a 40 year to balance its upstream and downstream holdings. The eventual production phase. goal is to have 8 - 10 million bpd of integrated chemical, refining and Off shore exploration in Egypt’s Mediterranean waters is finally marketing capacity. The chemical portion, especially, is expected to paying off for the African nation. Within the last 12 months, gas grow from one-third to nearly half. Much of the chemical component has begun to flow from several major gas fields, including the is planned for high growth countries such as China and India. 30 trillion ft 3 Zorh field. As of September 2018, Egypt halted imports Lost in all the news is the country’s move toward unconventional of expensive LNG, which cost it over US$2.6 billion annually. It is now resources. The World Energy Council estimated that Saudi Arabia’s seeking out deals with neighbouring countries. It has contracted with recoverable conventional gas reserves stood at approximately Cyprus to build a pipeline to ship Cypriot gas to its LNG facility in

| 11 order to process the gas and re-export it to Europe. Earlier in the year, of technically recoverable reserves). State-owned Sonatrach has Egypt signed an agreement with Israel to import gas from the latter’s drilled a handful of exploration wells, mostly in Sahara basins. It is off shore gas fields. currently in discussions with Total and Eni regarding development Oman is having a strong run. The Middle East country of unconventionals. However, protests in the water-scarce regions has 5 billion bbls of proven reserves and produces almost have hampered evaluation efforts. 1 million bpd, of which 80% is exported as crude. For over a decade, Israel, which has extensive off shore recoverable gas reserves, BP and Oman Oil Company have been appraising the giant Khazzan including Tamar (10.5 trillion ft 3), and Leviathan (19 trillion ft 3), is gas field, which holds approximately 100 trillion ft 3 of gas in tight fast approaching from the rear. An Israeli-US consortium recently reservoirs. Using advanced drilling technology, the JV began concluded a deal to purchase a disused pipeline from Ashkelon to production in 2017, and now produces 1 billion ft 3/d and 35 000 bpd the northern Sinai Peninsula, bypassing a land pipeline that has been of condensate. Recently, it was announced that the Ghazeer portion targeted by jihadists. The US$15 billion deal would see approximately of the project will commence development. It is expected to add an 64 billion m3 of Israeli gas shipped to Egypt over 10 years. additional 500 million ft 3/d and 15 000 bpd of condensate. Kuwait, which has proven reserves of 104 billion bbls, is always Out of the money a crowd favourite. It produced over 2.7 million bpd in 2016, of which Even though it has over 48 billion bbls in crude reserves, Libya 2.2 million bpd were exported as either crude or refined products. is still a long shot. After the overthrow of the Gaddafi regime, The Kuwait Oil Co. (KOC) has plans to spend over US$30 billion in the production plunged from 1.7 million bpd to approximately next five years to raise production capacity to 4 million bpd. 400 000 bpd. Since then, relative calm has returned to the However, Kuwait faces a gas shortage. The country produced country. Es Sider, Libya’s biggest export terminal, reopened in approximately 1.3 billion ft 3/d of associated and non-associated gas, late 2016 after major repairs, and production climbed to over which is insuff icient to meet its domestic gas demand, and it must 1 million bpd. import LNG. The north Kuwait Jurassic field has been producing oil and BP and Eni are planning to spud wells in Libya in 2019. The gas from conventional carbonate reservoirs since 2008. Exploration announcement came after Eni purchased half of BP’s 85% stake near the field outlined extensive tight shale reserves, and KOC has in an offshore concession. BP has held onshore concessions in the ear-marked US$4 billion to add 1 billion ft 3/d of unconventional Ghadames basin and offshore concessions in the Sirte basin since production. KOC is also looking to develop other non-associated gas 2007. Unless various factions can consolidate federal authority, fields in a plan to boost total gas production to 4 billion ft 3/d. however, long-range prospects for the country remain elusive. Iran, which has 158 billion bbls of proven crude reserves Placers and 1000 trillion ft3 of gas, has been floundering in long odds Iraq, which contains 143 billion bbls of proven crude reserves lately. After sanctions were lifted in 2016 under a new nuclear and 100 trillion ft3 of proven gas, has been stumbling out of the agreement, production climbed to 4 million bpd. In 2017, Iran gate lately. The country has seen oil production derailed by wars completed construction of a terminal near Kharg Island in the Gulf against Iran, the US and its allies, and, most recently, ISIL. By 2017, that added 300 000 bpd export capacity. however, relative peace had returned, and its output climbed to In 2018, the Trump administration stepped away from the above 4.5 million bpd. nuclear deal and again imposed sweeping sanctions. The Treasury Iraq has plans to increase its production to 5 million bpd. In Department’s Office of Foreign Assets Control noted in November August, 2018, Chevron signed an MOU with Iraq’s Basra Oil Co. to that the effect of the sanctions was to limit exports to about develop several fields in the south of the country. The agreement 1 million bpd. will include studies to upgrade reservoir characterisation and Some importing nations have asked and received temporary extraction. Iraq has awarded contracts for six fields located in exemptions, and are also seeking out alternate sources of supply. the Basra Diala and Maysan governorate regions. The contracts The Treasury Department noted that increased US production will cover the rehabilitation of ageing infrastructure; the Ministry of Oil offset drops in Iranian supplies, helping to stabilise the market. expects production from the affected fields to reach 500 000 bpd. Until the sanctions are resolved, Iran’s oil and gas sector faces US-based oil services company Schlumberger has inked a deal significant pressure. with the Iraq Oil Ministry to drill 40 wells in the giant Majnoon oilfield. Royal Dutch Shell had operated the 240 000 bpd field The future in southern Iraq, before relinquishing operations to Basra Oil in When a resurgence in global crude supplies toward the end of June 2018. 2018 put downward pressure on oil prices, OPEC agreed to a six Algeria’s oil production and exports have been flagging over month reduction of 800 000 bpd of production and 10 non-OPEC the last decade, and now stand at approximately 1 million bpd countries agreed to cut a further 400 000 bpd, starting and 500 000 bpd, respectively. Gas production remains high at January 1, 2019 (Iran, Libya and Venezuela were exempted). 91 billion m3/y, however, three new fields – Touat, Timimoun and In the short term, MENA’s outlook is muddied by a proxy war in Reggane – are set to add 9.3 billion m3. In November 2018, Eni and Yemen between Saudi Arabia and Iran (which has seen oil tankers Total signed exclusive agreements with Sonatrach that cover a attacked), the political dispute between Qatar and its neighbours, virtually unexplored offshore area in Algeria, within the country’s and the murder of journalist Jamal Khashoggi at Saudi Arabia’s deepwater region. Turkish Embassy. Domestic gas demand is growing at a tremendous clip; the In the longer term, growth in North American (NA) shale Algerian Electricity and Gas Regulation Commission estimates production and Canada’s oilsands (and the development of a NA that domestic gas consumption will increase 50%, to 50 billion m3, LNG export industry), are placing pressure on traditional MENA by 2020. Algeria is thus moving ahead with plans to develop its markets. The countries of the Middle East and North Africa realise huge unconventional gas resources (the US Energy Information they must perform well in the home stretch; falling behind risks Administration estimates that the country has over 700 trillion ft3 significant financial and domestic consequences.

12 | Oilfield Technology March 2019 LEVERAGING LEGACY DATA

Jo Firth and Priyabrata Pradhan, CGG, UK, explore the value in reprocessing legacy seismic data sets.

ecent years have seen many rapid Many thousands of square kilometres of developments in subsurface imaging, seismic data around the world are suitable for R especially in velocity model building. This reprocessing. Many of these data sets provide means that not only can many older data sets be patchwork coverage, with different orientations reprocessed to a standard approaching that of and parameters, which would benefit from modern data sets, as a result of advances in areas being combined and reprocessed as contiguous such as deghosting and designature, but even volumes. In many cases, they may be improved data sets acquired relatively recently can benefit by infilling gaps with new acquisition. In more from reprocessing. As technology continually challenging areas, the data may be enhanced evolves, there is often value in reprocessing by over-shooting with new seismic acquired at a seismic data multiple times, ensuring it remains a different azimuth, which can then be processed valuable asset. with the older data to deliver the benefits in

| 13 illumination and multiple attenuation that multi-azimuth data more than a decade. These surveys are not a random patchwork provides. (like some reprocessing programmes), but rather were intentionally acquired in stages as a regular grid of multi-client Cornerstone Evolution projects, incorporating the latest advances in acquisition The Cornerstone Evolution reprocessing project in the Central technologies as they were developed. The earlier surveys were North Sea demonstrates the value achieved by reprocessing a all acquired with an approximate north-south orientation, large number of existing data sets in conjunction with newer while the most recent were acquired east-west, in some places acquisition. The Cornerstone data set consists of several phases overlying the previous surveys to provide dual-azimuth (DAZ) of acquisition, covering over 35 000 km2 (Figure 1), built up over data. The Central North Sea is a mature basin, yet still rich in opportunities for the discovery and development of new fields. There are many prospective intervals, with hydrocarbons encountered within three main sequences: Upper Jurassic sandstones, Cretaceous chalks (on the Norwegian side of the Central Graben) and Lower Tertiary submarine fan systems. Advances in technology have continued to allow new play models to be explored and new discoveries to be made. The development of broadband technology has enabled new stratigraphic traps and subtle structural closures to be delineated, and reservoir development and hydrocarbon recovery have been enhanced by more information about local facies variations and reservoir compartmentalisation. The higher frequencies in broadband data push the limits of amplitude tuning effects and help to resolve thin beds and pinch-outs that have previously been problematic to image. The low frequencies also play an important role by reducing sidelobe interference and helping in the interpretation of subtle facies transitions. Figure 1. Map showing the Cornerstone area, showing the areas of The Central North Sea suffers from a number of geophysical BroadSeis and dual-azimuth data. challenges, including shallow anomalies, heavy multiple contamination and sharp velocity contrasts, all of which may be resolved by modern processing techniques. Although the surveys that make up Cornerstone have already been recently reprocessed in depth (2015), the advances made in full-waveform inversion (FWI) for modelling velocity, visco-elasticity (Q) and anisotropy mean that considerable improvements can already be achieved by reprocessing again. The previous reprocessing started from archived pre-processed data, but the new Evolution project is reprocessing the data completely, starting from the field tapes, to gain the maximum advantage from improvements in signal processing such as 3D designature and deghosting. The project also benefits from advances in demultiple, especially the move from predictive to model-based techniques. Two areas of Cornerstone have been reprocessed as a priority, one of which is in the DAZ area and is the example discussed here.

Designature and deghosting Figure 2. Data before (left ) and aft er (right) the new demultiple 3D designature was applied to all the data sets using wavelets (recursive 3D MWD with 3DSRME). generated from recorded near-field hydrophone (NFH) data, with advanced Ghost Wavefield Elimination (GWE) 3D deghosting to extend the bandwidth as much as possible. In the most recently acquired surveys, the NFH measurements were used on a shot-by-shot basis to provide an accurate estimate of the source response to improve debubbling and zero phasing. For the older surveys, the quality of the NFH recordings was not suitable for shot-by-shot use, so global wavelets were generated for each survey. The bandwidth that GWE can achieve depends on the signal-to-noise ratio in the recorded data, and so the ultra-low frequencies of BroadSeis™ true broadband data could not be Figure 3. Comparison of the 2015 velocity model (left ), which used obtained for all surveys. Nevertheless, considerable extension multi-layer tomography, and the 2018 model (right), derived from Q-FWI, to the original bandwidth has been achieved, providing sharper showing the improvements in resolution achieved (image courtesy of wavelets and improved visibility of impedance contrasts for CGG Multi-Client & New Ventures). enhanced interpretation.

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© 2019 Abaco Drilling Technologies. All rights reserved. Demultiple reservoir-focused reprocessing workflow and creation of AVO Predictive deconvolution in the tau-p domain has been the QC products at intermediate stages in the sequence, have standard demultiple tool in shallow-water areas for many years, contributed to a significant uplift in image quality, reliable but in some cases has recently been found to harm primary reservoir properties and Quantitative Interpretation (QI) reflections, especially at low frequencies and at near offsets. attributes. Using model- and inversion-based methods avoids this effect. A combination of the latest demultiple techniques is being used in Full-Waveform Inversion the Evolution reprocessing, including 3D recursive model-based One of the most significant advances in model building of the water-layer demultiple (MWD), for the waterbottom and last few years has been the evolution of FWI from a research short-period peg-leg multiples, and 3D surface-related multiple project to a large-scale production tool. FWI is now used elimination (SRME) for longer-period, surface-related multiples routinely to determine a number of different parameters, from (Figure 2). velocity and anisotropy to Q. The near-surface of the Central North Sea features large-scale Reservoir-oriented processing sequence Quaternary channels that strongly influence the imaging of Modern multi-client data from CGG is processed in such a way deeper data. Accurate modeling of these shallow features was as to be ‘reservoir-ready’. Quantitative amplitude-versus-offset one of the main aims of the Evolution project to reprocess the (AVO) QC attributes, generated after each key processing stage, Cornerstone surveys, as inaccuracies in the shallow section can be used to ensure that the seismic data will be compliant cause distortions in the imaging of the deeper structures. FWI with any requirements for later reservoir characterisation work. uses recorded and modelled waveforms to derive a high-velocity One of the benefits of the reprocessing has been the increase model of the near-surface, which frequently has enough detail in the usable angle range of the data. The improvements in for use in shallow hazard identification (Figure 3). It does not rely the signal processing and demultiple, combined with the on assumptions regarding structure or require residual moveout picks and is therefore an effective and reliable tool. In addition to the velocity anomalies caused by these channels, there are also areas of gas leakage that cause absorption effects, resulting in amplitude dimming, a serious impediment to the accurate amplitudes required for AVO. Q-FWI is an important new tool for identifying these anomalies, whose effects can then be compensated by Q-migration. Jointly inverting for Q phase and amplitude effects alongside velocity reduces the likelihood of erroneous velocities being Figure 5. Evolution of image quality from the 2010 processing, through 2015 to today’s version. Note that the LS-Q derived from FWI due to the data is an initial test, and the processing of this data is not yet finalised (image courtesy of CGG Multi-Client & New cross-talk between Q and Ventures). velocity.

Figure 4. Figure 4. (a) Input velocity model from the 2015 reprocessing, derived using TomoML multi-layer tomography; (b) FWI velocity model derived using constant background Q. Due to the Q anomaly not being included, the velocity beneath the channel is too low; (c) Q-FWI velocity model derived by joint inversion for Q and velocity; (d) Q-migration with Q model overlay. The absorption anomaly in the Q model delivers stable velocities beneath, so that local pull-up is reduced and amplitude is recovered (all images courtesy of CGG Multi-Client & New Ventures).

16 | Oilfield Technology March 2019 Q-FWI results show good conformance with geology and broadband data, followed some years later by the industrialisation seismic structures. The Q-FWI successfully identifies the shallow of FWI. The next big improvement is likely to come from extending glacial channels and their associated velocity and absorption the improvements in azimuthal sampling, delivered by wide- and anomalies, to deliver a more stable velocity field beneath them full-azimuth surveys, from the Gulf of Mexico to more areas of the (Figure 4). The reprocessed data shows much sharper features world, even those without salt. Rich- and multi-azimuth surveys than the legacy processing results, with better well ties and not only benefit from improved illumination but also from the therefore more reliable depth imaging. denser fold coverage, which significantly improves signal-to-noise ratios and attenuation of multiples. CGG is already acquiring a Conclusion rich-azimuth survey over the North Rona Ridge, Northwest of The Cornerstone Evolution project clearly demonstrates the value Shetland, and various node surveys are being planned around the that even legacy data can contribute when reprocessed. For the world for the coming years. With this trend, ownership of legacy priority area discussed here, the older data was processed in data to overshoot at a diff erent azimuth will be an even more combination with newer acquisitions to deliver DAZ coverage. In valuable asset than it is already. Seismic data is always as good as other areas of the full project there is only single-azimuth data, the day it was acquired; it does not perish, even though the media some of which was acquired with broadband technology and is only that it is stored on may. Newer, more advanced data may deliver a couple of years old, and some of which is conventionally acquired improved imaging, but older data remains a valuable commodity. data. Figure 5 shows the evolution of data quality from the initial 2010 processing to today’s DAZ Least-Squares Q-PSDM. The Least-Squares Q-PSDM panel is only an initial test. Unlike the other DAZ panels, which have been processed through a full DAZ sequence, each azimuth has been processed individually and then been stacked together with 50% weights. Further improvements are expected when this has been processed through a proper DAZ sequence. The entire 35 000 km2 Cornerstone project is being combined and reprocessed through the new sequence. This will deliver a seamless, contiguous volume of the highest-quality reservoir-ready data. An early-out volume will be available during the third quarter of 2019. CGG has recently reprocessed several of its older seismic data sets around the world, in some cases combining them with new acquisition, to deliver large contiguous volumes of modern, broadband, pre-stack depth-migrated seismic data. These large-scale projects include over 100 000 km2 of data in the Santos and Campos Basins, 38 000 km2 in the Perdido fold belt in the Mexican Gulf of Mexico, and 11 000 km2 of data offshore south-east Australia, where new, complementary acquisition is planned. Larger surveys deliver a better overall understanding of a basin by providing a regional view. By processing these surveys using the latest advanced FWI imaging sequences, they also have the fine resolution necessary to make the best-informed decisions. The rapid improvement in subsurface imaging technology is continuing, meaning that reprocessing is becoming mmoˆ-ঞomş|;1_moѴo]‹-u;bmo†u  more necessary – today’s highest-quality $;m7;h-7;Ѵbˆ;uv-7ˆ-m1;71olrѴ;ঞomv-m7ruo7†1ঞomorঞlbv-ঞom data will be next year’s baseline for =ou‹o†uu;v;uˆobuvĺ!;]-u7Ѵ;vvo=;-uѴ‹Ѵb=;oul-|†u;C;Ѵ7v-rrѴb1-ঞomvķ improvement. Nevertheless, improvements ‰;ruoˆb7;0;vroh;voѴ†ঞomv-m7C;Ѵ7Ŋruoˆ;m|;1_moѴo]b;v|o tend to progress by incremental stages bm1u;-v;ruo7†1ঞomo=‹o†u‰;ѴѴĺ with occasional quantum leaps. Recent step-changes have been the introduction of mmoˆ-ঞˆ;-m7-7-r|-0Ѵ;ķ$;m7;h-bv‹o†uruoˆ;m1olrѴ;ঞomvr-u|m;u

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18 | Tom Hewitt, Jordan Lewis, and Stephen Forrester, NOV, examine the use of custom solutions to the challenges of North American coiled tubing. s North American shale has continued its rebound from 2014 lows, coiled tubing has similarly grown in A importance. Coiled tubing is facing new challenges, largely centred around the difficulty of horizontal wells with extended laterals as well as a wider variety of well paths and geological conditions in expanded drilling areas. This challenge is further impacted by the complicated logistics of coiled tubing operations, which require significant movement of heavy equipment. National Oilwell Varco (NOV), recognising that the changing landscape

of coiled tubing demanded new solutions, has been developing custom answers in response.

Enhancements for existing equipment One issue surrounding coiled tubing equipment is retrofitting. It has become more common, across virtually all drilling- and completions-related capital equipment, to upgrade components and functionalities rather than purchase entirely new equipment, especially as companies remain cost-constrained and wary of unnecessary large purchases. The need for upgrades will be especially prevalent in 2019 and moving forward, as pressure pumping and coiled tubing fleets have largely been built out in 2018 on the back of the shale boom. Motley Services, a provider of well completion and intervention services

| 19 in the Permian Basin, is one company recognising the value of Logistical hurdles retrofitting. After purchasing an older coiled tubing unit at an Another issue for coiled tubing equipment has been the auction, Motley approached NOV for the prospect of an overhaul. constraints of mobilising and operating the equipment in NOV completely stripped the unit and rebuilt it to like-new, different jurisdictions where highway regulations typically including more advanced equipment and a larger control cabin. differ substantially, thus restricting where the equipment is The unit was originally built for 2 in. coil, and after the upgrade able to legally go. Copper Tip Energy Services, a Canadian well it could handle 2⅜ in. coil. This meant that the unit could handle servicing provider offering coiled tubing, nitrogen pumping, the larger coiled tubing necessary for longer, more difficult and fluid pumping solutions, was looking to enhance their laterals – and that Motley Services was equipped to provide such product offerings and add NOV coiled tubing equipment to their services for their customers. current large fleet of NOV-built nitrogen units. Unfavourable market conditions in Canada, primarily related to pipeline constraints and discounted oil prices resulting in reduced capital investment, presented Copper Tip with a less-than-ideal operating environment. Recognising that several Canadian service companies were heading south of the border to take advantage of more lucrative market conditions, Copper Tip sought a way to move their equipment as well should conditions continue to decline. Unfortunately, moving such large equipment was not as simple as it sounds; allowable dimensions, weight, and axle/suspension configurations dictate whether or not something can be moved on standard roads. Without the ability to legally move equipment between Canada and the US, Copper Tip had little recourse other than the prospects of doing nothing or buying two separate units configured to the different countries’ specs. A standard configuration in Canada is a 24 wheel, three-axle trailer suspension, while in the US the configuration is a 20 wheel, five-axle suspension. Neither of these are recognised in the other country, but it was impossible to justify purchasing two units, especially with the economic uncertainty of the Canadian unit, which might have to sit idle for a prolonged period. Faced with this dilemma, Copper Tip approached NOV to design a technology that would allow a unit to travel on both sides of the border, effectively changing the suspension to enable use in each location. NOV developed a new coiled tubing unit that had the ability to interchange complete axle groups in a relatively short time and at a minimal cost to the operator. If it is necessary to relocate the coiled tubing unit, the alternate suspension/axle group – the one required by the country to which the unit is headed – is pinned into place, and the unit can cross the border safely and legally.

Bringing together new equipment with training initiatives Bridging the skills gap with new or upgraded equipment is another important component of optimising coiled tubing operations. Not having enough staff who can use the equipment effectively makes the investment worthless, an issue compounded by the financial loss and HSE concerns should an incident occur as a result of untrained staff. Balanced Energy Oilfield Services, Inc. is a coiled tubing operator in the western Canadian Sedimentary basin. With a desire to increase their market penetration in North America, the company needed to both add equipment that would be permittable in both markets, and hire and train new employees to meet higher demand expectations. Working Figure 1. The first image in the sequence shows the original unit purchased by with NOV, Balanced Energy was able to develop equipment Motley Services, while the next two images show the unit overhauled by NOV and specifications suited to both Canada and the US. In addition, the new coiled tubing reel for larger spools. they developed a complementary training programme to

20 | Oilfield Technology March 2019 The future of energy startsHERE In New Orleans, LA

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Contact For Pricing & More Information LAGCOE.com/expoLAGCOE.com/expo +1 337-235-4055 [email protected] reduce operational and service-related issues encountered with coiled tubing itself. To optimise coiled tubing string design, NOV expansions. partnered with steel suppliers to develop TRUE-TAPER™ XR, Balanced Energy requested that NOV provide specific an enhancement that is designed to minimise the number of training on the coiled tubing equipment as it was delivered. One bias welds in the tapered string and to assure a gauge-to-gauge potential area for improvement was with coiled tubing injectors. bias weld in each instance. While traditional tapered strings The coiled tubing injector grips the tubing as it is inserted or have stress points at the bias weld juncture due to non-uniform pulled out of the well, and extremely high forces are required to load transfer, the TRUE-TAPER string achieves a linear taper by control the tubing without damage to the injector or the tubing gradually varying the thickness of the flat steel strip over almost itself. In some instances, the coiled tubing could be a continuous its entire length. This reduces stress concentrations and the piece of steel pipe in excess of 20 000 ft and valued at more number of bias welds while optimising strength-to-weight ratio than US$200 000, making potential damage a major concern. and safety factors. Improper maintenance or operation of the injector could damage Pioneer Energy Services, a provider of coiled tubing services the tubing. After implementing new training practices created for well intervention and new well completion programmes, by NOV, Balanced Energy saw a significant reduction in service needed a product that would help them meet the challenges of issues associated with both the coiled tubing injector and the longer laterals in unconventional shale. NOV provided Pioneer coiled tubing. Improvement was so dramatic that the company with the TRUE-TAPER XR. Pioneer initially developed string requested additional training on other aspects of coiled tubing designs with XR tapers that could better overcome the weight equipment and operation and, more broadly, various pieces of restrictions of the Rockies, which were imposed by using a intervention and stimulation equipment. one-piece coiled unit and stricter DOT laws in the region. Given Balanced Energy found the injection operation training to be that acceptable pipe weight maximums were much lower, the useful and saw good results from supervisors who were enforcing new XR tapers allowed for hourglass string designs that had and following the new procedures. The technical background of better reach and set-down weight in their well simulations versus the instructor, coupled with NOV’s knowledge of the equipment non-XR taper designs. This increased performance allowed as the OEM, was key. Pioneer to reach total depth on wells that were over 4 miles in measured depth and that could have 1 - 2 mile laterals. With Optimised coiled tubing string design non-XR designs, reaching the required depth would have been Achieving success with coiled tubing operations depends not extremely difficult, if not impossible. only on the equipment involved but also on the design of the As horizontal wells with long laterals require heavy-wall tubing in the vertical section to go beyond the heel into the lateral, the string wall transition needs to go from heavy wall to light wall as quickly as possible to reduce the overall weight of the string. The XR tapers allowed Pioneer to maximise their string lengths while maintaining simulated performance levels and meeting strict weight requirements. In addition to completing projects with extended-reach laterals, the XR tapers also provided for greater string length. While without TRUE-TAPER XR the design would have resulted in a shorter string length, with them the string length could still be maintained for required well depths even as pipe was cut during normal string management.

Looking forward Due to the number of problems that can develop in producing wells, coiled tubing will remain a critical component of intervention solutions for the Figure 2. The new coiled tubing unit, designed to allow rapid change-out of foreseeable future. As failing to address problems suspension/axle groups to enable movement between countries. with producing wells could lead to a total loss of production over time, finding an appropriate intervention solution quickly is key. For many wells, the simplest considerations are well design versus solution economics – do they match, and is the solution financially feasible? Coiled tubing is frequently the answer due to how time-effective it is, and because it eliminates the typical costs of removing the tubing from the well via a workover rig. Figure 3. On a previous project, NOV reduced the length of a 2⅜ in. coiled tubing string Combining the utility of coiled tubing with custom design by approximately 64.5% when compared to a conventionally tapered design. The solutions to problems will help companies get amount of taper sections was decreased from four to two, and the total average length of ahead of the curve in this highly competitive, rapidly the tapers from 4315 ft to 1530 ft , with the TRUE-TAPER XR design. evolving market.

22 | Oilfield Technology March 2019 EENHANCINGNHANCING TTUBINGUBING TTECHNOLOGYECHNOLOGY Irma Galvan, Global Tubing, USA, explores how the rise of ‘super lateral’ wells is driving the optimisation of coiled tubing interventions.

echnological advances in horizontal drilling and hydraulic fracturing Well status created a resurgence in focus on US unconventional reservoirs, As of January 2019, well laterals of more than 23 000 ft have been drilled T driving the exponential increase in oil and gas production over the onshore internationally, with domestic examples of up to 19 000 ft in last few years. These advances gave operators the ability to produce shale length in Utica Shale in Pennsylvania. This drilling strategy has brought oil and gas at reduced costs and continue to improve profit margins as the advantages and eff iciencies, but oft en results in complex well trajectories wells reached higher production rates. which complicate service operations throughout the life cycle of a well. To optimise well productivity and economics, operators are An overview of Drillinginfo shows an increased number of wells with maximising reservoir contact while minimising surface footprint by over 12 000 ft lateral lengths since 2013. At the same time, the number of increasing drilled lateral lengths. As 10 000 ft has become increasingly wells surpassing 14 000 ft lateral lengths have increased by 5% of the total common and achievable, well producers continue to push the lateral wells drilled in the same time frame (Figure 1). Figure 2 shows the US well well boundaries to over 15 000 ft , creating ‘super lateral’ wells. These count of laterals featuring over 14 000 ft in the last 5 years. wells challenge not only directional drilling, logging and completions, but According to off icial data, lateral length alone has increased particularly coiled tubing (CT) interventions. approximately 130% from 2010 to 2018 in plays such as the Niobrara and

| 23 Permian Delaware. US operators in the Bakken, Permian, Haynesville, and due to increasing demand for larger coiled tubing units (CTU) and more Marcellus are now drilling ‘super laterals’ (Figure 3 - right chart). It can be eff icient equipment mobilisation and logistics. observed that the maximum drilled laterals in 2010 are the average well CT equipment manufacturers have released CTUs that are able lateral lengths in 2018. to handle larger tubing in line with local transportation regulation guidelines. These new units are capable of transporting over 27 000 ft Industry response of 2.625 in. CT weighing upwards of 160 000 lbs. CT injectors are being As drilling technology is creating ‘super lateral’ wells, the CT industry has redesigned or retrofitted to be able to deliver pull and snub capacities developed products to satisfy demands for CT with extended capabilities, of 140 000 lbs and 70 000 lbs, respectively. reliability and predictability. CT service and manufacturing companies Meanwhile, CT manufacturers such as Global Tubing are are continuously working with operators to develop products and responding to meet the ever growing demands of the industry. The technologies to remain a competitive option with deeper, longer, and more latest technological development in the CT manufacturing industry is challenging wells that continue to drive the industry. the implementation of an in-line quench and temper (Q&T) process, In response to the demand, US operators have had success using CT such as HALO Induction Technology™. This process enhances the in well laterals of 12 000 ft to 13 000 ft in post-fracture plug mill-out and overall CT life and predictability by producing tubing with more clean-out operations by deploying 2.375 in. and 2.625 in. CT diameters uniform microstructure throughout its entire length, increased material with over 23 500 ft tubing length. These CT strings use custom-built wall strength (110 000 psi to 130 000 psi yield strength), and improved bend thickness configurations and state of the art manufacturing technology of fatigue performance. The final product is called DURACOIL. When high-grade materials that surpass 125 000 lbs in tube weight. DURACOIL products are combined with rapid-taper strip technology Newer models of surface CT equipment are being manufactured and an advanced CT design, strings have been shown to achieve to accommodate the longer CT lengths along with heavier and larger unprecedented well lateral reach with improved service life. CT strings. However, the field deployment of these massive CT rigs to Engineered CT optimisation has become an integral part of the remote field locations has become a diff icult and complex challenge well intervention job design. It has progressed to a complex process that requires a multifaceted understanding of well conditions, CT working pressures and axial loading boundaries, low cycle fatigue, forces, stresses and fluid mechanics expected during the operation. CT surface equipment capabilities and regional transportation logistics are also considered during the string design optimisation. With this new generation of large diameter CT strings that exceed 24 000 ft in length and 130 000 lbs in weight, one of the critical challenges is the current mobilisation weight constraints of the CT surface equipment (reel and trailer). As mentioned previously, CT equipment manufacturers have paced their releases with the market demand of handling heavier CT. Figure 1. US well count of +10 000 ft laterals lengths (Source: Drillinginfo). However, the existing weight restrictions continue to limit the maximum wall thickness that can be used in the CT design, which aff ects the stiff ness and horizontal reach capacity of that specific CT string design.

Engineered approach CT design methodology followed by Global Tubing has modernised the CT manufacturing industry and enabled CT service providers to support the requirements of operators (see summarised methodology in Figure 4). This design criteria has been proven to increase CT performance in extended reach Figure 2. US well count of +14 000 ft laterals lengths (Source: Drillinginfo). well operations, as well as increasing useable service life while conforming to surface equipment design constraints. The process starts by reducing the CT weight in the horizontal section of the well. The CT weight can be reduced by increasing the diameters to wall thickness ratios (D/t) in the downhole end, achieved by decreasing the wall thickness as much as possible. To retain mechanical properties, the material yield strength is increased to compensate the pressure and axial load capacity. The process continues by strategically selecting and placing various wall thicknesses along the length of the CT string to improve Figure 3. Maximum lateral length per US shale comparison 2010 (left ) versus 2018 (right) (Source: Drillinginfo). bending stiff ness and avoid the onset

24 | Oilfield Technology March 2019 Global Publication

A global industry requires a global publication

Subscribe online at: www.oilfi eldtechnology.com/subscribe of helical buckling in the well. If necessary for weight minimisations, Friction is another variable that can be reduced by using the heavy wall thickness in the upper end (reel core-end) is reduced vibration tools (extended reach tools) and fluid additives such as as much as permissible, creating the ‘hourglass’ configurations. An metal-to-metal lubricants and friction reducers. The force generated hourglass string configuration features a reduced wall thickness in by the vibrating tool is a function of the amplitude of the pressure the upper end of the CT string which is typically not under severe pulse generated, the flow rate across the tool, as well as the cross- stress. However, this reduced wall is carefully selected to provide sectional internal area of the CT string. The tool lowers the eff ective enough axial load capacity to maintain safe overpull values during friction coeff icient and translates to lateral axial movement further operations. This new trend of string design configuration does not into the well. Fluid additives also lower the eff ective friction by way of aff ect the reach capacity of the CT, if utilised properly. The main providing lubrication between the CT and the casing, enabling further benefits are: weight optimisation, reduction of CT frictional pressure lateral movement. losses due to the restricted inner diameters, and reduction of tubing The combined eff ect of using a custom engineered CT string costs. design with vibration tools and/or fluid additives to improve reach is The number of wall thicknesses and lengths of the transitions significant. Depending on the complexity of the extended reach wells, have significant influence on the performance of the string, it is possible to reach target depths with smaller CT sizes and lighter particularly on extended reach, weight and overpull. In extended string makeups, eliminating costly logistics and specialised surface reach CT designs, the configuration of the transitions points is key equipment. for the performance of the string. This includes the transitions from thicker to thinner wall, the required length of each section, and the A look ahead de-rating of the string due to the bias welds. Technology such as Across North America, a movement towards drilling ‘super laterals’ SMARTaper™ provides rapid wall thickness transitions of 300 ft to has manifested in E&P companies’ target objectives for future 500 ft in length to help place specific thicknesses along the length development. Operators in the Bakken and Permian Basin projected of the string to enhance force transmission to the end of the tubing, drilling for 2019 of super well laterals reaching over 3 miles. The use increase strength and stiff ness, and reduce fatigue accumulation and of CT has been thoroughly vetted and custom CTUs have been built weight. to support the increased CT length and weight. CT service companies collaborated with Global Tubing to engineer strings that have a reach capability in wells with over 15 000 ft laterals. CT force analysis and friction matching of post-job data evaluations gathered from several long lateral wells, were used to extrapolate the CT performance in multiple super lateral wells drilled in West Texas and North Dakota. An extensive CT design evaluation, in diff erent planned wells, revealed that CT interventions in over 15 000 ft laterals are feasible by utilising 2.625 in. and 2.875 in. CT diameters. Figure 5 shows predicted lateral reach of custom-engineered CT strings in 2.375 in. to 2.875 in. CT sizes. These CT strings are expected to be over 27 500 ft in Figure 4. Summarised CT design methodology for extended reach strings. continuous length and exceed 150 000 lbs of tube weight (Table 1). The utilisation of high strength quench and temper materials with special wall thickness configurations, featuring specific D/t ratios and 0.276 in. maximum wall thickness, which is the thickest used historically in CT interventions, have maximised CT lateral reach capabilities in ‘super lateral’ wells. The inclusion of the latest technologies on extended reach tools and fluid additives is essential to maximise friction reduction and wellbore cleaning at rates of over 4 BPM and working pressures above 8000 psi. With the trajectory of super laterals pushing even farther, considerations will need to be made for equipment that is able to safely handle over 30 000 ft of large OD tubing and provide pull capacities of over 200 000 lbs.

Conclusion Figure 5. Anticipated lateral reach of custom-engineered CT designs in ‘super The oil and gas industry has had a long history of continuous laterals’. innovation and technological development in support of E&P operations. Technological innovations on surface equipment, Table 1. Engineered solutions for CT interventions in super lateral wells. downhole tools, and custom-engineered CT strings, along with 2 ⅜ in. CT 2 ⅝ in. CT 2 ⅞ in. CT refined operational practices and logistics, are required to perform low-risk ‘super lateral’ completions on a larger scale. CT Length 27 500 ft 27 500 ft 27 500 ft As new cutting-edge horizontal drilling and completion Estimated manufacturing 134 000 lbs 150 000 lbs 173 000 lbs technologies are released and utilised in the industry, CT weight manufacturers continue to innovate and provide engineered

Overall weight solutions that enable coiled tubing to be a premium, safe and (working reel 148 000 lbs 168 000 lbs 195 000 lbs reliable technology in the toughest environments for the most + CT) critical projects.

26 | Oilfield Technology March 2019 CCollaborativeollaborative Completions

Dale Logan, C&J Energy Services and Panos Adamopoulos, Seismos, USA, examine a combination of new technologies designed to optimise horizontal completions.

he process of optimising a horizontal completion is typically a series of Ttrial-and-error adjustments designed to improve well productivity. As changes to the treatment schedule and/or perforation scheme are implemented, the eff ectiveness is judged by comparing the production of the new well to the production of off set wells. However, most operators agree that this optimisation process could benefit significantly from additional feedback. For instance, when there is an observed diff erence in production between the new well and neighbouring wells, is it caused by variations at every stage – or is it just a few stages that are underperforming or overperforming? It would also be valuable to be able to diff erentiate between productivity variations that result from changes in the completion design versus changes due to heterogeneity in the geological facies along the lateral. There are several commercial technologies in the market that attempt to address these questions. A few examples include hydraulic frac monitoring using microseismic, production logging and tracer logs. While these techniques have been used successfully in some instances, none have proven valuable enough to be universally accepted. The biggest challenge is that they are diff icult to deploy and require a lot of planning on the part of the operator. And, because diff icult deployment translates to increased expenses, most operators are willing to consider using these technologies only if they are foolproof, easy to use and provide complete diagnostic insight. Unfortunately, this

| 27 is not the case with any of them, so they are relegated to exist as niche Quantitative data tells the story players within the shale industry. In a recent well, this collaborative approach was put to the test. In part one of the test, a group of seven stages was completed Simple deployment delivers sophisticated data using 57% less proppant and 38% less slurry than a comparable The new Seismos-Frac™ service targets this shortcoming with a group of stages with similar rock properties (as indicated by the simple, noninvasive method that delivers a direct, comprehensive LateralScience facies). For the subject test group, the Seimos-Frac measurement of fracture-network properties. Seismos’ approach geometric results indicated 35% less half-length, exactly the same uses a combination of ambient noise and induced, tube-wave height and slightly higher frac width. Qualitatively, these results pressure pulses to investigate the hydraulic fracture network. The make perfect sense – and, since the goal was to achieve a shorter measurements delivered include frac geometry (width, height and half-length (to avoid frac hits), the operator was pleased. half-length), as well as near- and far-field characterisations of fracture In part two of the test, a group of 16 stages drilled in network complexity, fracture conductivity and proppant placement. lower-strength rock was compared to a group of eight stages drilled These results are produced on a stage-by-stage basis in near-real time, in higher-strength rock. The treatment schedule and completion normally within 10 minutes of the completion of pumping. This enables design were held constant between the two groups. In this scenario, the operator to review the measurements, assess the performance of a the lower-strength rock delivered half-lengths that were 24% longer, given stage and then use any learnings on successive stages. accompanied by far-field fracture conductivity that was 30% lower The service is relatively aff ordable because it uses a than in the higher-strength rock. Once again, this result is consistent straightforward installation process that is virtually plug and play. with a lower-strength interval creating more planar fractures that A pair of pressure transducers is installed at surface, which can extend farther from the wellbore, which distributes the proppant typically be done in less than an hour. During the completion process, across a larger area and therefore produces a lower average ambient noise is analysed, and pressure pulses are sent down the conductivity index. Qualitatively, this is consistent with Nolte plot fluid column to investigate the perf clusters – both before and aft er interpretations made on previous wells, and a quantitative value fracturing operations. This can be done without any interruption can now be assigned to the impact observed. to the on-location completions team. As a result, this technology is particularly well suited to the industrialised environment of today’s Better information delivers better value shale industry. The value of Seismos-Frac measurements is obvious to experts in the completion engineering domain, and this value goes Collaboration is key well beyond optimising the completion design. The principle Seismos-Frac technology has been available in the field since applications that operators have identified as most valuable include 2017 and has been deployed on roughly 110 wells to date. Early the following: evaluations show that variability in frac geometry and conductivity from stage to stage is not only common, it is oft en the norm. The Well-to-well optimisation two most frequent causes for these variations are changes in the treatment schedule and changes in the rock properties along the New field development horizontal wellbore. To isolate the two sources of variability, Seismos This application can be extremely valuable when an operator is encourages operators to use the Seismos-Frac service alongside moving into a new area and trying to determine what works and C&J Energy Services’ LateralScienceSM method. This method uses what does not. It can provide clarity on what the fracture system existing drilling data to evaluate changes in rock mechanics along the looks like and what well spacing might be most appropriate. It lateral. As with the Seismos-Frac service, the LateralScience method can also provide insight into understanding correlations between is delivered in an aff ordable, noninvasive manner, which makes the stimulation designs, geology and fracture-network properties. tandem technologies a natural fit into any completion workflow. Sensitivity studies Seismos-Frac measurements can also quantify how sensitive the completion is to any changes implemented in the treatment schedule. It is not unusual for operators to experiment with changes in slurry volumes, pump rates, proppant concentrations, chemical additives, etc. Real time, quantitative feedback on how these changes impact fracture geometry and fracture-network properties aff ords the operator greater insight to help decide whether to adopt a new completion approach. In addition to the real time value brought by sensitivity studies on a stage-by-stage basis, they are also useful aft er the fact to plan for the next well.

Stage-to-stage optimisation (real time)

Completion optimisation When operating in well-understood areas, the value of these measurements is realised in real time, stage-by-stage completion Figure 1. This graphic representation shows the LateralScience facies (indicated optimisation. The original treatment schedule assumes an in trajectory plot) combined with Seismos-Frac results for both geometry (blue) anticipated geometry and set of fracture-network properties. The and conductivity (green). Lower-strength stages at the heel show much longer metrics that most completion engineers use to gauge fracturing half-lengths than the high-strength stages further downhole. performance are pounds of proppant per lateral foot or barrels

28 | Oilfield Technology March 2019 of treatment fluid per lateral foot. When wells perform outside of field. Experience has shown that there can be significant ‘value expectations, they presume it is related to these metrics or that it is due leakage’ at the field level if this is not properly addressed. This is to poorly distributed proppant. By monitoring each stage, compliance the primary driver in the alliance formed between Seismos and C&J can be assessed and the treatment adjusted as needed. When Energy Services. adjustments are required, the monitoring also provides measurements Seismos believes value leakage can be minimised by aligning to quantify the impact of each treatment change to the resulting its Seismos-Frac off ering with a service provider that is fully vested fracture system. in the success of the service. It starts at the front lines, where C&J’s frac engineers are trained to understand both LateralScience and Zipper fracs Seismos-Frac technologies – as well as how the two complement When it is time to develop the field, most operators move to pad each other. On-site engineers are fully briefed on both the drilling and zipper fracs. The tighter well spacing introduces issues overarching objectives of the survey and the expected results. It like potential interference between wells and even frac hits. In is very important that the person in charge of executing the job this case, understanding the frac height and half-length is critical understands completely how each specific action will impact the to ensure compliance. This allows the operator to approach the success of the survey. While communication with the head off ice is completion aggressively while avoiding excessive frac length that important, communication between the frac van and the Seismos could be detrimental to production. trailer is vital. When this is done seamlessly, the odds of success increase significantly. Operational assurance In some scenarios, the focus will be on operational eff iciency. By Setting the stage for the next generation monitoring treatments on the fly, an operator can detect issues – such As with any groundbreaking technology, growth and adoption follow as leaking plugs, hydraulic communication with previous stages or a distinct life cycle – and these are still the very early days of the even screenouts – as they develop. Providing an additional tool to Seismos-Frac off ering. While the service is being embraced by the detect these events enables the operator to do a better job of reacting industry, it is still in the evaluation phase as operators continue to to them and ultimately in adjusting the approach to avoid them. test it and become comfortable with the results they are getting. Equipment and people are being added as quickly as practical to Delivering results meet the demand. Pioneering technologies will enable the next As discussed above, this service has the potential to change how the generation of engineers to make better-informed decisions and completion workflow is performed in the field. However, to transform ultimately deliver more oil and gas with ever-greater eff iciency. The this potential into tangible value, the plans put together at the head Seismos-Frac and LateralScience collaboration provides a preview of off ice must be well aligned with what is actually happening in the what that will look like.

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GLOBALPETROLEUMSHOW.COM March 2019 Oilfield Technology | 29 DDevelopingeveloping a digitaldigital ffutureuture

Manoj Nimbalkar, Weatherford International, USA, discusses recent advances in digital and cloud-based technology designed to drive oilfield productivity.

afely producing more barrels at a lower cost is and cost reductions. Leading the way is the increasing Sthe common, industry-wide goal for operators adoption of technologies that incorporate components – despite increasingly challenging operating of Industry 4.0. environments and constant fluctuations in economic cycles. Industry 4.0 and Production 4.0 In response, the oil and gas industry has devised The world is currently undergoing a fourth industrial innovations across each phase of the well lifecycle – revolution. During the first revolution in the exploration, drilling, completion, and production – to nineteenth century, industries embraced water and extract hydrocarbons eff iciently and cost-eff ectively. steam-powered mechanisation for the production of For example, in the past operators have leveraged commercial goods from large, centralised factories. innovations in exploration, drilling and completion In the second revolution during the early part of to drill more wells in sweet spots, add more fracture the twentieth century, electric power enabled mass stages per well, and pump more proppant per stage to production and assembly-line creation of goods boost production. However, this solution has plateaued such as automobiles. During the latter half of the in terms of eff iciency. New, innovative completion twentieth century, the third revolution introduced designs – including intelligent completions – have computers, automation, and robotics. Aff ordable helped to foster a production renaissance in the US, semiconductors brought computers into customers’ but unless a major step change in technology occurs, homes and eventually their pockets. All three of the benefits yielded from these solutions will plateau these previous revolutions maximised productivity as well. and eff iciency while reducing costs. With no major technological advances introduced For decades, digitalisation has increasingly since the advent of artificial lift , the production phase is served as a vehicle for achieving these goals, the next frontier for realising significant eff iciency gains especially in oil and gas. However, the paradigm of

30 | Industry 4.0 – the fourth revolution – has altered not asset, well, or any other level from a single dashboard, just how digital technologies are used, but also how analytics aids in the identification of anomalies and organisations think and operate on a larger scale. trends along with opportunities to improve eff iciencies, Industry 4.0 is about linking technologies so they predict future performance, optimise production, and can better communicate with each other and make maximise profits. Furthermore, instead of serving a business or operational decisions without human purely mechanical function, analytics helps oilfield involvement. While other technology-driven industries equipment to act as intelligent machines that learn and have already started their transformation journey, the teach themselves to enhance eff iciency, predict failures, oil and gas industry has just started implementing and manage assets by exception. This avoids error-prone Industry 4.0 technologies. Early results indicate that human judgment and thus provides proactive well it has introduced eff iciencies in accessibility and maintenance rather than reactive well repairs. computing, and has allowed operators to better When the components behind Industry 4.0 are exploit their most valuable asset: their data. applied to the management of oil and gas production Four components comprise Industry 4.0. First, the performance, Weatherford refers to it as Production 4.0. Internet of Things (IoT) links groups of physical devices so they can communicate, and allows remote monitoring Creating Production 4.0 technology – and control. This increases access to data, broadens the software scope of viewable data, and helps to drive systematic A component of Production 4.0 technology that has eff iciencies. proven highly useful to oil and gas operators is the Second, cloud computing – using a network of Weatherford ForeSite production-optimisation and remote, Internet-hosted servers to store and manage CygNet SCADA soft ware. To date, these platforms data in a secure environment – enables users to access monitor and optimise 460 000 wells around the world data from anywhere and on any desktop, tablet, or daily, monitor 125 000 miles of oil and gas pipeline, and mobile device while reducing technology infrastructure manage 30 billion data updates every day. and the associated installation, maintenance, and ForeSite soft ware acts as a field-wide intelligence support costs. Companies can choose to use the public platform with the ultimate goal of optimising the cloud or a private, internal cloud. This helps users to eff iciency of production, maximising production volume, connect with data in a fast, direct, and meaningful way, increasing the run life of equipment, extending the life which is especially helpful for industries – such as oil and of assets, and making production as profitable and gas – that generate large volumes of data over several economically viable as possible. years. Currently, the platform’s nodal-analysis engine is Third, edge computing connects intelligent devices to the only technology capable of monitoring all forms of current and historical data so that autonomous decisions artificial lift . The Everitt-Jennings algorithm provides load can be made where they matter most – at the wellsite. computations at multiple points along the rod string for In the oil and gas industry, this means that lower-level, reciprocating rod lift , and – in combination with the Gibbs day-to-day decision making can be transferred to method – is the only platform capable of computing autonomous computers, which frees personnel to focus the downhole dynamometer card in two diff erent on higher-priority projects and tasks while reducing ways. In this fashion, asset performance is continuously overall staff ing needs at remote wellsites. monitored on a remote and automated basis. Fourth, advanced analytics brings the concepts of IoT, The information is then displayed in an intuitive cloud computing, and edge computing together to create and visual interface – in either a map or dashboard an interconnected, intelligent ecosystem that enables mechanism – that allows for real time performance operators to glean meaningful, actionable insight from analysis, the diagnosis of potential performance data. Letting operators see entire enterprises by function, problems, the identification of opportunities for

| 31 operational improvements, and more informed decision making. instant notifications, provides optimisation models on the Edge, Currently, the ForeSite soft ware platform is the sole provider of and enables autonomous control. In other words, it incorporates all enterprise-level optimisation for all forms of artificial lift , naturally the components of Industry 4.0 into one product – ForeSite Edge. flowing wells, pipelines, and surface facilities around the world. Using technology on the Edge, operators can gather both Using artificial intelligence combined with machine learning and historical-trend and real time production data from instruments physics-based models, the platform is designed to help predict failure and sensors across the asset. With a capacity to access years of by lift component. This capability – currently available for rod lift and sub-second, real time sensor data from the wellsite, Production ESP (electric submersible pump)-lift ed wells – enables operators to 4.0 systems, in future, can then use a suite of comprehensive pro-actively dispatch maintenance crews when needed to reduce calculation and modelling engines – including physics-based well downtime and associated production losses. models – to optimise production. Users can even import models Operational realities can restrict the time and resources from third-party technologies. available to install and support on-site solutions. A low barrier to These Edge systems also deliver instant, intelligent IoT-based implementation makes cloud-based soft ware platforms simple data notifications. For example, operators can be alerted to install, maintain, and use. The ForeSite soft ware platform is a immediately when sensors detect variances in performance or web-based system that is reliably hosted with Google Cloud or installed trends, failures or imbalances in equipment, when slugging occurs on premise. Users have complete ownership and control of their data, in wells, or when operating parameters pass critical limits. Alerts and can access data on the go, from anywhere. can be sent to any device, upon which users can respond and take Separation is provided between process controls and the corrective action in real time. business network. Fully compliant with security best practices, all Further, Edge platforms today can deliver predictive analytics data monitored through the soft ware platform is stored on the cloud. at the wellsite by monitoring the performance of a reciprocating Another major benefit is system elasticity. With cloud computing, rod-lifted or ESP-lifted system. Edge systems can analyse artificial users can create a production ecosystem that is both scalable and lift performance and predict when the systems will fail. flexible. As enterprises expand in well count or asset base, cross This IoT-based controller also makes daily operational geographical borders, or increase in complexity, cloud solutions let decisions and autonomously optimises production using users easily capitalise on business opportunities without incurring enterprise-wide data and the insight gleaned from modelling and additional costs. analysis on the Edge. As an example, one common problem that the controller can help to resolve is managing idle time for rod Creating Production 4.0 technology – pumps. The system dynamically manages idle time to eliminate next-generation automation the extreme scenarios of over-pumping, which causes equipment Pairing this soft ware platform with Cloud computing, IoT-enabled failure, or under-pumping, which in turn leaves valuable communication, and next-generation automation delivers hydrocarbons behind in the well. The ForeSite Edge device Production 4.0 at the wellsite, or ‘on the Edge’. This combination integrates the autonomous controller, optimisation software and can acquire and store a stream of high-frequency data at the IoT gateway. Alternately, the device can also upgrade any legacy wellsite, off ers secure communication in the form of IoT-based controller – meaning operators can enjoy the benefits without having to change their existing controller. The overarching advantage is that data collection and lower-level daily operational tasks that improve production outcomes are placed on autopilot.

Conclusion The oil and gas industry is typically slow to adopt next-generation digital technologies in the upstream production space. But there are many compelling reasons for operators to harness the power of Production 4.0. Most importantly, these technologies off er the potential to improve oilfield productivity significantly – producing more barrels in a safer, less risky manner while reducing costs. The advantages of implementing Production 4.0 technologies extend far beyond advancing oilfield operations. The transition to these newer technologies will help operators to fill gaps in the workforce, especially aft er the industry has experienced a series of economic downturns. There is an opportunity to discover new talent and create a workforce that strikes the right balance between technical and technological brainpower. Although traditional oil and gas disciplines such as engineering are and will remain critically important, the industry also needs expertise in digital operations, soft ware engineering, and data science. Digital technologies will also play a more varied role in the future of the oil and gas industry. With functionalities and Figure 1. Available on any platform, the ForeSite now provides capabilities that are in no way limited to the production phase, predictive failure analytics for ESP systems and complete optimisation operators can leverage these technologies to improve R&D and capabilities for plunger-lift ed wells. ForeSite is now edge-computing manufacturing, for example. This is the way of the future, and will ready, paving the way for the next-generation automation system. help to drive meaningful results for operators.

32 | Oilfield Technology March 2019 TThinkinghinking ooutsideutside tthehe boxbox

Andrew Poerschke, Teddy Mohle ven aft er all of the prep work is finished – surveys completed, seismology reports assessed, funding secured, permits and Paul Ryza, Apergy, discuss a new Eprocured, contracts signed, wellbores drilled, production approach to implementing artificial gas equipment installed, product recovery initiated – there is still no surefire way for oilfield exploration and production companies to lift designed to improve production in confidently know just how much recoverable oil and gas their wells will declining wells. produce and how long they will remain productive.

| 33 There is a simple reason for that: no two wells, even if they are located mere yards from each other, possess the same production and life-cycle characteristics. While this uncertainty can be frustrating for oilfield operators who need to show their investors with some level of accuracy what their capital investment is actually buying them, it does create some opportunities. Namely, the opportunity for oilfield engineers to employ some outside-the-box (or wellbore) thinking when trying to identify ways to flatten each individual well’s inevitable decline curve, which will result in more predictable production rates and higher monetary returns over a longer period of time.

Surveying the field A US-based energy company purchased acreage in Texas’ Permian Basin – the largest petroleum-producing basin in the country Figure 1. Well 1. – specifically, Pecos County, in the Southern Delaware Basin’s Wolfcamp A and Wolfcamp B formations. Most of the company’s drilling locations there are horizontally fractured wells with depths ranging between 9500 and 10 500 ft with flowing bottom-hole pressures (FBHP) of anywhere from 5000 - 6000 psi. On average, each well has 50 fraccing stages and requires 2250 - 2500 lbs of sand/ft and 60 - 80 bbls of water/ft . The energy company’s objective was to create an economically viable production trend for each individual well, knowing that the wells could produce from anywhere between 20 and 40 years, and also realising that it costs money to abandon an underperforming or played-out well. It is an inescapable fact of oilfield life that as soon as the well begins producing on the first day its decline phase begins. That is why the operator, as mentioned, will incorporate any means necessary to make the decline curve as flat and long-lasting as possible, which will help optimise the production company’s return on investment. Figure 2. Well 2. Again, while acknowledging that each well is unique, the wells in this formation generally have strong bottom-hole pressures, but fail to flow naturally for an extended period of time in this part of the basin. This means that they will require some form of artificial lift earlier in their operational window in order to keep them flowing. For example, the characteristics of Southern Delaware wells are such that they may only flow for 90 to 120 days before needing artificial lift , while wells that appear similar and are located just a few miles away may flow for more than two years before requiring intervention. Over the years, the default artificial lift system that has been deemed most eff ective is one that features an electrical submersible pump (ESP) installed in the well. However, in the Southern Delaware Basin, this approach could be problematic for three main reasons: Ì The remote areas of West Texas that are home to the Permian Basin do not always have access to reliable electricity. Figure 3. Well 3. h If power is not readily available in all areas of the basin, building a power grid can cost millions of dollars. Ì If an operator is set on using alternative high-volume lifts, a natural gas generator that can convert natural gas into electricity can be rented, but this would add significant cost to the bottom line of the operator’s lease operating expenses (LOE). Ì Other forms of artificial lift may have a high upfront cost, as much as 10 to 20 times more than a set of gas lift valves.

Realising that using other forms of high-volume lift can be cost-prohibitive, for a possible solution, the producer reached out to Apergy, a provider of technologies to help oil and gas production companies optimise their returns safely and eff iciently. Their main request was a challenging one: get as much oil and natural gas out of the well as possible in the first 90 days of operation, while reducing the Figure 4. Well 4. well’s LOE over its production life cycle.

34 | Oilfield Technology March 2019 Seeing is believing The client was not averse to using alternative lift s, no matter the cost, if reaching the goal of maximised rates could be realised, but Apergy’s oilfield engineers knew there had to be a more cost-eff ective way to tackle the problem. What they eventually developed was a four-pronged approach to introducing gas lift to a series of 10 Wolfcamp A and B wells. The trial involved introducing to the wells, at four specific points during their operational lifetimes, a gas lift system that featured annular gas injection: Ì Option A: well flows for 90 days before annular gas lift is installed. Ì Option B: well flows for 15 - 45 days before annular gas lift is installed. Ì Option C: annular gas lift is installed on the first day the well begins flowing. Ì Option D: annular gas lift is installed on the first day the well begins Figure 5. Well 5. flowing, while injecting gas in the first few days of producing. The first two options did not really represent a radical departure from accepted norms. Options C and D, on the other hand, are solutions that very few, if any, production companies will consciously choose to implement. Ten individual wells were tested: one well with Option A, the next three with Option B, three with Option C and the final three with Option D.

Well 1 Well 1 began producing in early February 2017, but by the end of April was beginning to experience daily oil and natural gas production declines, though water-recovery rates had remained steady. Staying on the existing course likely meant an early death for the well, but as soon as the annular gas lift was installed at the 90 day mark, the production curve bumped up and remained steady, save for some small peaks and valleys, through June of 2018. Figure 6. Well 6.

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worldpipelines.com/integrity Wells 2 - 4 Well No. 2 was a similar story to Well No. 1: strong early production that had already begun to taper off before the 90 day mark, when annular gas lift was installed, which stabilised production at a rate that remained relatively steady. Annular gas lift valves were installed aft er only 15 to 45 days of operation. The result was a much more gradual decline in production rates over the following months of operation. In fact, the wells’ returns beat the engineer’s forecast by such a significant margin that they were used as an example for investors that illustrated how their return on investment could improve as a result of this well setup.

Wells 5 - 7 These were the results that the engineers had been anxious to see since the setup – the annular gas lift application deployed from the first Figure 7. Well 7. day of the wells’ operation was departure from accepted operational norms. All three wells began operating in 2018 and the results have been similar for all of them – strong production rates from day one that have continued with only small valleys experienced (this is attributable to some operational anomaly like a compressor failure or other maintenance issue). If there has been one standout performer among the four, it has been Well 7, which showed an absolutely negligible decline curve over its first three months of operation.

Wells 8 - 10 The last wells had annular gas lift valves installed with injected gas within the first few days that the well began flowing. Based on the significant return, negligible decline curve, and optimised LOE, the operator decided to treat all of its future wells in the Southern Delaware Basin in this fashion from now on. Overall, there are several key takeaways that can be analysed when considering how these wells performed based on the four Figure 8. Well 8. diff erent gas lift setups: Ì Adding a velocity string during flowback reduced slugging and outproduced casing flow. Ì Switching from annular gas lift to conventional gas lift did not improve production at 2500 bpd total fluids. Ì When the injection gas was turned off after the first 90 days of injecting, the wells loaded up immediately. Ì Production results compared to other forms of high-volume lift were similar and, in some cases, surpassed due to lack of downtime, but at a fraction of the cost.

Conclusion In a complex industry like oil and gas exploration and production, which features so many diff erent well-to-well variables that need to be considered when determining the best way to produce the well, there Figure 9. Well 9. simply can be no one-size-fits-all solution. However, that randomness can be an advantage for oilfield operators who are willing to consider non-traditional ways to get the oil and gas to the well’s surface. While many companies continue to rely on alternative high-volume lift s, or waiting to introduce artificial lift systems until the last possible moment before the well loads up, the companies that retain an open mind are finding that there are some noteworthy alternatives available. Based on the from-the-field empirical information noted above – not from just one isolated well, but from 10 notable well sites in the most fertile oil and gas reservoir in the US – one of the more successful next-generation approaches can be to intentionally install an artificial lift system earlier in the well’s life, up to and including the first day of operation. This is proving to be another way to skin the proverbial cat, with the results so far Figure 10. Well 10. speaking for themselves.

36 | Oilfield Technology March 2019 Keeping things crystal clear

Simon Larson, Siemens, Sheng Kun Sun, CNPC, and Xiao Ming Sun, Liaohe Petro Engineering Company, review water treatment measures designed to comply with China’s tough new treatment standards.

he CNPC Liaohe Oilfield Shuguang Oil Production Plant – located petrochemical industries. The new standards established some of the some 560 km east-northeast of Beijing – used conventional most stringent eff luent quality limits in the world. To meet the standards, T oil-removal techniques to treat contaminated water generated the DI designed a robust, four-train activated sludge treatment system during oil extraction before reinjecting the produced water into the oilfield to help remove water soluble organics (WSOs) followed by multimedia reservoir. Over time, though, the reservoir had become nearly saturated filtration. and could no longer receive reinjected water. The Design Institute for CNPC Yet the produced water generated by the Shuguang plant proved Liaohe Oilfield Shuguang (DI), therefore, developed a plan to implement diff icult to treat. The water chemistry contains large amounts of additional produced water treatment measures and discharge the newly WSOs (measured as chemical oxygen demand or COD) resistant to treated water into the Raoyang River, a tributary of the Liao River. biological treatment. Despite the best eff orts of the new wastewater In May 2015, however, China’s Ministry of Environmental plant’s operating teams, the new system could not reliably achieve the Protection implemented revised discharge limits for the refinery and discharge standard of 50 mg/l COD. The DI approached Siemens Water

| 37 Solutions for help in designing modifications to the treatment plant that would produce eff luent quality consistently meeting the extremely challenging COD limit.

Solutions start with good science Table 1 presents the produced water feed characteristics and final treated eff luent target concentrations required for discharge to the Raoyang River. Siemens’ team of field services personnel conducted a bench-scale proof-of-concept study using final eff luent samples from the wastewater treatment plant. Additionally, samples of the Liaohe produced water and treated eff luent were shipped to Siemens Water Solutions headquarters in Wisconsin, USA, to validate the work performed in the field and develop the upgrade plan. The headquarters of Siemens Water Solutions Figure 1. Upgraded Shuguang Oil Production Plant PACT® treatment hosts a complete 1000 m2 pilot testing plant supported by more than facility. 500 m2 of analytical testing laboratories, making it suitable for the analysis of industrial, municipal, and even hazardous wastewaters, Table 1. Shuguang Wastewater Treatment Plant Influent and waters, and sludges. Effluent Characteristics. Validation work consisted of bench-scale PACT treatability testing Item Unit Influent Required effluent and laboratory analyses to screen powdered activated carbon types and dose, as well as process modelling to determine the optimum COD mg/l ≤ 700 ≤ 50 configuration of process trains needed to achieve the required treatment BOD5 mg/l ≥ 140 ≤ 10 at the lowest possible cost. Based on the testing performed in the field and in validation Oil mg/l 10 ≤ 3 bench-scale testing results, Siemens recommended that the Shuguang Wastewater Treatment Plant be upgraded to a True 2-Stage (T2S) NH3-N mg/l ≤ 20 ≤ 8 PACT system. The existing 4-train activated sludge layout provided the TOC mg/l - ≤ 20 flexibility needed to easily convert the wastewater treatment system to a 2-Stage PACT process: three parallel trains of 1st Stage PACT followed by one train of 2nd Stage PACT. Capital improvements included the addition g( ) of a 2nd Stage Clarifier, powdered activated carbon storage and delivery, 1st Stage Effluent and diff used aeration upgrades. 2nd Stage Waste (WAS) 2nd Stage Recycle (RAS) Good science is also good business Sand PAC Filter The treatability study not only proved that the Siemens PACT technology 2nd Stage 2nd Stage PACT Clarifier Treated Effluent could meet these stringent discharge standards, but it also provided

1st Stage Clarifier supporting data used by Siemens to off er a process performance

Deoiled Wastewater guarantee for the upgrade. 1st Stage PACT Lift Station Siemens drew on its experience gained from more than 100 PACT

1st Stage Clarifier systems supplied globally to develop a retrofit plan that economically incorporated PACT technology using existing Shuguang Wastewater Waste (WAS) Sludge 1st Stage Recycle (RAS) to Dewatering Treatment Plant infrastructure and equipment.

Figure 2. Liaohe PACT® True 2 Stage (T2S). Treatment advantages Powdered activated carbon off ers customers several advantages for 250 1500 the treatment of eff luent water when compared with granular activated Effluent COD Limit carbon beds: 1 Stage Clarifier CODave 2 Stage Clarifier CODave Ì First, powdered activated carbon costs less than granulated carbon. 200 1200 PACT Feed CODh Ì Second, because it is powdered instead of granulated, it offers more active surface area per equivalent mass than granules do. 150 900 Ì Third, powdered carbon interacts more efficiently and thoroughly

PACT feed COD design = 700 mg/L with treated water inside the tank, and the required dose can be tailored to the precise discharge requirement. 100 600 Stage Clarifier Effluent COD, mg/L PACT Feed CODh, mg/L nd How the system works

and 2 50 300 st 1 Ì Powdered activated carbon solids flow counter-current to the wastewater flow. Virgin carbon dose is first applied to the 2nd Stage nd 0 0 PACT; waste carbon solids from the 2 Stage are transported to the 8/23/2017 10/12/2017 12/1/2017 1/20/2018 3/11/2018 st Sample Date 1 Stage PACT, where additional COD adsorption occurs in equilibrium with the higher concentration of 1st Stage recalcitrant COD (Figure 2). Figure 3. Liaohe Oilfield Shuguang PACT T2S Wastewater Treatment Ì De-oiled wastewater enters the 1st Stage PACT, consisting of Plant performance (note: trend lines represent 5 day moving averages). three parallel aeration tanks followed by two parallel clarifiers.

38 | Oilfield Technology March 2019 Return activated sludge recycle maintains the total mixed liquor the characteristics of the produced water are available as needed – as an suspended solids (MLSS) at 12 000 mg/l concentration. A portion of additional service – for the life of the system. this recycle is wasted from the process and dewatered for disposal. 1st Stage Clarifier effluent discharges to the lift station from where Conclusion nd nd it is pumped to the inlet of the 2 Stage PACT. The 2 Stage PACT, The DI was challenged to meet China’s new petrochemical industry consisting of a single set of aeration tank and clarifier, receives virgin standards for discharge to surface waters. Siemens Water Solutions carbon dosing, resulting in maximum recalcitrant COD removal. collaborated with the DI to develop a solution path that maximised the use Return activated sludge recycle maintains the MLSS concentration at 15 000 mg/l; a portion of this recycle is wasted to the 1st Stage PACT. of existing infrastructure and equipment by implementing Siemens PACT The wastewater exits the 2nd Stage Aeration Tanks into the 2nd Stage T2S. A treatability study conducted in Siemens’ analytical laboratories – Clarifier where the final solid/liquid separation occurs. using actual produced water from the Liaohe Shuguang Oilfield – proved Ì 2nd Stage Clarifier effluent discharges to existing pressure sand filters that a 2-stage, powdered activated carbon treatment solution would meet and discharges to the Raoyang River. the strict new standards. Data generated during the study enabled both performance and operating carbon cost guarantees to be provided to the Performance results DI, minimising future operating and financial risks to the client. Eff luent COD performance results following the PACT T2S upgrade are shown in Figure 3. Despite the variability that occurs in feed COD – oft en well above the design level of 700 mg/l – the PACT T2S has been able to achieve consistent compliance with the 50 mg/l COD limit. Even with a spike of feed COD nearly 200% of design concentration, the PACT T2S eff luent maintained performance with 95% COD removal and eff luent returning to normal within days of the event.

Operational support Siemens Water Solutions’ approach to treating this produced water challenge included complete sales, installation guidance, training and service support. The most economical programme was sought, which in the DI’s case included retrofitting and adapting existing equipment to a PACT process. Training CNPC’s staff to maintain successful operations at full flow rates – meeting guaranteed performance targets on an ongoing basis – was an integral part of Siemens’ startup process. Additional services for support during emergencies, or changes in eff luent specifications, or in Figure 4. PACT® T2S™ eff luent.

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www.oilfi eldtechnology.com/app WELL CONTROL Oilfield Technology invited experts from CUDD Well Control, Halliburton, RESMAN, and Wild Well Control to share their knowledge on a variety of WELL CONTROL topics. Read on for insights from: CUDD Well Control JOHN FU is a well control engineer who provides onsite and remote consultation for well control related issues such as kick circulations, blowouts and well fi res for oil and gas clients globally. John is a licensed Professional Engineer and earned his BS in Petroleum Engineering from the University of Texas. ZOHAIR MEMON is a petroleum engineer from the University of Houston. He develops solutions for eliminating downtime, critical path failures, and preventing well control incidents. HALLIBURTON

ANDY CUTHBERT is a post-graduate of the University of London with 34 years of industry experience. He has been involved in projects of ever-increasing complexity with the introduction and coordination of new technology and pioneering innovations, such as multilateral completion technology, rotary steerable systems and a game-changing air-mobile subsea capping stack system. Andy holds eight patents with over 10 still pending; he has authored or co-authored almost 30 technical papers for the SPE, IADC, ASME, OTC and the PMI on directional drilling, multilateral technology, contingency well control measures and various aspects of project management, presenting to the oil and gas community all over the world.

RESMAN AS MARTIN V. BENNETZEN is Head of Well and Reservoir Surveillance and Digitalisation at RESMAN AS. Martin earned his MSc and PhD degrees from the University of Southern Denmark and in 2010 received the ‘Elite Research Award’ from the Danish Ministry of Science and Technology. Before joining RESMAN as R&D Manager in 2018, Martin worked in a number of senior reservoir engineer positions in Denmark and the Middle East for Maersk. WILD WELL CONTROL

STEVE L. RICHERT is manager of instructor and course development at Wild Well Control in Houston, where he leads education and development for well control instructors, including knowledge progression, certifi cation, and course and instructional materials development. He has 20 years of industry experience, coupled with a 20 year adult education background.

Detecting and dealing with kicks Fluid (NADF), the solubility of gas complicates kick detection, as does circulating out remnant gas from the horizontal section. Well control modelling for deviated and horizontal wells has been Halliburton – Andy Cuthbert applied since the early 1990s and consideration of multiphase Diff erences in conventional and unconventional well flow, for the section of well aff ected by the presence of a gas kick, construction introduce variances for response to well is essential to avoid making improper decisions. A comparison control incidents. Most unconventional wells are drilled with between the pressure at the casing shoe and casing pressure for long lateral sections; the behaviour of a gas kick circulated from diff erent vertical and horizontal well scenarios concludes that a the lateral section of an unconventional well is diff erent from a kick taken closer to the casing shoe resulted in higher pit gain, conventional well, but the well control fundamentals are the same. gas discharge rate, and casing pressure due to the well profile and As most lateral sections are drilled with Non-Aqueous Drilling drillstring pressure profile.

| 41 It is generally believed that low reservoir permeability has make sure that there are robust emergency response plans in place reduced well control and well integrity risks and consequences should an event occur. These plans will detail how operational personnel to an acceptable level, within a given risk tolerance. However, data are expected to react to various levels during an incident escalation. indicates that occurrences of undetected kicks are increasing. Shale This should be part of a comprehensive well control programme which formations with microfractures are well known for the ballooning eff ect, acknowledges specific well risks. Oft en, this is not correctly done and however, fingerprinting techniques and the use of Horner plots have the same plan is used for operations on wells that do not flow unless made it possible to distinguish between a kick and formation ballooning. stimulated to HPHT and H2S wells. An expected minimum influx rate from the reservoir can be The response plans should at a minimum address what tertiary well complicated by the presence of natural fracture networks, leading to a control methods are available (with verification that they will succeed). higher than expected influx rate causing well control issues. It is possible This will include a capping plan and a relief well plan with a dynamic kill for a long lateral section to encounter two or more fracture networks analysis. with diff erent pressure regimes and without careful management, The dynamic kill analysis determines whether a kill is feasible, as a kick from one fracture and losses to another fracture could result well as what would be required to perform the kill. Recent advances in significant risk to the well. Fortunately, underbalanced drilling in dynamic kill modelling have shown techniques which can provide a and managed pressure drilling systems can detect the unexpected more accurate result, determining that some wells may be killed which influxes and adjust the operational parameters for safe drilling. Greater were previously thought to be ‘un-killable’. This analysis, while more understanding of unconventional and horizontal well design, and accurate, can be quite inexpensive and grants assurance regarding associated well control complications, leads to better evaluation of risks response capabilities and requirements. for a safer drilling operation. The capping plan will determine from where equipment can be brought, how it will be deployed, and any logistical concerns. This is true for both off shore and onshore wells. WILD WELL CONTROL – STEVE L. RICHERT One of the greatest risks related to drilling and managing oil Reservoir monitoring and gas wells is undetected and misunderstood hydrocarbon influxes, which are commonly referred to as kicks in the industry. Large hydrocarbon influxes can create significant problems: they RESMAN AS – MARTIN V. BENNETZEN increase well control non-productive time (NPT) and they can potentially Chemical tracers’ zero risk and longevity of up to 10 years can damage a wellbore. If unmitigated, unrecognised and uncontrolled, be used for continuous well and reservoir monitoring. There they can eventually blow out at surface and cause equipment damage, are several ways in which chemical tracers can support operational destruction of the environment, and potentially, loss of human life. decision making from proactive well surveillance at each stage of the The solution to out-of-control kicks is to understand the signs at production lifecycle. surface that indicate a kick is developing downhole, and how to shut the Ì In the short-term, chemical tracers can lead to the identification well in before the kick becomes too large to manage. of production losses/gains (analysis of zone-specific drawdown Wild Well Control Training has developed a unique way to teach rig requirements for fluid-specific inflow operation) and identification crews how to detect and control influxes by utilising a mobile Rig Crew of zones to be targeted for selective solvent injection (e.g. in the case of asphaltene deposition) to improve the productivity index of Training classroom. The instructor can facilitate a dialogue to help crew that zone. members learn about well control in a focused, relatable discussion In the mid-term, chemical tracers can contribute to an improved with immediate application and implementable results upon returning Ì productivity index and reduced lifting cost by identification of zones to the rig. Rig crews will learn about kick detection and control on their to be targeted for selective water shut-off, selective stimulation rig, with their crew, and in the context of their company policies and and/or re-stimulation and other targeted well interventions. procedures. From rig to rig, and crew to crew, drilling hands are taught Ì And in the long-term, chemical tracers can result in improved the key surface kick indicators and how to shut the well in. Education at forecasting, reservoir development planning and reduced the rigsite allows the application of kick detection to be applied directly uncertainty from refined and better predictive reservoir models due in the context of the current drilling operation. to reduced subsurface uncertainty. Improved production can also In addition to kick detection, false kick signs, such as ballooning, be achieved by identification of zones to be targeted for future water are taught in the mobile classroom. Too many crews assume that a injection or future infill drilling. well is ballooning when it is actually kicking. A portion of the course One example of how chemical tracers are eff ective in supporting well shows crews how to analyse ballooning so that they can understand the monitoring can be seen through the analysis of tracer profile changes diff erence between ballooning and kicking. during a multi-rate test and correlation with production changes. When hydrocarbon influxes are identified quickly, the possibility This approach was used in a horizontal well in which five oil and for a blow out at surface is reduced. The likelihood of loss of life, water tracer systems were installed (OS-1 to -5 and WS-1 to -5). By environmental destruction and equipment damage decreases cross-correlating choke settings (or equivalent production rates) and by significantly through well control training. Understanding and detecting processing well events following intentional step-rate changes, a zonal hydrocarbon influxes reduces the risk of company financial loss due to production matrix for both oil and water was established. In this way, the NPT and ‘out of control’ events. drawdown-threshold to sustain oil inflow in all five zones as well as the threshold at which water production starts/stops is known and digitised. Managing blowouts The simple multi-rate test can: i) in the short-term provide details on the consequences of changing tubing head pressure (THP)/bottom hole pressure (BHP) where zones 1 and 2 require the highest drawdown CUDD WELL CONTROL – JOHN FU to sustain flow; ii) in the mid-term identify zone 5 as a potential water It has been said that the best way to handle a blowout is to shut-off target, as most water comes from that zone; and iii) in the make sure it does not happen, and right behind that is to long-term lead to targeted waterflooding where oil production

42 | OilfieldOilfieldd TecTTechnologychnoh lloooggy MMaMarcharch 201920200119 could potentially be sustained by a water injector to target zones 1 and 2, strings can be sheared and sealed during an emergency well but not in zone 5 as high water production occurs in this zone. control event. A comprehensive inspection of the equipment The result of this enhanced reservoir monitoring through chemical setup is performed to verify that the correct BOP configuration, rams, tracers is reduced subsurface uncertainty and a proactive well and and models are used and mimic the field setup. Testing is then carried reservoir management production strategy. out according to the BSEE Shear Verification Best Practices. Shear calculations are then performed to eliminate any uncertainty in function Subsea challenges and verify equipment limitations. Another method can be field audits of well control equipment to verify that current inspection and maintenance practices are being Halliburton – Andy Cuthbert followed in the field. This should leverage knowledge from industry Subsea challenges vary in terms of well control, but over time publications such as API ST53 along with past lessons learned. Field more robust source-control planning has been conducted. audits verify well control equipment installation, current working Relief well contingency planning has been the mainstay of well control condition, and equipment rating feasibility. Many gaps are identified response for years, but a number of considerations should be taken during audits such as inadequately rated equipment selection, incorrect into account, not least the veracity of the directional surveys for the equipment installation, and heavy equipment wear that compromises target well and any off set wells in the vicinity, including specific survey integrity. This helps to ensure reliable equipment performance. tool uncertainty values. Deciding on the best seabed surface location for the relief well involves an examination of metocean data, including Chemical tracer technologies bathometry maps to identify sea floor obstructions, current speed and direction, and also wind rose information for the prevailing wind direction. RESMAN AS – MARTIN V. BENNETZEN Subsea-capping stacks have been designed to shut-in an unabated The last few years have seen the growth of digitalisation in subsea source control incident at surface. In general, a most credible the oil and gas industry with diff erent elements of the well, worst-case scenario should be planned for, to include worst-case compressors, pipelines and terminals being fed into an integrated asset discharge, reservoir oil/gas ratio (GOR), and subsea geometry at the model to support operational decisions and optimise hydrocarbon exit point (wellhead). A low GOR will exit at low velocity but create production. more oil eff luent, whereas a high GOR will tend to exit at rates reaching Permanently installed chemical tracer systems represent a wireless Mach 1. Water depth is the primary challenge with respect to capping and risk-free technology that provides zonal resolution and enhances the capability. The deeper the water the less complex the capping stack digitising of the wellbore. deployment; the plume emanating from the well is likely to be swept RESMAN has developed a chemical tracer system where tracers away down-current, allowing the capping stack to be lowered from are embedded in a polymetric matrix in the form of polymer rods and one surface vessel stationed vertically above the well. Conversely, the installed in completion components, such as sand screens, ICD screens shallower the water depth the more complex the deployment; a shallow and pup joints, in specific zones of the well. In conjunction with trend water plume invariably reaches the sea surface, creating a gas-cut profiling analysis, the chemical tracer technology can digitise the environment in the immediate vicinity, giving rise to a water ‘boil’ and wellbore to enable zone-specific well event processing, exception-based emitting high levels of inflammable gases, making a close approach well surveillance and continuous monitoring for optimised oil extremely hazardous. Furthermore, since a vertical deployment is production and de-risked reservoir management decisions. rendered impossible, the capping stack has to be deployed using an With chemical tracers, water- and oil-sensitive tracer systems are off set technique that requires two vessels. designed to specifically release from the polymetric matrix when in Fortunately, well-specific detailed engineering analyses for the contact with the target fluid. Aft er the tracers are released, carrying deployment and landing of a capping stack from a floating vessel information about their specific zones, they flow to sampling points and have been developed, and include a high-fidelity computational fluid are detected even in ultra-low (part-per-trillion, ppt) concentrations. dynamics plume force flowfield analysis to understand the forces acting Correlating tracer profiles to other geoscience and production data on the stack and the capability of the equipment required for landing a enables well event identification. capping stack in any environment. By providing zonal resolution, inflow tracers increase the resolution of the digital oilfield model. Well events – such as loss of inflow, water Inspection and maintenance breakthrough and drawdown-dependent fluid inflow behaviour – can be assessed using inflow tracers. This way of digitising the wellbore unlocks zone-specific digital data-streams, enables improved well and reservoir CUDD WELL CONTROL – ZOHAIR MEMON surveillance, and supports short-, mid- and long-term operational Inspection and maintenance practices play a critical role in decisions to increase the net present value of the asset. ensuring the integrity of well control equipment such as the BOP, which is the final barrier in protecting personnel and preventing Tertiary well control an uncontrolled release of hydrocarbons. One part of this is having a comprehensive inspection and maintenance programme, which provides operators with peace of mind and ensures that the equipment CUDD WELL CONTROL – JOHN FU operates when needed every time. Multiple complex issues arise during Cudd Well Control (CWC) specialises in the blowout and drilling, completions, and production operations and reinforcing firefighting aspects of well control, but many may not be as equipment barriers prevents these issues from escalating to well control familiar with the special services side of well control response. These events and blowouts. services are innovative solutions to many challenging scenarios that One inspection/verification method is shear verification are actually commonly encountered in the oil and gas industry. Hot testing. This verifies that the planned casing and tubing tapping, gate valve drill-outs, and cryogenic freeze operations are

MarchMMaaarrchc 20192010119 OilOiOilfieldilffifieeld TecTechnologyhnonolologogy | 4343 routinely performed to resolve situations where no other choke pressure, pressure at the casing shoe, and maximum gas flow viable solution exists. rate. The type of kill fluid, either water-based mud (WBM) or oil-based mud (OBM) has to be taken into consideration. In terms of volume Hot tapping influx taken, maximum choke pressure, pressure at the casing shoe, Hot tapping is a method of gaining access to line pipe, tubing, casing, and maximum gas flow rate, WBM is considered to be the worst-case drillpipe, pipeline, bull plugs or blind flanges where there is trapped scenario. The time to shut-in the well becomes more critical because pressure and no method of relieving that pressure. It is oft en used dissolved gas will come out of solution nearer the surface, compared to gain access to a wellbore when wellhead valves are rendered to OBM. inoperable. A pressure sealing saddle and valve is typically installed During the dynamic kill operation, kill fluid is pumped down the on the tubular, providing the options of bleeding off or pumping into annulus of the relief well through a dedicated dynamic kill spool. the tapped hole. To tap a blind flange or bull plug, a threaded collar Losses will occur as the kill fluid u-tubes to the target well. Once the is welded to allow the hot tap unit to be installed. This operation is influx is stopped, the pumps are slowed to prevent breaking down also frequently performed when pulling tubing with severe paraff in the exposed formations. During the operation, the drillstring is used plugging, where breaking connections will expose the rig crew to monitor pressure at the interception depth. The conventional to trapped pressures. CWC’s hot tapping equipment is a pressure method is adding standpipe pressure at shut-in condition to the balanced unit capable of drilling up to 15 000 psi as well as H2S hydrostatic pressure of fluid in the drillstring. Other methodologies, environments. including pressure while drilling, should be evaluated in order to monitor the pressure at the interception depth in real time, to Freeze operations avoid exceeding the fracture pressure at the interception depth or Freezing is a technique used to form a temporary ice plug pressure other exposed weak zone, which may result in loss of well integrity, barrier within the ID of a tubular or the bore of a valve or BOP jeopardising the success of dynamic kill operations. while under pressure. Freezing allows for safe equipment repair The applied backpressure is a factor to be considered when or replacement above the ice plug. This is commonly used when employing managed pressure drilling (MPD); the limiting factor wireline has stranded at surface with the tools across the wireline has been the fluid and gas rate handling capability of the surface BOPs and frac valves, and there is no means to shut in the well. There equipment. Therefore, the scope of well control analyses for the MPD are two methods of forming these ice plugs, traditional dry ice freezes systems has been to determine the safe operating window in the and cryogenic nitrogen freezes. Traditionally, dry ice has been used presence of a controlled influx, using MPD to control the high-pressure on non-cylindrical items due to its ability to have a significant contact drilling near-balance (or higher than the collapse pressure) without area with larger and peculiar shaped items that copper tubing exceeding the minimum horizontal stress of the formation. cannot wrap. Cryogenic freezes using copper tubing are very eff ective on tubulars like tubing, casing, and drillpipe but have significant limitations when wrapping non-cylindrical items. Wild Well Control – STEVE L. RICHERT CWC’s new flexible stainless steel cryogenic hoses allow the Along with undetected hydrocarbon influxes (kicks), one advantages of a cryogenic freeze, such as faster rig up times, ease of the oil and gas industry’s greatest risks to company of maintaining and monitoring the plug, and fewer personnel reputation and revenue is a misunderstanding of proper well kill requirements, to carry over to both cylindrical and non-cylindrical procedures. items. All freezing processes are initiated by cleaning any grease or In 2015, Wild Well Training developed a unique approach to well hydrocarbons from the bore of the item that will be frozen with a control training to teach students not only how to ‘do’ well control, caustic solution. Then a viscous freeze medium is pumped across the but also how to ‘think about’ well control. freeze interval, which aids in preventing gas migration. Aft er a freeze In the classes, students are exposed to an influx in the well plug has formed, a positive and negative pressure test is performed through simulated well kicks. Wild Well’s courses teach students to check its integrity prior to performing any intervention work that, ‘when in doubt, shut the well in’. Curtailing NPT requires above the plug. Aft er the necessary repairs are completed, the plug knowledge that precedes action. The course of action taken by is allowed to thaw naturally, and normal operations can commence. crews to shut-in and to kill the well is critical to lowering well For a freeze to be successful, there cannot be any flow through the control NPT. freeze interval, such as a leak. Additionally, the ability to pump Two diff erent shut-in methods are taught: soft shut-in and hard through the freeze interval is critical, as the caustic solution and shut-in. The correct shut-in procedures are as follows: stop drilling, viscous freeze medium will need to be pumped across the area that position pipe, shutdown pumps, check for flow or unexplained pit will be frozen. gains, and shut the well in if the well is flowing or pit gains cannot be explained. Well kill procedures For soft shut-in, drilling commences with the choke partially open. Aft er the flow check procedure substantiates an influx, the choke line is opened (HCR), the BOP is closed, and the choke is Halliburton – Andy Cuthbert slowly closed. A systematic approach and careful coordination of several For hard shut-in, the choke remains closed during drilling. When specialised technical disciplines around well control an influx is confirmed the BOP is closed and the HCR/choke line is preparedness are key to planning well kill procedures. opened. Some recommend opening the HCR first on land rigs due A blowout scenario is calibrated to the highest expected to potential damage to equipment when the valve is opened with production rate and based on a worst-case credible discharge, pressure on only one side. derived from anticipated drill stem test and production analyses. Once the well is shut-in, for drilling, two basic well kill The dynamic kill analysis provides the weight of the kill fluid, the rate procedures exist: the ‘driller’s method’ and the ‘wait & weight it should be pumped with expected pumping pressure, maximum method’.

44 | OilfieldOilfieldd TecTTechnologychnoh lloooggy MMaMarcharch 201920200119 The driller’s method removes the kick first, then circulates kill experience mental gridlock, known as cognitive overload, fluid throughout the well with two circulations. This method works which slows them down and makes them more prone to best for lateral or deviated wells. The wait & weight method kills the errors when they attempt to combine these new skills during an well while circulating kill fluid, both in one circulation. This works actual event. The task is to train personnel to make judgement calls best for long open holes in the vertical section of the well, but is not when many pieces of information are arriving simultaneously. recommended for horizontal wells. ‘Normalisation of deviance’, a term coined from the Kick identification as well as an understanding of proper well kill NASA Challenger incident, refers to how human behaviours can methodology should assist with mitigating NPT, and will help protect drift to become riskier over time; the change happens slowly, a company’s reputation and revenue. until eventually it becomes the normal way of working (Group Bias). Taking this into consideration, a change is required Training & certification when running well control education and training programmes to improve on the traditional curriculum by constructing it differently, stress-testing by more complex ideas, questions, Wild Well Control – STEVE L. RICHERT or problems in a scenario-based environment. Even at the What value does well control training deliver and simplest level of required knowledge acquisition – the old how does it relate to well control certification? fashioned ‘chalk and talk’ – where a trainer interacts with In Wild Well Training courses, crews learn how to recognise the audience in one direction with an array of slides, the influxes early and keep kicks small, which lowers the time content of which is the same as the words spoken, is of little it takes to resolve a situation. Well control training can help long term value. When subjected to this kind of training, the increase profits by lowering NPT and strengthening employee audience may be stimulated by the presentation, engaged by professionalism. the graphics, and motivated by the speaker, but the chance of Early perception of kicks and keeping them small helps them remembering what is being taught is very slight. Building mitigate NPT. Large well control events, even if appropriately scenario-based training into learning programmes benefits a managed, can take time, which increases NPT. Understanding wide range of topics, including risk analysis, leadership, and kick recognition and resolution also results in professional coaching. It also raises awareness and allows learning and crew members. Skilled crews can improve a company’s image development professionals to fill in the gaps left by sequential in the marketplace and enhance future business with their modes of teaching, and developing the scenarios by immersing competency. the participants in real-life situations locks in knowledge and understanding. What is well control certification and how does it differ from well control training? Well control certification sets a minimum training standard. Cudd Well Control – John Fu The oil and gas industry recognises that a certified well control Well control practices are both the first and last barriers worker has met the minimum requirements of a particular to a catastrophic event. The first barrier comprises programme. robust understanding of well control risks when planning a well Too often, companies depend upon well control ‘certification and ensuring that well design, monitoring programmes and training’ as the only training that workers receive. Unfortunately, enhanced operational training and drills address all significant well control certification training does not fulfill the need for well control risks. The last barrier is operational personnel ongoing learning. Wild Well Control offers both certification reacting quickly and correctly. For conventional operations, this training and ongoing learning and review through its well mainly entails robust monitoring and a clear understanding of control classes, mobile crew training at the rig site, rig crew what anomalies may mean, when a well should be shut-in and assessments, and kick drills. The assessments reinforce how to do so. However, it also means properly diagnosing how training through exercises, and prepare crews to respond to to proceed after shut-in, and it is at this stage that some of the any well control issues or concerns that may arise. The use of costliest and most dangerous mistakes occur. repetitive techniques improves the crew’s reaction time to a well It has become an accepted fact that while well control control event. The assessment builds crew readiness through certification is necessary to ensure minimum knowledge, more onsite-customised drills for the entire crew at a fraction of the needs to be done to provide assurance that people will make cost of offsite training. correct decisions both in planning and during operations. It is often expressed that ‘training is too expensive because Operators are instituting comprehensive programmes such there is little return on investment’. Training can be costly, but as the Cudd Well Control Programme, which develops high it is inaccurate to say that there is no return on investment. reliability, learning organisations regarding well control. A Training improves a company’s profits by lowering NPT and comprehensive well control programme needs to be tailored to a improving employee professionalism, both of which directly company’s activities and well risk profiles. influence the bottom line. The process begins with making sure that company standards conform to industry requirements and best practices, as important requirements need to come to life in both design Halliburton – Andy Cuthbert and operational phases. Simple well control certification is Preparation removes the propensity for key personnel not sufficient, and procedural well control barriers need to be to behave in an ill-informed or irrational manner and tested regularly. Lastly, the loop needs to be closed so that any replaces indecision with positive and well-defined actions. identified gaps regarding operational knowledge, or information However, because individual skills needed for emergency learnt from events, are addressed. When utilised, this process response control are taught separately, employees oft en has led to a significant decrease in well control events.

MarchMMaaarrchc 20192010119 OilOiOilfieldilffifieeld TecTechnologyhnonolologogy | 4545 Michael MacMillan, C-Innovation, USA, discusses the benefits that a single-source ROV and vessel support services solution can deliver for subsea construction projects.

d h

e or more than a decade, oil and gas c t F projects in the Gulf of Mexico have been calling for increasingly complex ROV operations. In answer to this, C-Innovation’s (C-I) ROV capabilities are designed a a to provide a range of support to subsea construction projects, as well as drilling, intervention, maintenance and heavy lift assignments. The ability to respond to a client with a full solution,

r operating as a single point of contact, reduces the cost to the client and

o also reduces the risks by dealing with a single subcontractor. This ‘single source solution’ approach is particularly valuable in today’s spot market climate, in which operators are adopting a more

r turnkey approach to managing their business while at the same time g seeking more inclusive off erings at the same price structures. A single contractor can maintain a higher utilisation rate for its clients by joining services together and off ering complete packages to the end user, enabling projects to be completed more eff iciently than p

e ever before. As a member of the Edison Chouest Off shore group of companies (ECO), C-I has the ability to draw on integrated ROV and vessel

t support services. By partnering with other ECO companies to harness the resources of a large vessel fleet, shipyards, port facilities and logistics n p and communications services, C-I aims to off er a complete, economical solution to its clients, under one operating umbrella. With this large-scale, single solution approach, work scopes such as tree installations, hydrate n remediation, survey operations and inspection, maintenance, and repair (IMR), which used to take six months to a year to plan, can be An An A Integrated I Approach A

46 | achieved in three to four weeks. Engineering, design, project management Case study 5 along with execution and follow-up are all carried out internally, on C-I’s C-I performed a successful 19 day flowline hydrate remediation. vessels, port facilities and by C-I’s personnel. Remediation/removal of complete hydrate blockage and flushing of The following case studies describe the ways in which an integrated, flowline to satisfy government requirements for decommissioning one-stop-shop service capability can off er unique adaptability when was performed. The tieback well had already been de-completed and solving project challenges. the jumper removed. Access was through a high-flow hotstab port on a flooding cap installed on the PLET. The client engaged a third-party Case study 1 engineering firm to define and guide initial, novel methodology for C-I completed a flowline asphaltene remediation job for a large remediation of hydrate blockage, which proved unsuccessful. With international operator in the Mississippi Canyon area in the Gulf of Mexico. approval of the client, C-I’s own field-proven methodology for remediation The main objective was to clear a flowline of an extensive asphaltene began with good results. blockage, to satisfy the government’s decommissioning requirements. The Currently, C-I is working actively with clients to handle the full scope of C-I Subsea Projects Group provided project management, engineering, pumping, returns and well restart for well stimulation jobs such as these. off shore management, logistics and client relations/interface. The crew Once a safe and successful solution is defined, it will represent a significant and associated personnel ultimately achieved a task previously thought to change to the rig schedule-driven market to include job mobilisations be impossible: lift ing a pipeline off of the seabed and threading it through aboard suitable vessels of opportunity. the moonpool of a vessel and supporting it for weeks while a surface intervention was performed. The client is now sole-sourcing a phase 2 Case study 6 solution through C-I to continue to complete the work scope safely and C-I played a key role in a flowline decommissioning project, responsible without impact to the environment. for flushing and preparing 60 miles of pipeline for decommissioning. The project, located in the Mississippi Canyon area of the Gulf of Mexico, lasted Case study 2 for approximately two weeks, required two vessels with coiled tubing units C-I was called upon by a large international operating company in the and was gas lift ed using hot tap while flushing operations were executed. Gulf of Mexico to open an FS2 fluid loss isolation barrier valve using ROV The project was complex and the timing was critical, as the logistics of power only. With the drilling and completion rig already having moved multiple vessels and ROVs were managed along with partner Halliburton’s off site, a high cost and even higher impact to the remaining drilling and multiple coiled tubing units. completion schedule would have been incurred to bring it back just to actuate this valve. C-I designed, built and deployed a subsea tree International operator controls interface system, which leverages the existing infrastructure and C-I has also secured a three-year contract which encompasses subsea technology of the ROV systems. Estimated cost savings were US$3 million construction, IMR and logistics services. With Port Fourchon, La. serving per well when compared to accomplishing the same with a rig and riser. as the home port, the new contract will bring together ECO’s fleet of The client considered the procedure to be a success and a long-term multipurpose platform supply and well intervention vessels with C-I’s ROV, solution to an otherwise costly endeavour. tooling, project management and engineering services. The scope of work includes: jumper installations; subsea tree installations; facility underwater Case study 3 inspections in lieu of dry-docking; commissioning of new assets; and C-I performed acid stimulation of wells in the Gulf of Mexico. The prescribed general field support. acid treatment to stimulate each well was pumped down dual, open-water The company has also signed a five-year master services agreement coiled tubing downlines to the subsea well location. Following completion with an international operator in Brazil for IMR services. The agreement of pumping, each well restarted production and returns were flowed back is an all-inclusive contract including vessel, ROV, survey, engineering and to the production facility via the existing production flowline(s). Typically, project management. this type of scope of work is completed with a rig, stimulation vessel and marine riser with BOP via direct vertical access – which can, in some cases, Conclusion include necessary wireline services. Pumping outside of a true ‘open hole’ A combined, single-source approach to project management, engineering, and flowing acid returns into the existing pipelines reduces cost, duration procurement and service leads to improved economics and the most and HSE exposure, allowing the operator more options and opportunity to feasible solutions to the most complex of off shore challenges. The industry employ this improved oil recovery method. can now respond to subsea equipment and well issues with existing technology and greater speed, and still maintain reliability in control. Case study 4 In the Gulf of Mexico’s Mississippi Canyon, C-I performed a flowline segment hydrate remediation. The primary objective of this project was to clear the flowline of a hydrate blockage to restore production from well #3. The extent of hydrate formation was unknown and the only access was through a 1 in. hotstab port in the ROV panel on the far side of the pipeline segment. C-I was required to allow for the rest of the system to continue production while still maintaining the dual barrier (from live production) and eff ectively remediating the blockage. Topside pumping and separation capability was utilised to remove potential mudline restriction, which alternative systems may introduce. Additionally, nitrogen injection and gas lift were utilised to remove liquid contents from one side of the blockage, eff ectively reducing pressure and providing a dry environment (both of which aid in the dissociation of hydrate formations). Figure 1. Case study 6 – flowline decommissioning project in the GoM.

| 47 Coming up next month April BONUSBO DISTRIBUTIOND NUS Image from Trendsetter Engineering IST RIBU TION - Regional Report: OTC Gulf of Mexico Houston, TX 06 - 09 May - Downhole tools

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- Offshore challenges

- Decommissioning

- Flow assurance

- Workovers & interventions

- Corrosion prevention

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